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JANUARY 2014JOURNAL OF PETROLEUM TECHNOLOGY • www.spe.org/jpt

EOR PERFORMANCE AND MODELING

MATURE FIELDS AND WELL REVITALIZATION

WELL INTEGRITY

DECOMMISSIONING AND ABANDONMENT

Robotics foR subsea

SPE Technical Directors’ 2014 Outlook

Better Offshore Risk Analysis

The Industry’s Technical Skills Gap

FEATURES

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Petrolink_IFC_jpt.indd 1 12/11/13 11:14 AM

6 Performance Indices

10 Regional Update

12 Company News

14 President’s Column

18 Comments

24 Technology Applications

30 Technology Update

38 Young Technology Showcase

112 SPE News

113 People

115 Professional Services

119 Advertisers’ Index

120 SPE Events

Cover: Lockheed Martin’s first autonomous underwater vehicle designed for the oil and gas industry, the Marlin Mk1, is deployed for inspection operations of a fixed leg platform in the US Gulf of Mexico. Photo courtesy of Lockheed Martin.

20 Guest editorial • reducinG uncertainty to ensure Future asset PerFormance With the shift of offshore developments to harsher environments and deeper water, the traditional method of estimating expected availability and production performance figures, using extrapolated data from previous experience, is increasingly insufficient.

44 a lonG-term View From multiPle anGles SPE’s technical directors think the industry needs multidisciplinary, data-driven ways to adapt to what is ahead, focus on what is critical for decision making, and take a long view as another generation takes over.

50 robotic roustabouts For tomorrow’s subsea Fields Robotic submarines, capable of operating by themselves thousands of feet under water for months and perhaps years at a time, are under development to become the vanguard of tomorrow’s subsea oil and gas fields.

56 Kuwait unVeils uPstream oPPortunities The inaugural SPE Kuwait Oil and Gas Show and Conference in Kuwait attracted more than 3,000 delegates representing major oil and gas companies from all over the world.

60 talent & technoloGy • taKinG a balanced aPProach to the technical sKills GaP The industry continues to face a shortage of skilled workers with 10 to 20 years of experience, which affects staffing for midlevel management jobs and, subsequently, senior level management positions.

An Official Publication of the Society of Petroleum Engineers.Printed in US. Copyright 2014, Society of Petroleum Engineers.

Volume 66 • Number 1

ContentsJan14.indd 1 12/17/13 2:40 PM

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TECHNOLOGY

The complete SPE technical papers featured in this issue are available free to SPE members for two months at www.spe.org/jpt.

62 EOR Performance and ModelingOmer Gurpinar, SPE, Technical Director, Schlumberger

63 Foam Simulation Faces Several Numerical Challenges

66 UK Field Benefits From Reduced-Salinity Enhanced-Oil-Recovery Implementation

69 Simulation of Flow-Control Devices With Feedback Control for Thermal Operations

73 Multiscale Simulation of WAG Flooding in Naturally Fractured Reservoirs

76 Mature Fields and Well RevitalizationJesse Lee, SPE, Chemistry Technology Manager, Schlumberger

77 Channel Fracturing Applied in Mature Wells in Western Siberia

82 Mature-Field Subsurface Integrity: Holistic Diagnostic Approach in Malaysia

86 Optimum Development in Mature Fields: Sanga-Sanga Assets, Indonesia

90 Well IntegrityOtto Luiz Alcantara Santos, SPE, Coordinator, Petrobras

91 Uncertainty Evaluation of Wellbore-Stability-Model Predictions

94 Zonal Isolation Through Gas Hydrates Offshore Tanzania

98 Perforating Through Casing Strings to Remediate Annulus Gas Leak

102 Decommissioning and AbandonmentWin Thornton, SPE, Vice President of Decommissioning, BP

103 Modeling Options for Drill-Cuttings Management

106 Environmental Risk Arising From Well-Construction Failure

109 Digital-Slickline Capability on Plug-and-Abandonment Conveyance Phases

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Failing to properly understand the true

capabilities of lifting equipment such as

forklifts and cranes can easily lead to

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lifts or hoists, always perform a Job Safety

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DID YOU KNOW EVEN THOUGH THE EQUIPMENT DOES THE HEAVY LIFTING, YOU’RE STILL RESPONSIBLE FOR DOING IT SAFELY.

SPE PublicationS: SPE is not responsible for any statement made or opinions expressed in its publications.

Editorial Policy: SPE encourages open and objective discussion of technical and professional subjects per-tinent to the interests of the Society in its publications. Society publications shall contain no judgmental remarks or opinions as to the technical competence, personal character, or motivations of any individual, company, or group. Any material which, in the publisher’s opinion, does not meet the standards for objectivity, pertinence, and professional tone will be returned to the contribu-tor with a request for revision before publication. SPE accepts advertising (print and electronic) for goods and services that, in the publisher’s judgment, address the technical or professional interests of its readers. SPE reserves the right to refuse to publish any advertising it considers to be unacceptable.

coPyright and uSE: SPE grants permission to make up to five copies of any article in this journal for personal use. This permission is in addition to copying rights grant-ed by law as fair use or library use. For copying beyond that or the above permission: (1) libraries and other users dealing with the Copyright Clearance Center (CCC) must pay a base fee of USD 5 per article plus USD 0.50 per page to CCC, 29 Congress St., Salem, Mass. 01970, USA (ISSN0149-2136) or (2) other wise, contact SPE Librarian at SPE Americas Office in Richardson, Texas, USA, or e-mail [email protected] to obtain permission to make more than five copies or for any other special use of copyrighted material in this journal. The above permis-sion notwithstanding, SPE does not waive its right as copyright holder under the US Copyright Act.

Canada Publications Agreement #40612608.

georgeann bilich, Publisher

John donnelly, Editor

alex asfar, Senior Manager Publishing Services

Joel Parshall, Features Editor

robin beckwith, Senior Features Editor

Stephen rassenfoss, Emerging Technology Senior Editor

abdelghani henni, Middle East Staff Writer

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TECHNICAL PAPER DOWNLOADSThe Journal of Petroleum Technology offers SPE members the opportunity to download and read the full-length SPE technical papers that are synopsized in the magazine.

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OFFLINE ACCESSDownload PDF versions of 180+ issues dating back to 1997 for reading online or when an Internet connection is not available.

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JPT • JANUARY 2014

PERFORMANCE INDICES

wORlD CRuDE OIl PRODuCtION+‡

tHOuSAND BOPD

OPEC 2013 FEB MAR APR MAY JUN JUL

Algeria 1490 1490 1510 1510 1510 1520

Angola 1790 1840 1855 1890 1770 1790

Ecuador 506 504 516 522 524 531

Iran 3200 3200 3200 3200 3200 3200

Iraq 3075 3075 3175 3075 3100 3100

Kuwait* 2650 2650 2650 2650 2650 2650

libya 1400 1350 1450 1420 1130 1000

Nigeria 2320 2420 2400 2420 2270 2400

Qatar 1200 1200 1200 1200 1200 1200

Saudi Arabia* 9140 9140 9440 9640 9840 10040

uAE 2820 2820 2820 2820 2820 2820

Venezuela 2300 2300 2300 2300 2300 2300

TOTAL 31891 31989 32516 32647 32314 32551

tHOuSAND BOPD

NON-OPEC 2013 FEB MAR APR MAY JUN JUL

Argentina 534 536 532 541 539 545

Australia 309 328 344 338 356 361

Azerbaijan 903 870 860 870 905 890

Brazil 2017 1853 1923 1993 2101 1974

Canada 3259 3419 3237 3026 3146 3586

China 4146 4164 4174 4174 4245 4043

Colombia 997 1012 1007 1013 974 1020

Denmark 197 193 183 181 169 177

Egypt 547 545 543 541 540 538

Eq. Guinea 303 303 303 303 303 305

Gabon 239 239 238 238 237 245

India 767 777 773 776 778 766

Indonesia 853 866 860 856 834 811

Kazakhstan 1583 1588 1580 1458 1555 1586

Malaysia 552 536 506 511 522 491

Mexico 2595 2555 2557 2548 2559 2522

Norway 1502 1498 1567 1563 1386 1648

Oman 944 934 910 920 948 931

Russia 9990 9995 10002 10018 9955 10052

Sudan 106 112 115 248 336 301

Syria 133 91 71 71 71 71

uK 823 803 812 857 774 787

uSA 7133 7160 7335 7323 7270 7487

Vietnam 355 337 359 348 343 318

Yemen 162 140 118 118 118 118

Other 2461 2442 2428 2416 2436 2408

Total 43410 43295 43337 43249 43399 43980

Total World 75301 75284 75853 75896 75713 76531

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PERFORMANCE INDICES

HENRy Hub GulF COASt NAtuRAl GAS SPOt PRICE*‡

WORlD ROtARy RIG COuNt†

REGION2013 MAY JUN JUL AUG SEP OCT NOV

uS 1767 1761 1766 1781 1760 1744 1756

Canada 128 183 291 368 387 378 385

latin America 424 423 418 399 404 420 411

Europe 124 138 139 143 139 136 137

Middle East 362 389 379 362 379 383 388

Africa 124 133 128 125 119 131 135

Asia Pacific 249 250 241 238 243 245 240

TOTAL 3209 3178 3277 3362 3416 3431 3437

WORlD CRuDE OIl PRICES (uSD/bbl)‡

109.06 86.53 109.49 87.86 112.96 94.76 116.02 95.31

2012 NOV DEC 2013 JAN FEB

108.47 92.94 102.25 92.02 102.56 94.51 102.92 95.77

MAR APR MAY JUN

107.93 104.67 111.28 106.57 111.60 106.29 109.08 100.54

JUL AUG SEP OCT

Brent WTI

WORlD OIl SuPPly AND DEMAND1‡

MIllION bOPD 2012 2013

Quarter 4th 1st 2nd 3rd

SUPPLY 89.57 89.06 90.39 90.52

DEMAND 90.31 89.35 89.93 90.82

INDICES KEY + Figures do not include NGLs and oil from nonconventional sources.

* Includes approximately one-half of Neutral Zone production.

1 Includes crude oil, lease condensates, natural gas plant liquids, other hydrocarbons for refinery feedstocks, refinery gains, alcohol, and liquids produced from nonconventional sources.

† Source: Baker Hughes. * The US Dept. of Energy/Energy Information Administration discontinued its reporting of US Natural Gas Wellhead

Prices, replacing them with Henry Hub Gulf Coast Natural Gas Spot Prices.

‡ Source: US Dept. of Energy/Energy Information Admin.

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REGIONAL UPDATE

10 JPT • JANUARY 2014

AFRICA

◗◗ Oil was discovered at the Ekales-1 wildcat well located in Block 13T in northern Kenya. The well has a potential net pay of between 197 and 322 ft in the Auwerwer and Upper Lokone sandstone formations. Tullow (50%) operates 13T with partner Africa Oil (50%).

◗◗ The Mzia-3 appraisal well in Block 1 off Tanzania encountered a combined total of 183 ft of net pay in the Lower and Middle sands and confirmed reservoir quality in line with that seen in the Mzia-1 and Mzia-2 wells. BG Group (60%) operates Block 1 with partner Ophir (40%).

ASIA

◗◗ The Luba-1 offshore well on Brunei Block L was spudded. The well will evaluate the hydrocarbon potential of the Triple Junction structure. Serinus has a 90% interest in Block L, through indirect wholly owned subsidiaries Kulczyk Oil Brunei (40%) and AED SEA (operator, 50%). A private Brunei company owns the remaining 10% interest.

◗◗ Drilling began on the Malida-1 exploration well in Block G1/48 in the northern part of the Gulf of Thailand. The well will test for the development of the main Miocene-age interval of the Manora oil-bearing sands in an independent fault-dependent structure, east of the Manora field. The well will be drilled to a measured depth of approximately 2670 m. Mubadala Petroleum (60%) operates, with partners Tap Oil (30%) and Northern Gulf Petroleum (10%).

◗◗ Heavy oil was discovered at the Luda 5-2 North discovery wells in the Liaodong Bay area of China’s Bohai Gulf. The two wells, Luda 5-2N-2 and LD 5-2N-4, were both drilled to a depth of approximately 1140 m and encountered oil pay zones with total thickness of 394 and 279 ft, respectively. China National Offshore Oil Corporation (100%) is the operator.

AUSTRALIA

◗◗ OMV completed its Manaia-2/2A appraisal well within Petroleum Mining Permit (PMP) 38160 in the Maari field located 50 miles off the coast of South Taranaki District, New Zealand. The well, drilled to a measured depth of 2891 m, reached its target in the North Cape

formation and intersected oil-bearing sands in the Moki and Mangahewa formations. OMV New Zealand (69%) operates PMP 38160 with partners Todd Maari (16%), Horizon Oil International (10%), and Cue Taranaki (5%).

◗◗ Drilling began on the Matuku-1 well in New Zealand’s Petroleum Exploration Permit (PEP) 51906 in the offshore Taranaki basin. The vertical well will be drilled to a potential total depth of 4750 m. OMV New Zealand (65%) operates PEP 51906 with partners Octanex NZ (22.5%) and New Zealand Oil & Gas (12.5%).

EUROPE

◗◗ Oil was discovered at the 6407/8-6 exploration well and the 6407/8-6A sidetrack well in the Snilehorn prospect in the Norwegian Sea northeast of the Njord field. Estimated volume of the discovery ranges between 55 and 100 million bbl of recoverable oil. Statoil (35%) is the operator, with partners GDF Suez E&P Norge (20%), E.On E&P Norge (17.5%), Core Energy (17.5%), Faroe Petroleum Norge (7.5%), and VNG Norge (2.5%).

◗◗ Drilling began on the 16/5-5 appraisal well on Norwegian production license (PL) 410. The well will target the Luno II South structure. The reservoir is expected to be of Jurassic/Triassic age. Planned total depth is 2374 m below mean sea level. Lundin Norway (70%) operates PL 410 with partner Statoil (30%).

◗◗ Hydrocarbons were confirmed at Statoil’s North Sea Askja West prospect exploration Well 31/11-9S in Norwegian PL 272. Statoil (50%) operates PL 272 with partners Det norske (25%) and Svenska Petroleum (25%).

MIDDLE EAST

◗◗ Oil was discovered at the Mirawa-1 exploratory well in the Harir Block in the Kurdistan Region of Iraq. The well, drilled to a total depth of 4267 m, found oil and natural gas shows over an extensive gross interval of both Jurassic and Triassic reservoirs. Flow rates from multiple Jurassic zones totaled more than 11,000 BOPD. Multiple nonassociated gas zones in the Triassic flowed at rates totaling around 72 MMcf/D, together with associated condensate from one zone at a

rate of 1,700 BOEPD. Marathon Oil (45%) operates, with partners Total (35%) and the Kurdistan Regional Government (20%).

◗◗ The Salsala-1 exploration well in Block 32 onshore Yemen flowed naturally at an initial rate of 5,900 B/D of 36°API crude oil. The well, directionally drilled to a total depth of 4147 m, encountered oil shows in the Shuqra formation. DNO International (38.95%) operates Block 32 with partners Ansan Wikfs (42.93%), TransGlobe Energy (13.12%), and Yemen Oil & Gas (5%).

NORTH AMERICA

◗◗ The US Bureau of Ocean Energy Management will hold Gulf of Mexico Central Planning Area (CPA) oil and gas lease sale 231 in New Orleans on 19 March 2014. The sale is the second CPA lease sale and the fourth overall sale under the 2012–2017 Outer Continental Shelf Oil and Natural Gas Leasing Program. The auction will offer 39 million acres offshore Louisiana, Mississippi, and Alabama, and include all available unleased areas in the CPA.

SOUTH AMERICA

◗◗ Production began at the Papa Terra heavy-oil field development within Block BC-20 of the southern Campos basin, using platform P-63, which is connected to the PPT-12 well. The floating production, storage, and offloading platform is anchored at a water depth of 1200 m and has the capacity to process 140,000 BOPD, compress 1 MMcf/D of gas, and inject 340,000 B/D of water. Petróleo Brasileiro (62.5%) operates Papa Terra with partner Chevron (37.5%).

◗◗ A third 3D seismic survey began on Falkland Oil and Gas’s license areas to the south and east of the Falkland Islands (Islas Malvinas) in the south Atlantic. It is the final survey prior to commencement of drilling operations in late 2014. Interpretation results from the survey, operated by Noble Energy, should be available by the end of the first quarter 2014.

◗◗ A 396-m column of 28°API oil was confirmed at Petrobras’ 3-BRSA-1184-RJS (3-RJS-723) well, informally known as Franco Leste, in the Santos basin presalt Franco area 124 miles southeast of Rio de Janeiro, Brazil. Total depth of the well was 5900 m in water depth of 2011 m. Petrobras (100%) is the operator. JPT

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COMPANY NEWS


MERGERS AND ACQUISITIONS

◗◗ Compania Espanola de Petroleos entered into a definitive merger agreement to acquire Coastal Energy for an aggregate value of approximately USD 2.2 billion. The transaction is expected to close in the first quarter of 2014.

◗◗ Total, with partners Anadarko and Canadian Natural Resources International (CNR), will spend up to USD 300 million during 2014 to drill exploration wells on three ultradeepwater offshore blocks (514, 515, and 516) in Ivory Coast waters. Total owns a 54% interest in 514, with CNR (36%) and Petroci (10%). Total and Anadarko each control 45% of 515 and 516, with Petroci (10%).

◗◗ Eni signed an agreement with Quicksilver Resources to jointly evaluate, explore, and develop potential shale oil resources in 52,500 gross acres held by Quicksilver in the Leon Valley area, Pecos County, Texas. The agreement calls for an initial three-phase program that includes drilling up to five exploration wells and acquisition of a 3D seismic survey, both aimed at determining the area’s hydrocarbon potential and a subsequent development plan. Eni will pay Quicksilver up to USD 52 million to cover drilling, completion, and seismic survey costs, while the two companies will equally share any future expenditure.

◗◗ Heritage Oil entered into a joint venture with Bayelsa Oil Company, owned by Nigeria’s Bayelsa State government, to establish an oil company called Petrobay Energy. The new company will look to acquire production, development, and exploration assets from international oil companies operating in Nigeria. Heritage will own a 45% equity interest.

◗◗ Ophir Energy will sell a 20% interest in Blocks 1, 3, and 4 in the Ruvuma and Mafia Deep basins area offshore Tanzania to Pavilion Energy, a Temasek portfolio company, for USD 1.3 billion. The transaction is expected to be completed in the first quarter of 2014.

◗◗ Seadrill subsidiary Seadrill Jack-up Holding agreed to pay USD 235 million for 100% of the shares and certain intercompany obligations of Prospector Offshore Drilling subsidiary Prospector Rig

3 Owning Company (PR3OC). Prospector will receive a total of USD 55.2 million from Seadrill. The transaction includes PR3OC’s yard construction contract with Dalian Shipbuilding Industry Offshore for the new-build, high-specification jack-up rig Prospector 3. The rig, scheduled to be delivered in first-quarter 2014, has a water depth capacity of 400 ft and a drilling depth capacity of 35,000 ft.

◗◗ Devon Energy will buy closely held GeoSouthern Energy’s assets in the Eagle Ford shale play in south Texas for USD 6 billion. The assets include current production of 53,000 BOE/D and 82,000 net acres.

COMPANY MOVES

◗◗ Schlumberger announced the official opening of the Schlumberger Reservoir Laboratory (SRL) in Brisbane, Australia. The 10,000-ft2 facility is the latest addition to the global network of SRLs, providing core measurement and analysis services for companies with unconventional and conventional oil and gas assets. Laboratory personnel will work closely with the Queensland University of Technology.

◗◗ Construction began on a 30-story, Class AA office tower located in Houston, Texas, to anchor a new headquarters campus for BHP Billiton’s global petroleum business. The 600,000-ft2 office building, constructed to LEED-Gold standards and expected to be completed in 2016, will be situated on a 2.72-acre tract beside BHP Billiton’s current petroleum business headquarters.

CONTRACTS

◗◗ Benthic was awarded a contract by Neptune Marine Services for an offshore geotechnical investigation to collect seabed geotechnical data off the north coast of Western Australia. Benthic’s portable remotely operated drill will perform rotary drilling and piston coring, and also perform in-situ testing using a piezo-cone penetrometer to identify the soil conditions and geotechnical properties of the soil for the placement of a mobile jackup rig.

◗◗ KS Drilling, an 80%-owned subsidiary of KS Energy, with its joint operation partner, Pertamina Drilling Services Indonesia,

received a 1-year, USD-41-million contract extension for the jackup KS Java Star. The KS Java Star is expected to continue drilling in the West Madura oil field offshore Java until January 2015.

◗◗ Transocean entered into a 3-year contract with Royal Dutch Shell for work off the coast of Alaska starting July 2014. Transocean’s Polar Pioneer harsh environment semisubmersible drilling unit will earn a rate of USD 620,000 per day in the summer season from July to October and then USD 589,000 per day the rest of the year.

◗◗ Ukraine signed a shale gas production-sharing agreement, to extend for 50 years and whose potential value is USD 10 billion, with Chevron to develop the country’s western Olesska field. The agreement foresees an initial investment of USD 350 million by Chevron for exploratory work over 2 to 3 years to establish the commercial viability of shale reserves in the 2,000-sq-mile Olesska.

◗◗ Adyard Abu Dhabi, a subsidiary of Interserve, was awarded a USD-17-million contract by Dana Gas for the fabrication of an offshore platform for the Zora Field Development Project, which spans the territorial waters of Sharjah and Ajman, United Arab Emirates. The platform will help extract reserves from the Zora field through an offshore facility and transport the reserves through a 21.7-mile subsea pipeline to an onshore gas-processing facility.

◗◗ Mitsui Ocean Development & Engineering Company and Schahin were awarded a supply, charter, and operations contract for a floating production, storage, and offloading (FPSO) vessel by Petrobras, on behalf of Consortium BM-S-9, for the BM-S-9 block (Carioca area) in the presalt region of the Santos basin, Brazil. The FPSO vessel, with expected delivery by June 2016, will be capable of processing 100,000 B/D of crude oil, 177 MMscf/D of gas, and 120,000 B/D of water injection, with the ability to store 1.6 million bbl of crude oil.

◗◗ Lamprell completed construction of the jackup rig Jindal Star for Jindal Pipes to be used offshore India. The Jindal Star, weighing 10,500 metric tons, is a LeTourneau Super 116E rig with a self-elevating 477-ft leg design. JPT

CompanyNewsJan.indd 12 12/17/13 2:36 PM

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EMERGING FRONTIERS


Big Data! Jeff Spath, 2014 SPE President

“Big data,” once only the concern of database geeks or a market-ing technique among retailers, is now part of our mainstream consciousness and vocabulary. Big data is having a profound impact on the upstream E&P industry as well.

What is “big data”? According to a McKinsey Global Insti-tute report, “big data refers to datasets whose size is beyond the ability of typical database software tools to capture, store, manage, and analyze.” I like this definition because it does not

require a dataset of any specific size. It allows datasets to increase as technology ad-vances. This definition also varies to the extent that different industries have different standards of database and analytic software tools.

To get a feel for just how big data has become, consider recent rates of data growth. In 2012, disk drives worldwide added 7 exabytes (1018) of new data. Global data volumes are projected to increase 40% per year, while global information tech-nology (IT) spend will grow only 5%. Thirty billion pieces of content are shared on Facebook each month. Or consider that Asia now leads the world in the generation and storage of personal location data due simply to the number of mobile phones—an es-timated 800 million in China alone.

How mainstream has big data become? Consider these examples of wide - spread usage:

◗◗ High-speed supercomputers statistically analyze massive amounts of data, enabling scientific breakthroughs such as the gene sequencing of individual organisms and entire ecosystems.

◗◗ Coaxing the Higgs boson into a nanosecond of existence required the global distribution and analysis of roughly 200 petabytes of data.

◗◗ Or, more familiar to most of us, retail organizations cleverly obtain our behaviors, preferences, and product perceptions by monitoring our Facebook and Twitter information.

The combination of massive amounts of data and sophisticated analytics is pro-foundly affecting a spectrum of industries, and oil and gas is no exception.

Big Data in the Oil FieldThe amount of data that our industry acquires, communicates, stores, and analyzes is exploding exponentially. For example, the growth of land seismic acquisition is one of the most data-intensive phases of our industry. Channel count has roughly doubled every 3.5 years since 1970. Together with advances in the acquisition technology—which now measures vector information rather than scalar—the data acquired and stored in a typical survey has grown from gigabytes to petabytes. Furthermore, the growing popularity of permanently installed geophones for monitoring fluid fronts, passive monitoring of carbon capture sequestration sites, and observing microseismic events during hydraulic fracturing has driven an extraordinary and daunting growth in seismic data of all forms.

SPE BOARD OF DIRECTORS

OFFICERS2014 President

Jeff Spath, Schlumberger

2013 President Egbert Imomoh, Afren

2015 President Helge Hove Haldorsen, Statoil

Vice President FinanceJaneen Judah, Chevron

REGIONAL DIRECTORSAFRICA

Anthony Ogunkoya, TBFF Upstream Oil and Gas Consulting

CANADIANDarcy Spady, Sanjel Corporation

EAStERN NORtH AmERICABob Garland, Universal Well Services

GulF COASt NORtH AmERICABryant mueller, Halliburton

mID-CONtINENt NORtH AmERICAmichael tunstall, Halliburton

mIDDlE EAStFareed Abdulla, Abu Dhabi Co. Onshore Oil Opn

NORtH SEACarlos Chalbaud, GDF Suez E&P UK

NORtHERN ASIA PACIFICRon morris, Roc Oil (Bohai)/Roc Oil (China)

ROCky mOuNtAIN NORtH AmERICAmike Eberhard, Anadarko Petroleum Corporation

RuSSIA AND tHE CASPIANAndrey Gladkov, Modeltech

SOutH AmERICA AND CARIBBEANNestor Saavedra, Ecopetrol–ICP

SOutH, CENtRAl, AND EASt EuROPEmaurizio Rampoldi, Eni E&P

SOutHERN ASIA PACIFICJohn Boardman, RISC

SOutHwEStERN NORtH AmERICAPeter Schrenkel, Vision Natural Resources

wEStERN NORtH AmERICAtom walsh, Petrotechnical Resources of Alaska

TECHNICAL DIRECTORSDRIllING AND COmPlEtIONS

David Curry, Baker Hughes

HEAltH, SAFEty, SECuRIty, ENVIRONmENt, AND SOCIAl RESPONSIBIlIty

Roland moreau, ExxonMobil Upstream Research Company

mANAGEmENt AND INFORmAtIONCindy Reece, ExxonMobil Annuitant

PRODuCtION AND OPERAtIONSShauna Noonan, ConocoPhillips

PROJECtS, FACIlItIES, AND CONStRuCtIONHoward Duhon, Gibson Applied Tech PF&C

RESERVOIR DESCRIPtION AND DyNAmICSOlivier Houzè, KAPPA Engineering

AT-LARGE DIRECTORSliu Zhenwu, China National Petroleum Corporation

mohammed Al-Qahtani, Saudi Aramco

To contact the SPE President, email [email protected].

Search the Groups Field for “Society of Petroleum Engineers”.

PresColumnJan.indd 14 12/18/13 7:11 AM

Mew_015_jpt.indd 1 12/17/12 1:13 PM

EMERGING FRONTIERS


As a consequence of this data explosion, technology con-tinues to advance. The industry has developed significant im-provements in survey design, data compression techniques, auto-picking algorithms, and intelligent storage schemes. As an aside, it is worth noting how much value is created by new technologies that store and analyze what was once considered “noise,” revealing even more detail within complex reservoirs.

On the production side of our business, a well-known ex-ample of big data and associated analytics is the advent of the “smart field” or “digital oil field.” Here, the carefully defined combination of IT and data acquisition with intelligent pro-duction engineering analytics—often including artificial intel-ligence—has generated a deluge in data. Examples range from water/oil ratios along intelligent completions to measurements of methane emissions during hydraulic fracture flowbacks.

To understand the often frustrating amounts of data in-volved, consider the fact that for each well in a digital oil field we now measure and store—often using permanently installed fiber—different flow rates for each phase, various pressures and temperatures at the wellhead, as well as electrical submers-ible pump parameters, environmental data, and power usage. As a result, smart engineers now apply sophisticated algorithms and powerful software tools to enhance decision making and re-duce cycle time, and to optimize productivity, return on invest-

ment, and net present value, thus reducing the need for skilled on-site personnel.

Big data combined with smart people and smart software is proving to be very powerful.

What’s Next?The rate and volume of growth in data generation and usage will continue to increase in our industry over time.

In thinking about recent trends, it is apparent that the value of taking many more measurements is increasing rapid-ly. Take the drilling domain, for example. From high-telemetry logging-while-drilling or measurement-while-drilling measure-ments to the many parameters required for automated or as-sisted drilling on the rig floor, the amount and the rate of drill-ing data being acquired, stored, transmitted, and interpreted is increasing dramatically every year. And as we are asked by reg-ulators and the public to monitor our operations more closely, big data will only get bigger.

In each case, growth in data alone is not useful. While gen-erating insights from more data is always important, “action-ability” is the hallmark of big data, through data analytics and old-fashioned smart petroleum engineering. The next wave of technology innovation in our industry and the next level of un-derstanding our reservoirs will depend on our ability to inte-grate diverse data, measurements, and domains. This implies, of course, that our young professionals will require additional skillsets to succeed.

SPE Activity in Big DataWith the growth in E&P applications of big data SPE has recog-nized that members need to collaborate on these new issues and to learn how to leverage the many opportunities provided. The first SPE Intelligent Energy conference was held in 2001 and since 2008 we have held seven conferences, 12 workshops, and one forum, dealing with intelligent energy and digital oil fields. A quick search in OnePetro shows more than 6,500 papers on the subject. As part of the new SPE strategy to create life-long learning and fast-track young professionals, the topic will become more prevalent in all our meetings, whether it is the main topic or the catalyst behind the next big discovery.

Each month, I post my JPT column topic on the SPE LinkedIn group for comment and conversation. I invite you all to join in this discussion and look forward to hearing your viewpoints. JPT

ReferenceManyika, J., Chui, M., Brown, B., et al. 2011. Big data: The

next frontier for innovation, competition, and productivity. McKinsey Global Institute. http://www.mckinsey.com/insights/business_technology/big_data_the_next_frontier_for_innovation

Tenure-Track Position

The Department of Chemical and Petroleum Engineering in the Schulich School of Engineering at the University of Calgary invites applications for a position with expertise in the following areas:

Computational Thermodynamics, and Energy & Environment Applications

Tenure-track Assistant Professor Position

The successful candidates will establish a strong research program, supervise graduate students, teach a range of undergraduate and graduate courses and attract external funding to support research activities.

Applicants must possess a PhD in Chemical or Petroleum Engineering, or related fields or be within 6 months of their doctoral thesis defense and be eligible for registration as a professional engineer with the Association of Professional Engineers and Geoscientists of Alberta.

For full posting details, please visit: http://schulich.ucalgary.ca/chemical/about/employment

The review of applications will begin February 15, 2014, and continue until the position is filled.

All qualified candidates are encouraged to apply; however, Canadian citizens and permanent residents of Canada will be given priority. The University of

Calgary respects, appreciates and encourages diversity.

PresColumnJan.indd 16 12/17/13 3:03 PM

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COMMENTS


2014 Outlook John Donnelly, JPT Editor

Signs point to sustained strong oil prices this year, levels that will continue to support upstream unconventional projects in North America and elsewhere.

North Sea Brent and West Texas Intermediate (WTI) crude oil, the world’s two key benchmark prices, averaged around USD 108/bbl and USD 97/bbl, respectively, in 2013. And most price forecasts for 2014, which began emerging from ana-

lysts and investment houses in the fourth quarter, predict similar price levels in the new year. The wild card in that scenario, however, is the growth of non-OPEC sup-ply and production levels from Libya and Iraq, which are difficult to anticipate. North American supply is expected to continue its upward swing, and significant increases in Kazakhstan are also forecast. Commercial production at Kashagan, Kazakhstan’s giant Caspian Sea oil field, is expected to begin in the first half of the year. The field was dis-covered in 2000, one of the largest finds in decades, but development has faced rising costs and numerous delays.

US crude oil production is expected to rise again this year. The US Energy Infor-mation Administration (EIA) says US crude output averaged 7.5 million BOPD in 2013 and will average 8.5 million BOPD in 2014. When US production hit 8 million BOPD in November, it was the highest monthly output level since 1988. The EIA believes that growth shows no signs of stopping, with US crude production forecast to come to a high of 9.6 million BOPD in 2016, a level not seen since 1970.

The EIA sees non-OPEC production growing from 54.2 million BOPD in 2013 to 55.9 million BOPD this year. Most of the non-OPEC production growth will be from US onshore tight oil formations and Canadian oil sands, with smaller increases from Africa, South America, and Asia. That will continue to put pressure on OPEC, which has watched its market share erode recently. OPEC countries are expected to produce 29.4 million BOPD this year, compared with an average of 30.3 million BOPD in 2013.

Oil prices are notoriously hard to predict. Some of the same analysts who fore-casts strong prices this year predicted a sharp drop in oil prices in 2013, something that never happened. Nevertheless, there seems to be a consensus that Brent and WTI will remain near their current levels in the new year.

A survey of price forecasters published by Petroleum Intelligence Weekly in December showed most analysts seeing Brent in a USD 100-110/bbl range for the near year, and WTI at around USD 90-100/bbl. The survey of 10 analysts at consult-ing groups and investment banks shows Brent crude averaging USD 106/bbl for 2014, while the average for WTI is USD 97/bbl. Forecasters were optimistic that Libyan output would recover after months of disruption, and that a strengthening global economy would help absorb oil supply growth. JPT

EDITORIAL COMMITTEESyed Ali—Chairperson, Technical Advisor,

Schlumberger

Francisco J. Alhanati, Director, Exploration & Production, C-FER Technologies

William Bailey, Principal Reservoir Engineer, Schlumberger

Ian G. Ball, Technical Director, Intecsea (UK) Ltd

Luciane Bonet, Senior Reservoir Engineer, Petrobras America Inc.

Robert B. Carpenter, Sr. Advisor – Cementing, Chevron Corp.

Simon Chipperfield, Team Leader Central Gas Team/Gas Exploitation, Eastern Australia Development,

Santos

Alex Crabtree, Senior Advisor, Hess Corporation

Jose C. Cunha, Drilling Manager, Ecopetrol America

Alexandre Emerick, Reservoir Engineer, Petrobras Research Center

Niall Fleming, Leading Advisor Well Productivity & Stimulation, Statoil

Ted Frankiewicz, Engineering Advisor, SPEC Services

Emmanuel Garland, Special Advisor to the HSE Vice President, Total

Reid Grigg, Senior Engineer/Section Head, Gas Flooding Processes and Flow Heterogeneities, New

Mexico Petroleum Recovery Research Center

Omer M. Gurpinar, Technical Director, Enhanced Oil Recovery, Schlumberger

A.G. Guzman-Garcia, Engineer Advisor, ExxonMobil (retired)

Robert Harrison, Global Business Leader, Reserves & Asset Evaluation, Senergy

Delores J. Hinkle, Director, Corporate Reserves, Marathon Oil (retired)

John Hudson, Senior Production Engineer Shell

Morten Iversen, Completion Team Leader, BG Group

Leonard Kalfayan, Global Production Engineering Advisor, Hess Corporation

Tom Kelly, Systems Engineering, FMC Technologies

Gerd Kleemeyer, Head Integrated Geophysical Services, Shell Global Solutions International BV

Jesse C. Lee, Chemistry Technology Manager, Schlumberger

Casey McDonough, Drilling Engineer, Chesapeake Energy

Cam Matthews, Director, New Technology Ventures, C-FER Technologies

Badrul H Mohamed Jan, Lecturer/Researcher, University of Malaya

Lee Morgenthaler, Principal Technical Expert, Chemical Production Enhancement, Shell

Alvaro F. Negrao, Senior Drilling Advisor, Woodside Energy (USA)

Shauna G. Noonan, Staff Production Engineer, ConocoPhillips

Karen E. Olson, Completion Expert, Southwestern Energy

Michael L. Payne, Senior Advisor, BP plc

Mauricio P. Rebelo, Technical Services Manager, Petrobras America

Jon Ruszka, Drilling Manager, Baker Hughes (Africa Region)

Martin Rylance, Senior Advisor and Engineering Manager Fracturing & Stimulation,

GWO Completions Engineering

Jacques B. Salies, Drilling Manager, Queiroz Galvão E&P

Otto L. Santos, Sênior Consultor, Petrobras

Luigi A. Saputelli, Senior Production Modeling Advisor, Hess Corporation

Sally A. Thomas, Principal Engineer, Production Technology, ConocoPhillips

Win Thornton, Global Projects Organization, BP plc

Erik Vikane, Manager Petroleum Technology, Statoil

Xiuli Wang, Vice President and Chief Technology Officer, XGas

Mike Weatherl, Drilling Advisor, Hess Norge AS

Rodney Wetzel, Team Lead, SandFace Completions, Chevron ETC

Scott Wilson, Senior Vice President, Ryder Scott Company

Jonathan Wylde, Global Head Technology, Clariant Oil Services

Pat York, Global Director, Well Engineering & Project Management, Weatherford International

To contact JPT’s editor, email [email protected].

CommentsJan.indd 18 12/17/13 2:29 PM

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GUEST EDITORIAL

Frank Ketelaars is head of UK Advisory Services at DNV with overall responsibility for its advisory units in London, Manchester, and Aberdeen. He

began his career at Shell International in 1989. Later, he worked for 10 years for Jardine and Associates, specializing in asset performance and availability analysis covering upstream, midstream, and downstream assets. Ketelaars joined DNV as part of the company’s acquisition of Jardine in 2005, and has worked as head of the DNV advisory unit in London since 2008, responsible for advisory activities covering safety, and environmental and asset risk.

Over the past 5 to 10 years, there has been an increasing focus in the offshore oil and gas industry on predicting and quantifying an asset’s expected production perfor-mance. This “performance risk” has always been considered one of the key risk fac-tors for an offshore development, in addition to subsurface, economic, safety, and environmental risks. However, with the shift of offshore developments to harsh-er environments and deeper water, the traditional method of estimating expected availability and production performance figures, using extrapolated data from pre-vious experience, is increasingly considered insufficient.

With increased investment required for some of the ambitious new offshore developments (floating liquefied natural gas [FLNG], Arctic, and ultradeep develop-ments), there is growing pressure to address any risk to the bottom line and under-stand how the impact of changing environments and operating conditions will affect economic return and expected revenue. As a result, most operators are now adopt-ing more robust methodologies, such as using simulation technology tools, to evalu-ate and predict expected performance.

Several key areas in the offshore industry illustrate where these “new” produc-tion risk factors are especially relevant.

The subsea industry, in particular, continues to undergo rapid transformation as it seeks to exploit untapped reserves. Subsea fields exploited since the late 1990s in the North Sea, US Gulf of Mexico (GOM), and offshore Brazil are now considered areas using proven technology and their performance is well understood. Howev-er, pushing subsea developments into ultradeep locations does result in addition-al performance risk. The 2010 Macondo accident in the GOM clearly showed that the potential impact and escalation of subsea failures or incidents can be dramati-cally increased because of high water depths. The ultradeep environment will affect potential diagnostics options (Is there a leak? Where is it coming from?), and miti-gation and repair options (What intervention activities are possible? Which vessels are available at short notice?). A relatively minor failure, which could have been addressed quickly by divers or remotely operated vehicles in shallower waters, can potentially result in long well or even field outages. In addition, public scrutiny concerning any potential environmental impact would make it likely that opera-tors would now opt for conservative decisions (e.g., a shutdown) in the event of any uncertainty about potential subsea leaks or failures.

The global drive to harsher environments, including West of Shetlands and Arctic locations, introduces its own set of uncertainties and risk to asset perfor-mance. Experience on fields such as the Schiehallion or West of Shetlands, has shown that the impact of the harsh environment is significant, both in operation of floating production facilities and access to the subsea wells. For example, any well or subsea intervention during the winter season will result in significant addi-tional intervention durations, increased operating expense, and long well outages. For such locations, an analysis and understanding of expected metocean conditions and their effect on operations is key to understanding production performance. For Arctic developments, there is the additional problem of access to facilities during

Reducing Uncertainty to Ensure Future Asset PerformanceFrank Ketelaars, Head of UK Advisory Services, DNV

GuestEdJan.indd 20 12/17/13 2:28 PM

*Mark of Schlumberger. © 2014 Schlumberger. 13-ST-0101

ENGINEERED STIMULATION DESIGN

IN THE PETREL PLATFORM

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PetroChina Changqing beats previous-best horizontal well production by more than 50%.PetroChina Changqing used Mangrove* workfow in the Petrel* E&P software platform to capture the

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wells were completed, sustained production rates were 50% higher than the previous-best ofset horizontal well.

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Schlum_021_jpt.indd 1 12/11/13 2:53 PM


GUEST EDITORIAL

periods with ice and the impact of Arctic conditions on maintenance activities.

Another major development for the offshore industry in the past few years is the option to consider FLNG plants for large stranded gas reserves. Many operators are currently consid-ering FLNG options for some of their biggest investments. The potential risk of taking a complex LNG facility to an offshore operating environment is sig-nificant. There are uncertainties as to how LNG-specific equipment will oper-ate under offshore conditions and wave motion, how reliable the LNG offloading operations will be, and how major main-tenance activities will be executed for a complex facility with less access to per-sonnel due to bedding constraints.

A recognition of the importance of these risks is apparent by the decision of some operators, during the design com-petition for the Masela and Tupi fields, to consider FLNG production risk a key performance parameter when compar-ing designs during the front-end engi-neering design competition for FLNG developments (in addition to compari-son of overall capital expenditure and safety risk).

A final area in which future produc-tion performance risk is a major issue is the aging facilities in mature offshore provinces, such as the North Sea and GOM, where lifetime extension projects are being considered. For these facilities, production is extended beyond origi-nal design life and there will be future downtime associated with additional maintenance requirements, both pre-ventive and corrective. In many cases, and as an added risk factor, these facili-ties will have changed ownership, intro-

ducing new operators and operations personnel to the facility and potentially losing some historical operational expe-rience. These factors pose a tough chal-lenge to maintaining strong production performance, while minimizing operat-ing costs, without jeopardizing the safe-ty and integrity of the asset. For these types of projects, a clear framework for assessing future performance against best-in-class performance and identify-ing the potential main bad actors at an early stage is essential.

The additional complexity in the operation of offshore assets demands more accurate and sophisticated tools and methodologies for assessing poten-tial performance. These methodologies, combined with a thorough understand-ing and qualification of the new technol-ogies employed, will ensure that future asset owners and investors can define a better picture of future performance. The developed performance models will also provide a clear auditable frame-work, clearly showing the links between input data assumptions (on reliability, operability, environmental conditions, etc.) and bottom-line performance. In addition, these models allow testing of alternative scenarios to mitigate identi-fied potential production loss. It is not surprising that for many operators such performance prediction tools are now mandatory requirements as part of the project “decision gate” processes.

By making potential risks more transparent to all stakeholders, the con-sistent implementation of better per-formance risk analysis should assist the industry in raising awareness of the crit-ical improvements that are required to push forward into new territory. JPT

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GuestEdJan.indd 22 12/18/13 7:10 AM

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TECHNOLOGY APPLICATIONS


Polycrystalline-Diamond-Compact BitUlterra has introduced its line of FastBack high-rate-of-penetration polycrystalline-diamond-compact (PDC) bits. FastBack-designed bits use a unique blade config-uration that supports the cutters with a smaller-than-usual profile that elimi-nates wasted energy needed for pushing larger blades, thereby focusing all energy on the diamond cutting surfaces (Fig. 1). This efficiency improvement resulted in a 56.8% drilling-speed increase in a Marcel-lus well. The FastBack’s new blade design is made possible by advanced surface coatings, which provide maximum ero-sion control without sacrificing strength. Additionally, the FastBack’s smaller blade configuration opens up the junk-slot area for optimal hydraulics and enhanced cut-tings evacuation. ◗◗ For additional information, visit

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Tagged InhibitorOperators are seeking ways to address scale-inhibitor monitoring on- and off-shore to better manage treatments. Determining the minimum inhibitor con-centration quickly and precisely is criti-cal to effectively manage the required

shutdowns and scheduling for offshore squeeze treatments. In response to this need, Kemira has introduced its Kem-Guard 2490 phosphorous-tagged inhibi-tor and its KemGuard 2420 fluorescent-tagged inhibitor, both of which can be monitored quickly and accurately down to single-ppm levels (Fig. 2). The tagged inhibitors can be quantified in the pres-ence of one another to monitor multiple wells from a single production stream at a collection platform or field battery. The tags are manufactured into the poly-mer structure so that both the tag and the polymer stay together as the poly-mer moves through the reservoir in the case of squeeze jobs or through produc-tion equipment for onshore treatments. The tagged inhibitors have proved effec-tive for inhibition of sulfate scales under a wide range of oilfield brine conditions. ◗◗ For additional information, visit

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Wireless Downhole Testing SystemSchlumberger has introduced the Quar-tet downhole-reservoir-testing sys-tem enabled by Muzic wireless telem-etry, which provides data in real time for validation so that critical informa-tion is available to meet well-test objec-tives. The Quartet system uses wireless bidirectional communication to provide downhole tool status and pressure and temperature data, allowing test-design modifications and test-data validation while reservoir testing is taking place (Fig. 3). The system also enhances test-ing efficiency by enabling the isolation, control, measurement, and sampling of the reservoir in a single run. Field tests using the Quartet system with wire-less telemetry have been run in Egypt, Indonesia, Qatar, Brazil, and Angola in environments ranging from onshore to deep water. A total of 22 reservoir

Chris Carpenter, JPT Technology Editor

Fig. 1—Ulterra’s FastBack PDC bit. Fig. 2—A test for residuals by use of Kemira’s tagged inhibitors.

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tests have been conducted with data from downhole to surface at a 100% communication-success rate. In Bra-zil, Petrobras and Schlumberger identi-fied an opportunity to optimize deepwa-ter well-test operations with a real-time communication solution on a well in the presalt Santos basin. As a result of the

collaboration, the Quartet system was deployed successfully, delivering flow and shut-in data to monitor operations and adjust the test program in real time. ◗◗ For additional information, visit

www.slb.com/Quartet-Muzic.

Tight-Casing CentralizerCentek Group’s UROS-CT centralizer, targeted at tight-casing applications in deepwater wells, is now available. The UROS-CT is designed for use in tight-tolerance casings where the centralizer is required to compress fully to travel between tight-tolerance casing strings, yet will expand to the designed open-hole size (Fig. 4). The UROS-CT is engi-neered to precise ring-gauge tolerances, partly because casing drift downhole is a major concern when running in deep-water wells, but also because the central-izer must compress as closely as possible to the casing because every millimeter saved allows for greater expansion in the open hole. The centralizer is secured into position by use of low-profile, positive stop rings. The UROS-CT fits

straight onto standard casing joints, so there is no need to run an expensive pup joint, and substantial rig makeup time is avoided. This centralizer significantly reduces insertion forces and drag, and the unit does not need to be pulled into the well because the design allows for normal run-in-hole methods, so it goes down under its own mass. The UROS-CT is being run successfully off Norway, Brazil, Brunei, and Malaysia and is now being used in the Gulf of Mexico by both US and Mexican operators. ◗◗ For additional information, visit

www.centekltd.co.uk.

Scale-Inhibitor-Evaluation SystemThe Model 5400 dynamic scale- deposition loop from AMETEK Chan-dler Engineering is a fully automated system that measures and evaluates the performance of scale inhibitors under high-pressure and high-temperature conditions (Fig. 5). The system pumps precisely heated oil samples at known rates through a tubing test section while

Fig. 3—Schlumberger’s Quartet Muzic wireless downhole testing system.

Fig. 4—The UROS-CT centralizer from Centek.

Fig. 5—AMETEK Chandler Engineering’s Model 5400 scale-inhibitor-evaluation system.


27JPT • JANUARY 2014

continuously measuring the differen-tial pressure. An increase in differen-tial pressure serves as an indication of scale formation, and the test is com-pleted once that differential pressure reaches an adjustable threshold value. The system features a precise forced-air convection oven, removable sample and preheat tube assembly, external pH electrode, and Hastelloy C276 sample tubing and fittings inside the oven. Its hardware includes two manual set-point backpressure regulators (high or low range) that are used to create the sam-ple pressure inside the test section dur-ing pumping. Two high-performance liquid chromatography pumps are used to transport the fluids through the tub-ing, both with six-port switching valves. The system’s proprietary software is designed for ease of use and is powerful enough to collect and calculate all of the acquired data over the completed test cycle. The software allows operators to control the overflow rate, test time, fluid selection, and temperature of each indi-vidual test. ◗◗ For additional information, visit

www.ametek.com.

Subsea Pile-Driving SystemConductor Installation Services has introduced its Subsea Piling System, a remotely operated system that the com-pany developed to drive piles as large as 36 in. in diameter in water depths to 300 m. The entire process is carried out by an experienced pile-driving engineer from a control unit and monitoring sys-tem located onboard a vessel or barge. A hydraulic hammer, connected by an elec-tronic umbilical cable to the control sys-tem, is lowered into the water and placed directly over a subsea pile (Fig. 6). Once it is positioned accurately, the pile is driven into the seabed by the hammer until it reaches its target depth. The operation is continuously monitored and controlled by an engineer in a dedi-cated control cabin. The system features self-tensioning hydraulic winches that lower and raise the hydraulic hoses and electrical cables that connect to the ham-mer. The constant- tensioning capabil-

ity of the Subsea Piling System’s winches means that they automatically heave and lower according to sea conditions. ◗◗ For additional information, visit

www.c-i-services.com.

Ball ValveVictaulic has introduced the Series 727 ball valve, a high-pressure, enhanced-port valve with grooved ends for upstream

oil applications. The internal design of the Series 727 valve has been streamlined to provide enhanced flow characteris-tics, offering improved throughput. Flow testing demonstrated up to one-third better flow than competitive standard- port ball valves. Featuring grooved ends, the Series 727 is joined using Victau-lic couplings, enabling quicker and eas-ier installation and maintenance than

Fig. 6—A subsea piling hammer, part of Conductor Installation Services’ Subsea Piling System.




flanged valves. The Series 727 weighs one-third less than equivalent flanged valves, further easing handling and installation. The two-piece valve features a floating ball for lower torque require-ments and is offered with manu-al handles with an integral tamper- resistant lock/seal (Fig. 7). The Series 727 is designed for full-open or shutoff service. Series 727 valves can accommo-date pressures up to 1,500 psi and are available in sizes ranging from 2 to 6 in. Common oilfield applications include wellhead hookups, flowlines, production headers, produced-water lines, heater treaters, and separators.◗◗ For additional information, visit

www.victaulic.com.

Electrical Submersible PumpsBaker Hughes’ new ProductionWave solu-tion is a suite of electrical-submersible- pump (ESP) -based products and ser-vices, providing a flexible production alternative to rod pumps for unconven-tional oil plays. Among the advantages of using ESP-based systems vs. rod-lift-based systems is the ability to place the ESP deeper in the well, which increases production and ultimate recovery. The pump’s deviation tolerance eliminates tubing wear typical of rod-lift systems, to improve uptime, reliability, and eco-nomic benefit. The ProductionWave sys-tems help operators increase production rates, in some cases by more than 40%, while lowering operating expenses and

reducing health, safety, and environ-mental risks in comparison with rod-lift operations (Fig. 8). These production systems are targeted at low-flow-rate unconventional oil wells with trajecto-ries that are troublesome for rod-lift systems. The pumps can operate in flow ranges from 50 to 4,000 BFPD, enabling operation in dynamic conditions while providing better associated-gas- and

solids-handling capabilities than does rod lift. In addition to the pump, Pro-ductionWave solutions include technol-ogies for gas handling, sand control, and production chemicals, and offer flexible commercial models and services related to applications engineering, real-time optimization, and field support.◗◗ For additional information, visit

www.bakerhughes.com.

Fig. 7—Victaulic’s Series 727 high-pressure ball valve.

Fig. 8—Baker Hughes’ ProductionWave ESP-based services in use.



Reservoir-Monitoring SystemWeatherford International announced the worldwide release of its OmniWell production- and reservoir-monitoring service, providing unified reservoir mon-itoring for real-time downhole data under

a wide range of well conditions, from conventional to extreme. OmniWell’s fit-for-purpose solutions incorporate elec-tronic and optical sensing technologies, integrating multiple measurement solu-tions for activities such as flow profiling,

fracture monitoring, production surveil-lance, and thermal profiling (Fig. 9). The data from those solutions are acquired at the surface and processed through a scalable data-management platform that relays critical data to visualization and analysis platforms in real time. A new, scalable data platform is also available for acquiring, integrating, and managing critical well data while offering software and services to simultaneously visualize dynamic, multiparameter data for chang-ing well conditions. The integrated data platform for multiapplication, multiple discrete measurements, and distribut-ed sensing enables correlated readings and permits advanced, real-time char-acterization of the well environment. The unification of these production- and reservoir-monitoring solutions for flow, temperature, thermal profiling, and seis-mic brings actionable data to the opera-tor for better decision making. JPT◗◗ For additional information, visit

www.weatherford.com.

Fig. 9—Applications of Weatherford International’s OmniWell reservoir-monitoring system include solutions for temperature and pressure, flow, thermal profiling, and seismic.


TECHNOLOGY UPDATE


A critical part of any oilfield production processing is oil and water separation. Although some highly effective demul-sifier products for this purpose have been developed for a number of produc-tion scenarios, the application of demul-sifiers to “heavy” oils remains prob-lematic. However, the work described below has led to the development of a tailored range of demulsifiers to add to the relatively small number of effec-tive chemistries applicable across the growing demands of heavy oil produc-tion activity.

Theoretical models show that the critical parameters of how chemical demulsifiers break crude oil emulsions are associated with the rheology of the oil/water interface. The work undertak-en was to determine whether such cor-relations are justified in real systems by measuring the rheological parameters associated with the oil/water interface and correlating them with demulsifi-er performance. The principle of this model was then used to design more efficient demulsifier molecules. All demulsifiers were evaluated individual-ly for comparison and not as a demulsi-fier blended package.

To meet the needs of field applica-tions, the desired demulsifiers must be very interfacially active and be able to displace the surfactants in crude oil at a use concentration as low as 10 ppm. A range of novel heavy oil demulsifiers has been developed with a wide demul-sification chemistry portfolio, includ-ing resins, polymerics, and esters to optimize and further develop more efficient molecules.

Experimental WorkInterfacial Tension (IFT). Demulsifiers that showed good performance in the IFT testing were further evaluated in a range of crude oils with a range of API gravities, water cuts, compositions, and regions of origin.

Relative Solubility Number (RSN). The relative solubility number of a demulsi-fier is a measure of its solubility prop-erties. This is a key factor in demulsi-fier selection, because solubility prop-erties dictate whether the chemical will perform effectively as a surface-active agent at the oil/water interface. The following physical properties, pour point, viscosity, density, and pH, were measured to provide an indication of how the products could be handled in the field.

Turbiscan Analysis. A Turbiscan labo-ratory instrument, which replicates on-field bottle testing, was used to evaluate the demulsifiers. This method enables the acceleration and documentation of an aging test for an in-depth under-standing of the destabilization mecha-nisms (creaming, sedimentation, floc-culation, and coalescence) of emulsions.

Results and DiscussionA list of the initial chemistries and their physical properties is shown in Table 1.

To establish information regarding the equilibrium adsorption of the demul-sifier materials at the oil/water interface, the IFT (mN/m) was measured over time (sec) for the demulsifiers. Figs. 1 and 2 show the IFT analysis for the demulsi-

fiers listed in Table 1. The graphs show that the steeper the gradient, the fast-er acting the demulsifier, and the lower the equilibrium IFT, the more effective the demulsifier.

The results show that an increased surfactant adsorption time results in a reduction in the value of the IFT. This also leads to an increase in the value of the interfacial elastic modulus. The demulsifiers were then further evalu-ated in the Turbiscan instrument, in some crude oils with a range of API gravities and water cuts. Three heavy crude oils with different gravities and basic sediment and water (BS&W) levels were used for screening the demulsifiers and the details. The crude oils are given in Table 2.

Tables 3 through 5 show the Tur-biscan results from the evaluation with the crude oils.

The characteristics affecting demul-sifier performance show that molecular weight, RSN, and functional groups are the keys to providing good separation of the water and oil in heavy oils. The IFT test gives a bias toward high RSN demul-sifiers, which are stronger water drop-pers. This is mirrored by the Turbiscan tests in the crude oils, as all demulsi-fiers <8 RSN did not exhibit any sep-aration. However, when the RSN was increased slightly (~11), the perfor-mance improved significantly regard-less of the chemical backbone of the molecule. This is related to the extent of alkoxylation, and the products that have high mixed alkoxylation levels have bet-ter demulsification properties than sin-gle alkoxylated products.

Developing New Surfactant Chemistryfor Breaking Emulsions in Heavy Oil Clare Temple-Heald, SPE, Craig Davies, Natalie Wilson, and Nicola Readman, Croda Europe

TechUpdate1Jan14_Art1.indd 30 12/17/13 2:23 PM

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TECHNOLOGY UPDATE


In general, the more water solu-ble demulsifiers show rapid interfacial adsorption and high values of interfacial elastic modulus. The value of interfacial elastic modulus is related to the strength

of interaction between molecules at the oil/water interface. Bulky hydrophobes based on resins, which cannot pack well at the interface, have lower elastic mod-ulus and promote coalescence. With

higher molecular weight chemistries, the interfacial adsorption rate decreas-es, the interfacial activity increases, and the interfacial elastic modulus decreases. Therefore, for higher molecular weight

TABLE 1—DEMULSIFIER CHEMISTRIES AND PHYSICAL PROPERTIES

DemulsifierChemical

Description

Appearance and Physical

Form RSN

Solubility (1% in DIi

water)

Pour Point (°C)

Viscosity at 25°C

(cp)

Density at 25°C (g/cm3)

pH (1% in 85:15 w/w

IPAii:water)

Molecular Weight (Daiii)

A C4/C9 resin, high

ethoxylation

Dark brown/ amber liquid

23 Soluble –30 100 1.01 12.5 <3000

B Ethoxylated trimer acid

ester

Amber/ brown liquid

21 Soluble –12 >5000 1.03 8.0 <3000

C C8 resin, high ethoxylation

Amber liquid 20 Soluble –15 700 1.03 8.5 <3000

D C9 resin, high ethoxylation

Dark brown/ red liquid

19 Soluble –12 >5000 0.98 8.0 <3000

E Quaternized polyimine

Pale yellow liquid

18 Soluble –18 >5000 1.02 4.5 >12000

F Ethoxylated polysorbate

adipate

Amber liquid 17 Soluble –9 1300 1.09 7.0 <7000

G C9 resin, high mixed alkoxylation

Yellow/ amber liquid

17 Soluble –33 1100 1.01 8.0 <7000

H EO/PO block copolymer

adipate

Pale yellow liquid

15 Dispersible –6 1700 1.01 4.0 <12000

I C9 resin, high mixed alkoxylation

Dark brown/ amber liquid

11 Insoluble 12 >5000 1.00 9.5 <7000

J EO/PO block copolymer

adipate

Brown/ amber liquid

11 Dispersible –9 800 1.05 6.5 <7000

K TMP EO/PO alkoxylate

Clear liquid 8 Insoluble –15 1300 1.00 7.5 <7000

L C9 resin, high propoxylation

Yellow liquid 8 Insoluble –30 1200 0.93 10.5 <3000

M PEG (40) sorbitol

hexaoleate

Pale yellow liquid

7 Insoluble –18 200 1.01 7.0 <3000

N Nonionic block

copolymer

Brown waxy solid

7 Insoluble >30 N/A N/A 7.0 <7000

O C9 resin, low propoxylation

Yellow/ amber liquid

6 Insoluble –12 >5000 0.92 8.5 <3000

i—deionized, ii—weight-to-weight isopropyl alcohol, iii—daltons


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TECHNOLOGY UPDATE

Fig. 2—Interfacial tension vs. adsorption time for demulsifier solutions in toluene at 10 ppm (products that achieved an equilibrium value of <15 mN/m). Graph courtesy of Croda.

Fig. 1—Interfacial tension vs. adsorption time for demulsifier solutions in toluene at 10 ppm (products that achieved an equilibrium value of >15 mN/m). Graph courtesy of Croda.

40

35

30

25

20

15

10

5

00 500

Demulsifier D Demulsifier E Demulsifier H

Demulsifier K Demulsifier M Demulsifier O

Demulsifier I

1000 1500

Time, secIn

terf

acia

l ten

sio

n, m

N/m

2000 2500 3000

40

35

30

25

20

15

10

5

00 500

Demulsifier A Demulsifier B Demulsifier C Demulsifier F

Demulsifier G Demulsifier J Demulsifier L Demulsifier N

1000

Inte

rfac

ial t

ensi

on

, mN

/m

Time, sec

1500 2000 2500 3000

TABLE 2—CRUDE OIL CHARACTERISTICS

Crude Oil Source °APIApproximate

BS&W (%) Characteristics

A UK onshore 11 50 —

B UK onshore 11 70 —

C France 18 55 Sour, asphaltenic

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TABLE 3—CRUDE OIL A (UK ONSHORE, 11 °API, BS&W 50%)

Demulsifier Chemical Description % Demulsified as % of BS&W Interface Quality Water Clarity

A C4/C9 resin, high ethoxylation 32 Excellent Excellent

B Ethoxylated trimer acid ester 20 Excellent Excellent

C C8 resin, high ethoxylation 100 Excellent Good

D C9 resin, high ethoxylation 100 Excellent Good

E Quaternized polyimine 100 Excellent Excellent

F Ethoxylated polysorbate adipate

98 Excellent Excellent


100 Average Poor

H EO/PO block copolymer adipate



100 Good Good

J EO/PO block copolymer adipate


K TMP EO/PO alkoxylate 20 Excellent Excellent

L C9 resin, high propoxylation No performance

M PEG (40) sorbitol hexaoleate No performance

N Nonionic block copolymer No performance

O C9 resin, low propoxylation No performance

TABLE 4—CRUDE OIL B (UK ONSHORE, 11 °API, BS&W 70%)



B Ethoxylated trimer acid ester 84 Average Average

C C8 resin, high ethoxylation 100 Excellent Good

D C9 resin, high ethoxylation 94 Poor Poor

E Quaternized polyimine 75 Average Average

F Ethoxylated polysorbate adipate

99 Excellent Good


100 Average Very poor

H EO/PO block copolymer adipate

82 Average Average


100 Good Average

J EO/PO block copolymer adipate

84 Average Average

K TMP EO/PO alkoxylate No performance






TECHNOLOGY UPDATE


demulsifiers, the initial effect is slower but more effective overall.

The other physical properties eval-uated in the study show no correla-tion with performance, but are required for the user to understand how to handle and use the demulsifiers in field condi-tions. The chemistries chosen were var-ied to assess surfactants other than those based on nonyl phenol resins. Although the nonyl phenol-based demulsifiers are still the best performers, other chem-istries have shown suitable demulsifi-cation performance. In particular, an ethoxylated polysorbate adipate (pat-ent pending) performs well in heavy oil, while classified as yellow and inherently biodegradable for use in the North Sea.

Internal development work was also done to evaluate resins with longer alkyl chains as resin alkoxylate demulsifiers. From this work, it was found that the ethylene oxide:propylene oxide mix and resin:alkoxylate ratio are more impor-

tant for demulsification performance than the type of resin used.

Customer trials with demulsifiers were executed and the leading products correlated with the performance in the laboratory. However, a formulation of several demulsifiers is commonly used to obtain optimum field performance.

ConclusionsLeading-edge techniques have been used that measure demulsifier interfacial properties, measure how these proper-ties relate to demulsifier performance, and evaluate how a range of demulsifi-ers perform in heavy crude oils. The ele-ments of molecular structure that deter-mine adsorption properties have been discussed, and this understanding has guided the development of new demul-sifier types with improved performance. Although the nonyl phenol resin alkox-ylates are the best performing products, a variety of chemistries can be used in

heavy oil, including ethoxylated polysor-bate adipates.

In field situations, the most effec-tive demulsifiers are likely to be a for-mulation of high and low molecular weight materials. The high molecular weight species occupies a large area at the interface, which reduces the sur-factant concentration, whereas the lower molecular weight materials will aid rapid relaxation of the IFT. The dif-ficulty in designing better perform-ing demulsifiers lies in balancing these various parameters, some of which are in opposition.

AcknowledgmentsThe authors would like to thank Croda employees involved in helping with the article. The authors also wish to thank Recherche Exploitation Produits and Star Energy for supplying materials, and Teclis and Fullbrook Systems for their technical support. JPT

TABLE 5—CRUDE OIL C (FRANCE, 18 °API, BS&W 55%)



B Ethoxylated trimer acid ester No performance

C C8 resin, high ethoxylation 60 Excellent Excellent

D C9 resin, high ethoxylation 89 Excellent Excellent

E Quaternized polyimine 71 Average Poor

FEthoxylated polysorbate

adipateNo performance

GC9 resin, high mixed

alkoxylation75 Average Poor

HEO/PO block copolymer

adipate76 Excellent Good

IC9 resin, high mixed

alkoxylation85 Good Good

JEO/PO block copolymer

adipate33 Excellent Excellent

K TMP EO/PO alkoxylate No performance






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BH_037_jpt.indd 1 12/16/13 9:35 AM

YOUNG TECHNOLOGY SHOWCASE


Determining the fluid properties of a reservoir by using pressure/volume/temperature (PVT) analysis is essen-tial to petroleum reservoir studies, production equipment design, and reservoir recovery efficiency estima-tion. The properties of the formation fluid are used to determine reserves and to predict reservoir performance and economics. PVT properties such as bubblepoint pressure, gas/oil ratio,

viscosity, oil formation volume factor, and detailed composition are impor-tant to well performance analysis, mate-rial balance calculations, reservoir simulation, and production engineering calculations.

Once the reservoir information is available, the well team makes the criti-cal field development decisions. Con-ventional post-well wireline formation testing operations can delay decision

New LWD Service Integrates Formation Fluid Analysis and Sampling

Editor’s note: If you have a

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The fluid analysis and sampling service can capture up to 16 fluid samples.

YoungTechJan.indd 38 12/16/13 2:29 PM


making for days, sometimes months, depending upon the logistics involved in transporting a sample from the well-site to a PVT laboratory. Additional-ly, wireline deployment is expensive in horizontal and highly deviated wells because of the extra time and equip-ment required to convey the tools to the test intervals.

Integration BenefitsThe latest logging-while-drilling (LWD) technology integrates downhole fluid analysis and sampling with forma-tion pressure while drilling (FPWD), thereby providing environmental, eco-nomic, time-saving, and data quality benefits over traditional methods of res-ervoir characterization. The integration

enables three distinct services: real-time formation pressure tests, real-time in-situ measurements of fluid proper-ties, and downhole capture and retrieval to the surface of fluid samples.

The real-time formation pressure testing provides important information on fluid dynamics within the reservoir, mobility measurements, and zone pro-ductivity predictions. It is also impor-tant for accurate gradient analysis. Mea-suring multiple formation pressures at different depths delivers a formation fluid gradient that makes it possible to find contact points between different formation fluids such as water, gas, and oil. Pressure testing in an LWD environ-ment also provides important informa-tion for safety and drilling optimiza-tion, including data that are valuable for controlling hydraulic overbalance and equivalent circulating density.

Representative fluid samples pro-vide information on the production potential of the reservoir. LWD fluid analysis and sampling enables fluids samples to be collected closer to in-situ conditions for a more accurate determi-nation of fluid composition. Addition-ally, sample integrity can be monitored continually from the first time the sam-ple enters the LWD tool until it is trans-ferred to the laboratory for detailed analysis. Greater accuracy improves project cycle times and reduces devel-opment risks.

Although the vital information pro-vided by the integrated LWD service is useful throughout the life cycle of a res-ervoir, it is particularly valuable during the initial assessment to determine the commercial potential of a project. The assessment includes estimates for pro-ducibility, fluid type and composition, fluid phase behavior, production facility design, and flow assurance.

FASTrak ServiceBaker Hughes’ FASTrak LWD fluid analysis and sampling service can col-lect an unlimited number of pressure and fluid analysis tests, and capture and recover up to 16 fluid samples under

The FASTrak service operates like other formation testing services.




PVT conditions. The service is based on the reservoir characterization instru-ment and offers automatic sequencing during pressure testing, pump-through operations, and sampling.

The tool consists of four modules: the power module, the pump and ana-lyzer section, the tank module, and the termination sub. The power module is a dedicated mud turbine-alternator sys-tem that provides the power for extend-ing and retracting the sealing element; opening and closing the valves within the modules; and operating the fluid identification sensors. It also provides power to the drawdown pump during pressure testing and cleanup operations.

The pump and analyzer section is the heart of the tool. It contains the pad-sealing element, the quartz pres-sure gauge, the sample pressure strain gauge, multiple temperature sensors, the drawdown pump, and the fluid ana-lyzer. The pad and pump design is simi-lar to that of the field-proven TesTrak FPWD service. Filters within the flow-line and pad prevent plugging. The pad-sealing element is exchangeable with different probe diameters for varying formation mobilities. A high-tempera-ture pad for temperatures above 275˚F (135°C) is also available. The quartz pressure gauge is the same as in FPWD tools. Strain gauges monitor the tank-filling pressure during each sampling process. Multiple temperature sensors in the flowline and on the pressure sen-sor electronics monitor tool and forma-tion fluid temperatures. The drawdown pump is designed for, and operated up to, 8,700 psi (600 bar) differential pres-sure at rates of up to 25 cm3/s for maxi-mum sampling efficiency.

The fluid analyzer contains four sensors: the piezoelectric tuning fork, the acoustic transducer, the tempera-ture sensor, and the refractometer. They measure fluid properties to help distin-guish mud filtrate from formation fluid and enhance the understanding of fluid

type, contamination level, and compo-sition. Density and viscosity are mea-sured using the tuning fork. The high-frequency acoustic transducer makes sound speed measurements by measur-ing the response of the acoustic travel time through the fluid. The high-resolu-tion response makes it possible to detect even very small changes in contamina-tion. The refractometer, which is highly sensitive to changes in water salinity, is used for optical analysis of the down-hole fluid.

Each tank module is capable of car-rying up to four tanks. The tool can carry four tank modules, providing the capability for retrieving up to 16 single-phase fluid samples per run. The termi-nation sub provides an exit to the well-bore for the contaminated fluids while the system is cleaning, before taking the fluid sample.

OperationThe FASTrak service operates like other formation testing services. Operations begin by positioning the tool within the formation of interest. Annular borehole pressure is measured before the pad or packer extends from the tool and seals itself against the borehole wall. The packer isolates the hydrostatic pressure in the borehole from the tool’s internal test and measurement system. Initially, a small quantity of fluid is drawn into the tool to confirm that a packer-to-for-mation seal has been achieved. The for-mation pressure is then recorded. As fluid flows into the tool, the pressure increases to a final stabilized value. The pressure buildup profile provides infor-mation about the local reservoir mobili-ty. A dual-action piston pump draws for-mation fluid in repeat drawdowns and discharges it either to the wellbore or into one of the sample chambers. When the mud-filtrate contamination is at a minimum level, the sample can then be directed into one of the sample tanks for future analysis.

Operational efficiency and test accuracy are enhanced by two continu-ous control closed loop systems. The SmarTest system enables fluid pressure and mobility testing to be performed automatically and the test parameters to be monitored by the engineer at the surface. The system then selects the optimum pretest and prepares to take a sample on the command of the engi-neer. The SmartPad system automati-cally maintains seal integrity through-out the operation.

Although still undergoing field testing, the new LWD fluid and pres-sure testing service is building a track record worldwide.

The service provided accurate pres-sure testing and gradient analysis in a highly deviated, unstable formation in the Netherlands. The project set an area record by acquiring more samples in a single run than other comparable servic-es. Twenty-five pressure tests were per-formed and three gradients were identi-fied, targeting four zones of interest for sample acquisition. Twelve single-phase samples were acquired—six oil, three water, and three gas—with 100% seal-ing efficiency. This test illustrated how the system mitigated risk while improv-ing drilling safety and efficiency.

In Australia, the service acquired 25 formation fluid samples and a range of pressure tests in challenging, near hor-izontal wellbores. The high number of samples acquired and excellent opera-tional efficiency enabled the operator to make critical field development deci-sions while saving valuable rig days.

In an oil-bearing reservoir in the deepwater Gulf of Mexico, the LWD ser-vice obtained three single-phase sam-ples with less than 5% contamination and identified a disconnect that, when verified, confirmed a fault that was seal-ing within the reservoir.

Numerous jobs are scheduled for Europe, Latin America, and the Asia Pacific region. JPT


Which Operators?

BHP including Petrohawk, Chevron including Atlas, EP

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Altamont, Appalachia, Avalon, Bakken, Barnett, Bossier,

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Falher, Fayetteville, Granite Wash, Groundbirch, Haynesville,

Horn River, Magnolia, Marcellus, Mesaverde, Montney,

Muskwa, Niobrara, Olmos, Otterpark, Permian, Pinedale,

Sand, Spraberry, Three Forks, Wasatch, Wilcox, Williston,

Wolfcamp, Woodford and many more in the pipeline.

How many wells?

Thousands, and the number of Operators and wells is

growing all the time.

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Very. The data is independently quality controlled by an

organisation with 25 years’ experience of doing this.

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If you are an Operator of shale gas or tight oil wells I would

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Many operators have a register of flanged connections identified as having fitted stud bolts below acceptable stan-dards and, on many occasions, in criti-cal condition requiring urgent attention. Corroded stud bolts seriously under-mine an asset’s integrity and unsched-uled pressure releases can have a dev-astating impact on offshore operations.

In 2009, the situation prompted several operators in the United Kingdom Continental Shelf to contact Stork Tech-nical Services regarding safety concerns related to incidents of uncontrolled pressure releases and future potential releases, as a result of severe stud bolt corrosion/failure on four-bolt flanged connections. Many of the corroded stud bolts were proving difficult to remove and replace during planned shutdown

activities, because of their location and the presence of existing systems.

Stork was asked to develop a more sophisticated method of removing and replacing corroded stud bolts that would mitigate risk and improve the safety of operations and the wider asset, while simultaneously reducing operat-ing costs and optimizing productivity.

Comprehensive R&DStork embarked on a rigorous re-search, design, and testing program and worked with a specialized manufacturing company to develop the hot bolt clamp (HBC) technology. The patented HBC sys-tem enables the safe removal and replace-ment of corroded stud bolts on live four-bolt flanged connections, with no disruption to ongoing production.

Since its introduction and develop-ment in 2012, the technology has suc-cessfully reworked thousands of four-bolt flange connections. Since devel-oping the initial standard HBC, which covers Class 150 rating flanges from 2 in. to 3 in., Stork now produces a range of HBCs to cover all four-bolt flang-es, including those designed for tight, restricted access applications.

Hot bolting (the practice of remov-ing, replacing, or freeing and retighten-ing stud bolts on live piping and equip-ment) of flanged connections with eight bolts or more is a well-established prac-tice. Traditionally, any stud bolt activity on four-bolt flanges required the system to be shut down, isolated, and purged prior to breaking the flange integrity to enable rework. This is a lengthy pro-cess requiring the system to be shut down (typically, with lost production) as well as associated alternative ser-vices to be in place to cover system purging and subsequent system testing to prove the integrity of the disturbed flanged connections.

The HBC system allows hot bolt-ing to be carried out on four-bolt flang-es without a shutdown. Corroded stud bolts can be removed and replaced on live connections while maintaining flange integrity, which delivers cost, efficiency, and time benefits.

The system hydraulically clamps pressurized bolted pipeline flanges together in a controlled manner so that the corroded stud bolts can be safe-ly removed. Once all the bolts have been replaced, the hot bolt clamps are depressurized and removed. Change-out of the bolts is achieved without tak-ing the flanges out of operation, disrupt-

Hot Bolt Clamp Addresses Corrosion Problem

Fig. 1—The hot bolt clamp (HBC) system undergoes vigorous testing and checks.

YoungTechJan_Art2.indd 42 12/17/13 2:22 PM


ing standard line pressure, or the dan-ger of a medium release.

Using the HBC, a four-bolt flange can be reworked in only 40 minutes and, as the system can be used on live assets, typically removes approximately 1.5 days of activity from a planned 1-month shut-down, which would otherwise equate to hundreds of thousands of dollars lost in deferred production. This also reduc-es the number of personnel required on board during the shutdown period at a time when bed space is at a premium.

Converting the initial clamp con-cept into a safe, practical, and efficient tool posed a number of significant chal-lenges. The clamp dimensions had to be compact enough to fit around the flanged dimensions, as well as having suitable rigidity to deliver sufficient load so as to start transferring the retained stress from the studs to the clamps. At the same time, the clamp also had to be adjustable to cater to a wide range of flanges.

The initial conceptual design was carried out with 3D computer-aid-ed design to check for limiting access/geometry constraints and using finite element analysis modeling. Rigorous testing was then carried out on manu-factured clamps, with hydraulic cylin-der, full-cyclic pressure tests to simu-late real environment use. The cylin-ders were pressurized beyond maximum working pressure for 10,000 pressure cycles with realistic dwell times between each pressurization.

Once the manufacture of the clamps was complete, the process of develop-ing the site service was initiated, which saw the clamps being operated in con-junction with ultrasonic bolt load mon-itoring equipment to ensure that min-imal load transfer could be detected while preventing excessive load transfer through the assembly to the energized sealing gasket.

Case StudyStork was contracted by Shell UK to carry out four-bolt flange replacement on the Nelson North Sea platform. It

was also asked to carry out a prejob sur-vey on the platform to determine a fixed scope of work. This allowed work to be planned efficiently in line with ongoing work scopes. All flanges worked were under live working conditions, which enabled the HBC team to work on them without the need to depressurize and purge any lines, thus removing the requirement for a costly shutdown.

Following the initial trip and suc-cessful bolt change on 20 flanges, the company continued using the HBC sys-

tem to operate a 5-month program in which more than 500 four-bolt flanges were successfully hot bolted. The full work scope was carried out in time and within budget, and the work was com-pleted safely.

After receiving requests from a number of operators and technical authorities, the next evolution of the clamp design is currently under way. Further innovation and new applica-tions will be developed and covered by the technology. JPT

Fig. 2—Flange before using the HBC system.

Fig. 3—Flange after using the HBC system.

YoungTechJan_Art2.indd 43 12/17/13 2:24 PM

SPE TECHNICAL DIRECTORS’ 2014 OUTLOOK


A condensed version of what is on the minds of SPE’s technical directors is: The industry needs multidisciplinary, data-driven ways to adapt to what is

ahead, focus on what is critical for decision making, and take a long view as another generation takes over.

In other words, this group of six representing key industry disciplines has a lot of ideas. When SPE’s technical directors met in October 2013, they discussed two big ideas that may become group projects: better management of critical processes to ensure they are done safely, and caring for aging fields.

A discussion of whether managing aging fields is worthy of greater attention brought up the challenge of permanently plugging offshore wells not designed with current technology in mind, whether worn tubulars in old wells can withstand the stress of life-extending fracture treatments, and estimating how long a well is likely to be producing.

“It crosses disciplines. There are problems, and opportunities to get more out of fields, that cross the lines,” said Roland Moreau, SPE technical director for Health, Safety, Security, Environment, and Social Responsibility, who has taken a personal interest in process safety.

Smarter, faster use of data is a common theme. David Curry, SPE technical director for Drilling and Completions,

wants to see drilling systems that are wired to manage the data needed to observe what is ahead and intelligently respond to it. Olivier Houzé, SPE technical director for Reservoir Description and Dynamics, sees the need for better systems to highlight critical bits of information from all the data flowing in as more sensors are built into wells.

Shauna Noonan, SPE technical director for Production and Operations, is interested in better long-term production management of unconventional wells. Her concern overlaps Houzé’s work on predicting reservoir life for unconventional wells because “part of the plan is for retirement, but how do you do that when you do not know what the retirement age is?”

When it comes to petroleum engineering educators, the average retirement age is uncomfortably close for two-thirds of those in academia. The academic crew change comes at a time when there has been a surge in the number of students enrolled, putting stress on institutions that are struggling to keep up. Cindy Reece, SPE technical director for Management and Information, said SPE needs to actively foster new ideas and greater cooperation between academia and industry to ensure a quality education for future petroleum engineers. “When we look at what is needed in the future, what we have today is not sustainable,” Reece said.

Stephen Rassenfoss, JPT Emerging Technology Senior Editor

A Long-Term ViewFrom Multiple Angles

TechDirectors.indd 44 12/17/13 2:36 PM


Shauna noonanSPE Technical Director, Production and Operations

not Fade away When SPE’s technical directors discussed managing aging oil and gas facilities, one question was: What do you call it? Plugging and abandonment has long been used, but the word “abandonment” sends a negative message to those living around those wells, and the directors want to make the point that the issues go well beyond permanently sealing old wells. Other possible labels include managing mature assets; fields nearing the end of their life; or restoration, since the procedure restores natural barriers where a well once flowed.

Noonan said there needs to be more thought about the end from the beginning. As with saving and investing for retirement, decisions made early on can have a profound impact decades later. This is particularly true for a generation of unconventional wells, because the cost of early miscalculations can be magnified by the tens of thousands that are being mass produced each year.

“The industry needs to think about how these wells will be produced years down the road as they near retirement,” Noonan said. “This is not a problem to be handed over to the production engineers once the well is drilled and completed.” Well design decisions affect the cost and effectiveness of pumping systems, flow performance, and well intervention capabilities.

Long-term monitoring could be used to extend the life of a field, but the decision to install

that costly hardware when the well is completed needs to

be made during planning. “For the unconventional well developments, a multidisciplinary team

of drilling, completions, production, and reservoir

engineers needs to map out an overall strategy of the entire well

life cycle,” Noonan said. The team’s vision needs to extend to the end of the

well’s life, when it will need to be permanently plugged. She said those building wells now need to answer the question “Are current drilling and completing practices leading us down a path that would make wellbore retirement a technical challenge?”

Even small decisions can have a lasting impact. Noonan would like to see greater use of “management of change” systems, which are used in industries such as aerospace to observe and control daily decisions. These systems are widely used to track maintenance work on major processing

equipment used on the surface, such as gas processing units, and Noonan said “that needs to be done below the wellhead.”

oLIVIER houZÉSPE Technical Director, Reservoir Description and Dynamics

Telling DetailsThe exploding number of sensors in wells offers reservoir engineers the opportunity to understand reservoirs as never before, if they only had the time to understand it all.

For Houzé, there is opportunity in this irony. The biggest challenge has moved from creating

computer systems capable of filtering enormous volumes

of data from sensors to developing smart software that ensures meaningful information is not missed. Doing so will require new

analytical methods that identify trends in data, point

out anomalies worth further attention, and provide data-based

forecasts. “What is common to the three items is that they all aim at saving an engineer’s time, which is the main, if not only, way to address information overload,” Houzé said.

The overload is the product of the growing number of wells with long-term monitoring systems, such as pressure sensors. This is likely to increase exponentially with the use of equipment such as fiber optic cables capable of measurements throughout the wellbore. A notable exception is unconventional formations, where the industry is still lacking quality data. Compounding the problem is the rise in wells per engineer as companies develop drilling-intensive onshore formations.

“The number of potentially significant recorded events has inflated to the point where it is absolutely impossible for the engineers to treat them all,” Houzé said. He offered several responses to the challenge:

◗ Refine computerized field management work flows so engineers can focus on instances where the observed data diverges from what was predicted.

◗ Revisit artificial intelligence, which fell out of favor after the 1990s, to create programs that constantly monitor well data, presenting engineers with problems likely to require creativity and the ability of humans to deal with events that fall outside the norm.

◗ Use models based on big data, rather than physics, to detect trends, spot outliers, and even provide draft forecasts.




“These systems let the data (production, logs, etc.) constrain a physics-less model that only honors the observed behavior,” Houzé said.

While the most enthusiastic supporters of this modeling approach argue that reservoir data-only production forecasts are the future, Houzé sees them as a near-term option, but not the final word. “All these technologies are meant to save time and streamline information,” he said. “The final word has to be with well-trained engineers using models honoring the physics. If you only rely on automatic physics-less processes, be ready for billion-dollar cyberblunders.”

DAVID CURRYSPE Technical Director, Drilling and Completions

Detect and ReactAdaptive well construction is not a familiar concept, but anyone who drives a new car has likely benefited from it. In driving and drilling, systems are able to use a rapid flow of data to react to changing conditions, such as the way

antilock brakes adjust to force applied to them on a wet road.

“Many parts of the control systems in modern

cars are adaptive,” said Curry, who recently helped organize an SPE forum to explore adaptive drilling and

completion systems. “As you drive, you are in ignorant bliss

of the incredible control system under you. If you turned it all off, you

would appreciate how much it is doing to look after you.” Adaptive systems have been developed to speed

drilling by using downhole data to adjust the weight-on-bit and rotary speed to reduce vibration. But the oil industry lags behind the automobile industry in using them. “Driverless motor cars are capable in tests of navigating safely along busy highways, so why can’t we do the same with our wells?” Curry said.

Reaching that goal will require better spatial awareness. One of the best known examples of adaptive well construction is geosteering, which guides the drillbit using petrophysical data showing where it is in relation to geological structures mapped during planning. “But with sensors typically 30 to 90 ft behind the bit, and current mud pulse telemetry rates, it’s a bit like trying to steer down the highway at 70 mph by looking in the rearview mirror,” Curry said.

“The challenge is knowing where you are geologically,” he said. “There are many things you could be doing better with a better knowledge of the environment you are drilling into.”

A key to reaching that state of knowledge is creating an electronic nervous system that provides a detailed picture of what is ahead based on drilling data gathered closer to the bottom of the hole, which is linked to a control system capable of intelligently responding to what is observed.

Doing so will require integrated systems with communication links that allow a wider range of sensors to transmit more data faster to control systems programmed to make the correct adjustments as conditions change.

Drillers will still be able to intervene when needed, but there was a discussion at the forum about how to define their role and how best to manage interaction between humans and future control systems.

“We have some of the technologies for adaptive well construction now,” Curry said. “We can look out 10 to 20 years to technological capabilities we would like to have and how we could use those to revolutionize how we drill wells.”

HOWARD DUHONSPE Technical Director, Projects, Facilities, and Construction

What Were They Thinking?Oilfield facilities engineering mixes precise analysis based on math and logic with the mental habits, psychology, and social skills of people in large organizations. Technical skills are obviously important, but so are soft skills.

Duhon is interested in both sides of the process. The level of difficulty in project management is rising along with the scale and complexity of the jobs, as well as the number of parties with a stake in the outcome. “The mission for the industry in the projects, facilities, and construction area is more effective project execution, more effective community engagement, and continuous improvement in process safety,” Duhon said.

He has been busy expanding the information and training available for members within the discipline. There will be more how-to articles in SPE’s Oil and Gas Facilities

magazine, which serves the discipline. A new SPE technical

section is being formed bringing together those involved in flow assurance issues, adding to what is offered by the Separation Technology and Water

Handling technical sections. Looking ahead, he sees the

need for similar attention to issues related to compressors.

When he looks at design, construction, and operations, Duhon also sees the need for greater awareness about what


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goes into engineering decisions. His work as a facilities engineer offers regular reminders that in this objective profession, with precise formulas used to define what needs to be done, there is a human element that adds a level of subjectivity.

Duhon’s interest in the messy process of how decisions really are made led to his first involvement in SPE committees. He began his study of decision making with objective systems, such as decision trees and linear programming. Over time Duhon has focused more on the social and psychological aspects of how decisions are made One goal is to make project managers aware of decisions they do not even notice they are making. “The invisible two-thirds of the iceberg is decision making,” Duhon said.

“There are explicit decisions—when you choose what type of compressor to install—where it is clear you are making decisions,” he said. “But most of our decisions are tacit—most do not realize they are making a decision when they do an analysis just like they did it on the last project.”

ROLAND MOREAUSPE Technical Director, Health, Safety, Security, Environment, and Social Responsibility

In ProcessThe SPE Board of Directors is considering ways to focus more on process safety. The challenge in that is deciding which

processes merit close attention. Moreau, who has been an

advocate for a greater focus on process safety, likened the

challenge to consuming a pie: “We cannot eat it all at one time. We need to break it into chunks.”

To gather input, Moreau used SPE Connect

to ask members to share their process safety concerns and he

received responses from around the globe. They suggested issues from safely integrating large systems to planning for how to properly execute an emergency shutdown. The goal is to choose the initiatives and programs that improve how the industry analyzes its operations to identify and reduce risks.

The push to expand process safety efforts comes at a busy time in this discipline. An SPE summit in March will consider how best to calculate worst-case discharge from offshore wells. United States regulators asked SPE to take a second look at the issue, which its members first considered in the wake of the Macondo disaster in the US Gulf of Mexico.

Those general guidelines have guided operators preparing the estimates that must be submitted in permit

applications for drilling in the US Gulf of Mexico. The US Bureau of Ocean Energy Management asked for a second, more detailed look, because it was concerned about the wide variations in some worst-case discharge estimates.

An SPE subcommittee is working on a more specific estimation method to calculate the size of a worst-case oil discharge using probabilistic analysis. The goal is an SPE- recommended method—a formula plus examples for how it can be applied in different circumstances. A proposal under development will be reviewed by an invitation-only group of experts from industry, academia, and regulators.

Growing use of chemicals for exploration and production led to plans for a workshop on chemical risks this year. Proper chemical management is a challenge for some companies in the industry, particularly those without specialized professionals on staff.

A July 2012 SPE summit looking at human factors in operational safety will yield a white paper. Moreau said there is also interest in starting a human factors technical section. And he is looking for member input for HSE Now, the SPE online periodical for what is new, interesting, and on the minds of professionals in the field.

cINDy REEcESPE Technical Director, Management and Information

The Other crew changeTo explain why she is concerned about the future of petroleum engineering education, Reece starts with a simple chart. It shows that the number of petroleum engineers expected to graduate in the next couple years is near the peak reached in the early 1980s when the industry was booming.

The problem in that good news is that in between the highs then and now is a deep U-shaped valley. The chart, based on an annual survey by Lloyd Heinze, a petroleum engineering professor at Texas Tech University, shows the number of petroleum engineering graduations falling rapidly after the oil boom ended and oil companies began cutting jobs. The curve turned steeply up in 2005 when companies began hiring large number of engineers to prepare for the big crew change, as many key workers

near retirement. Colleges, which downsized during lean times,

have been unable hire teachers fast enough to keep up with

rising enrollments. The number of students per faculty members jumped from less than 15:1 in 1993

to near 55:1 in 2013.This shift has put a

heavy load on the professors,



many of whom are nearing retirement age. More than two‑thirds of petroleum engineering faculty members in the US universities surveyed are older than 50, and 37% of them are past age 60. While similar statistics are not available outside the US, academics from other countries at a recent SPE forum on the future of petroleum engineering education, said they face similar problems, Reece said.

SPE’s Board recently recognized the critical nature of this issue when it made attracting, developing, and retaining petroleum engineering faculty a strategic initiative. To support this effort, the organization committed USD 600,000 a year to recognize faculty who use innovative teaching techniques and those who are successful at attracting people into an academic career. The program also helps new faculty members establish research programs.

It is a positive step, but Reece said the problem is far larger. There is a wide pay gap between academia and industry—a petroleum engineer with a bachelor’s degree can often earn more than an assistant professor with a PhD— which steers students away from seeking advanced degrees and entering academia.

Another area of need is industry support for young academics so they can do the research needed to publish

papers. Overcrowded laboratories need to be expanded and updated with the latest equipment.

“What we are finding is that the issues are so complex, no one company or no one university has the ability to really solve them,” Reece said. It will require collaboration among academia, which SPE is working to facilitate. SPE’s role is to promote programs that address specific issues and facilitate collaboration to spread the use of good ideas, she said.

One promising possibility is a cooperative program among universities to open up wider access to classes and equipment among students in participating institutions. Another would be to have petroleum engineering experts loaned by companies to teach in their area of expertise.

Other ideas include creating online networks that promote sharing of course‑related material, and using advanced communications to allow students at one school to remotely use automated laboratory equipment elsewhere.

Regional pilot programs in Nigeria and the northeastern US are currently under way to better understand regional differences, because the problems vary, as will likely solutions. Reece said, “It is not going to be one thing. It will be a lot of things.” JPT

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Robotic submarines, capable of operating by themselves thousands of feet underwater for months or perhaps years

at a time, are under development as the vanguard of tomorrow’s subsea oil and gas fields. This development comes as the off-shore oil and gas industry moves into ever-deeper waters and remote areas of the world, where installing a floating produc-tion facility is either economically unjustifiable or infeasible.

The industry’s solution is to install production equip-ment on the seafloor, where someone, or something, must keep a close eye on all of it. That something is likely to be what are known as field resident autonomous underwater vehicles (AUVs). Nonresident AUVs have already paved the way by prov-ing they can carry out detailed inspections of platforms and pipelines in some cases four times faster than a human-piloted remotely operated vehicle (ROV). Two of the leading companies in the resident AUV business, Lockheed Martin and Saab Sea-eye, are blending proven military technology with new software and hardware optimized for the offshore industry. Their emerg-ing systems represent a new breed of subsea robots that will be capable of much more than earlier generations of autonomous systems. As their capabilities are realized, resident AUVs will eventually be assigned many of the same tasks that ROVs are carrying out today.

To achieve that end, offshore operators are working with manufacturers to identify how best to fully deploy this emerg-ing technology. Much of the groundwork is being laid through

DeepStar, a research and development consortium that counts 11 operating companies as members. “We are already using AUVs for certain functions on a sporadic basis, but we’re try-ing to understand, as operators, what else this technology can do reliably,” said Greg Kusinski, DeepStar director and Chevron senior advisor to DeepStar.

DeepStar’s primary goal is to accelerate the development and adoption of AUV technology by drafting interface stan-dards, similar to the standards already developed for ROVs. Among the interface issues yet to be resolved is how resident AUVs will connect to life support systems in a subsea field. Because resident AUVs will have to remain submerged for months to possibly years at a time, the docking station is a criti-cal piece of equipment that will charge up the AUV and upload its data to the operator’s server by a subsea Internet connection.

Once the particulars of the docking station are under-stood, Kusinski said careful consideration must be given to other issues, such as where to place it among the subsea infra-structure. “There are a lot of questions of that nature,” he said. “As responsible operators, we are addressing these issues in a very systematic and methodical manner. I don’t think anyone is interested in putting a bunch of them down there and just seeing what happens.” DeepStar expects to conclude its AUV study on interfaces in about a year and will deliver its recom-mended best practices to the American Petroleum Institute for review.

Robotic Roustabouts for tomorrow’s subsea Fields

trent Jacobs, JPT Technology Writer

The Marlin Mk3 is an autonomous underwater vehicle (AUV) under development for the deepwater oil and gas industry. Equipped with several sensors and tools (not shown), the AUV is designed to carry out inspections and intervention operations of subsea equipment and infrastructure. Illustration courtesy of Lockheed Martin.

Submarine.indd 50 12/17/13 2:17 PM


Resident Capabilities Although AUVs have been used by the offshore industry for years, they have had very limited application until recently. One subset of AUVs called underwater gliders travel thousands of miles across the world’s oceans collecting oceanographic data for sci-entific research, but are not applicable to the deepwater environ-ment. Torpedo-shaped AUVs can zip through the water at high speeds while conducting ultrahigh-resolution seismic surveying and mapping; however, they lack the maneuverability to conduct the close inspection, sensor replacement, and valve operations a subsea production facility would demand. Human-piloted ROVs are not the answer either as they were designed to stay underwa-ter for only hours at a time, not days, weeks, or months.

A resident AUV must be able to hover in place or move in any direction. It must also have an onboard collision avoid-ance system that will prevent it from striking environmental hazards or production systems on the seafloor. “We have stan-dardized what kind of forces and momentum an ROV can carry into infrastructure from an impact perspective,” Kusinski said. “Now we are thinking about that from an AUV perspective, and since they are smaller, we could potentially allow them to trav-el faster.” ROVs are restricted in terms of speed for other rea-sons too. A typical ROV must move as slow as half a knot (kn) to properly manage its tether system and allow the surface vessel to follow it from location to location, whereas a resident AUV moves as fast as 6 kn because it works independently.

And unlike a work-class ROV, to deploy an AUV, operators do not need to contract a dynamically positioned support ves-sel. Day rates for this type of vessel, which in many cases are at least 300 ft in length and house up to 100 crew members, run as high as USD 250,000. Large vessels are needed because an ROV comes with a large equipment spread that includes a tether management system, winches, a control van, and replacement parts that together can weigh up to 90 tons. In contrast, an AUV can be launched and recovered from a significantly smaller ves-sel because it comes with a small amount of supporting equip-ment and without a tether, dynamic positioning is not needed.

Additionally, work-class ROVs require an onboard team of pilots and technicians to operate the vehicles and repair them when they break down. In contrast, when an AUV hits the

water, it begins its mission without the need for human inter-action until it resurfaces. Customized operations can be pre-programmed into the AUV telling it what to do in certain situa-tions and new commands can be uploaded to its software while submerged. Another important distinction is that AUVs are less prone to mechanical failure because they have fewer moving parts than an ROV and no hydraulic systems.

With these advantages in mind, AUV makers are hoping that in the not-too-distant future, oil and gas companies will not only see AUVs as more competitive than ROVs, but also as a required asset for life-of-field operations. “Field operators have very high standards,” John Jacobson, senior program man-ager at Lockheed Martin, said. “The infrastructure is extreme-ly expensive and it is carrying product. So as we work toward these capabilities, we have to keep in mind the standards that operators will put upon the AUV in terms of performance, reli-ability, and navigation.”

Deepwater AUVLockheed Martin is applying AUV technology that it originally developed for military applications to now meet the needs of the deepwater oil and gas market. The company’s latest devel-opment is a deepwater AUV called the Marlin Mk3, which is

Detailed 3D-rendered models of subsea structures, used for decommissioning surveys and post-hurricane inspections, can be completed in less than an hour using an AUV. Image courtesy of Lockheed Martin.

The Sabertooth AUV is capable of remaining inside a protective docking station for more than 6 months at a time without maintenance. Image courtesy of Saab Seaeye.


ROBOTIC SUBMARINES


capable of operating at depths of up to 13,100 ft (4000 m) for up to 33 hours on a single battery charge. Based on a field-tested model engineered for shallower depths, the deepwater Marlin is in its late-stage design phase. The future vision of the program is to develop a highly functional resident system that operators can rely upon for inspection and light intervention work.

To guide its way through the dark depths, the Marlin employs several navigation systems, including an inertial mea-surement unit coupled with Doppler sonar. “We enhance that using other features, including terrain- and feature-based nav-igation,” Dan McLeod, deputy director of offshore systems and sensors at Lockheed Martin, said. The Marlin’s software enables it to identify not only seabed hazards, such as boulders or steep inclines, but also specific equipment, such as mani-folds and subsea trees. Once georegistered, the AUV will never forget the location of the equipment, or the features of the surrounding terrain.

In order to withstand the pressures of the ultradeep, the latest Marlin will have stronger pressure vessels to protect its electronic and mechanical systems. To achieve buoyancy, the deepwater AUV will use a denser form of the synthetic flotation material used in the earlier models. As a result, the 17-ft-long deepwater Marlin is more than twice the length and weight of the first generation AUV designed to operate at a maximum depth of only 1,000 ft (304 m). “By necessity,” McLeod said, “deeper vehicles get larger and heavier.”

Another key difference between the earlier version and the deepwater model is that it will be equipped with interchange-able payload modules. Lockheed Martin believes that a modu-lar design provides the ability to tailor the AUV with regard to how much endurance vs. sensor capacity each mission calls for. “On one mission, you might need more battery and less work

payload, and on another mission, you may need less battery and more payload,” Jacobson said. “And we’re anticipating that you are going to want to change things out, that you are going to want to take on the latest sensors.”

Change DetectionAmong the modular systems that Lockheed Martin is planning on equipping the Marlin with is a 3D laser scanner. Current 3D imaging is done using sonar; however, even the latest sonar technology is limited by the physics of sound and only capable of resolutions with about 5 cm of detail. Using a laser, “you are seeing 5-mm sorts of resolution, so it is about an order of mag-nitude improved,” Jacobson said. With this level of precision, the AUV is capable of measuring the exact dimensions of subsea equipment, comparing the measurement data with a baseline 3D model stored in its internal memory, and then detecting any changes, or damage, between the two.

Over time, the AUV builds up an inspection inventory that it will use to detect subtle changes that may go unnoticed using conventional inspection technology. “Today, ROV companies pay operators to sit and stare at screens for hours and hours on end,” Jacobson said. “That is a lot of manpower and those people get tired, and when people get tired, they miss things.” The AUV, he added, does not get tired, nor does it require a crew change.

While carrying out an autonomous inspection, the Marlin will use its high-definition video and still cameras, along with sonar or laser sensors, to record images of the systems and structures it is checking on. “What it is doing at the same time is detecting changes and flagging the operator,” Jacobson said. Preset commands tell the AUV that when it detects a change, however small or large, to investigate the problem further by getting closer to take photos, video, and detailed scans from

The Marlin Mk3 uses a suite of navigation and mapping systems to simultaneously pinpoint its location while mapping the surrounding area with great detail. Image courtesy of Lockheed Martin.



multiple angles. “There might be 2 days of video, but does the operator have to watch 2 days of video to be cued up to what the significant issues are? Not necessarily,” he said. With the auto-matic flagging system, inspection engineers can skip over the innocuous and fast forward to where the problems have already been identified by the AUV’s software.

In 2011, Lockheed Martin and Chevron completed a series of demonstrations in the Gulf of Mexico of the shallow-water Marlin’s change detection software. Then in 2012, Chevron field-tested Lockheed Martin’s real-time 3D georeference mod-el-building software, again with the shallow-water Marlin, to inspect 14 offshore sites in the Gulf of Mexico, including 11 standing structures. Over the course of the 2-week opera-tion, the AUV was in the water for a total of 62 hr and covered nearly 76 miles in depths up to 125 ft (38 m). It took less than a day to download the data and generate 3D models of each of the structures.

The Marlin’s change detection technology is also designed to monitor flowlines and pipelines that may have moved or become suspended across subsea berms. When production is starting up or shutting down, the temperature in the pipeline changes quickly. This can cause a thermal expansion or con-traction of the pipe’s materials, which can then force entire sec-tions to move out of place. This phenomenon, known as walk-ing, can contribute to fatigue and serious failures at tiebacks and riser hookups.

Light Intervention Like the Marlin, the underlying technology inside Saab Seaeye’s Sabertooth AUV is military born, originally conceived for hunt-ing explosive mines and designed to carry a payload of sensors including cameras and sonar. The technology inside the Saber-tooth was field proven, not in the deep waters of the US Gulf of Mexico or offshore Brazil, but high in the Rocky Mountains of

Colorado. In 2011, Hibbard Inshore, an ROV company specializ-ing in underwater industrial inspections, deployed the military version of the AUV in a 9-mile (15 km) water transportation tun-nel used to supply water to a hydroelectric dam. Using the AUV, the customer incurred zero loss in revenue. “Traditionally, this operation was very expensive and difficult, because you had to drain the tunnels and that costs a fortune,” Jan Siesjö, chief engineer at Saab Seaeye, said.

The Sabertooth has an excursion range of about 25 miles (40 km) and can be depth rated up to 9,842 ft (3000 m) for deepwater operations. Subsea equipment maker Aker Solutions has partnered with Saab to fully integrate the technology with its subsea production systems. Aker has also completed design studies for a subsea control module for the Sabertooth’s dock-ing station at which the AUV can power up and upload data in between missions.

By geotagging each aspect of the inspection and using feature-based navigation, AUVs such as the Marlin are able to detect changes much quicker and more dependably than conventional visual inspections that rely on humans. Image courtesy of Lockheed Martin.

MARLIN MK3-V1

Payload CapacityWet Weight—350 lb (160 kg)Volume—20 ft3 (0.57 m3)Power—4 kw peak

Endurance 33 hr (mission dependent)

Speed 0–5 kn

Range 100 nmi (185 km)

Depth Rating 13,124 ft (4,000 m)

LengthWidthHeight

17 ft (5.2 m)3 ft (0.9 m)4 ft (1.4 m)

Weight in Air 5,500 lb (2,500 kg)


ROBOTIC SUBMARINES


One of the misconceptions that engineers are trying to put to rest is that AUVs are unequipped to operate the controls on a subsea system, which involves using a manipulator arm or a torque tool to turn various sockets and valves. The Sabertooth is among the first commercially available resident AUVs capa-ble of these operations, termed light intervention. “People think they need hydraulic power,” Siesjö said regarding an AUV’s abil-ity to operate valves. “You can actually do it just as well with a small electrical tool, but you need a vehicle with a high degree of maneuverability so you can be oriented to where you want to put the tool.”

With this need in mind, the Sabertooth was designed to be very nimble, so that it can swim inside manifolds and under-neath equipment for close inspection. Its thrusters and buoyant

design allow it to pivot 360° on its axis and maintain its posi-tion at any angle, which means it can work facing straight up or straight down. Although the vehicle was designed to oper-ate independent of human controllers, it is a hybrid system. If the vehicle is connected using a tether or radio link, it may be manually operated. When used as a resident system, the Saber-tooth recharges itself in a protective docking station where the AUV can begin uploading sensor data, video, and sampling data to onshore using an Ethernet connection. Using a hydrophone, the Sabertooth is even able to listen for oil or gas leaks. If a leak is detected, the AUV can take up to four environmental samples and send the resulting analytic data back to the operator.

Several operating companies have shown interest in the Sabertooth, including Chevron, which sponsored a project in late 2012 to demonstrate the AUV’s data harvesting capabilities. During the tests, the AUV retrieved data wirelessly from a sub-sea sensor and then physically connected to the sensor to trans-fer data through a hard link.

The test determined the useful range of an aftermar-ket communication system and was carried out under both lake and open sea conditions. In another study, completed for Exxon Mobil, the AUV’s reliability as a backup solution should an emergency occur in a remote subsea area, such as the Arctic where most support vessels are unsuited to operate during the winter months. “If you are in the Arctic and it is frozen all over,” Siesjö said, “when something happens, you need to be able to go out to find out what it was and possibly turn a valve to shut something down.” In Arctic scenarios, AUVs such as the Saber-tooth could serve as early warning systems for the particular-ly real threat of ice scouring and could alert operators quickly about oil or gas leaks, or even shut in production. If the AUV is unequipped to remedy the problem right away, “you will always be in a situation where you will gain time, whether it be hours or days if you have something already there in the field that can go out and investigate for you,” Siesjö said.

Communications Last year, the Sabertooth was tested by Eni Norway in the fjords just off Hammerfest, Norway, located more than 300

Saab Seaeye’s Sabertooth AUV comes in two models: single hull and double hull (which has twice the battery capacity of singe hull). Image courtesy of Saab Seaeye.

A computer illustration shows the Sabertooth AUV carrying out light maintenance, inspection, and intervention work inside a subsea manifold. Image courtesy of Saab Seaeye.

SABERTOOTH AUV (DOUBLE HULL)

Endurance >14 hr (mission dependent)

Battery Capacity 20 kW-hr

Speed 0-5 kn

Range 100 nmi (185 km)

Depth Rating 9,842 ft (3000 m)

LengthWidthHeight

12 ft (3.7 m)2.1 ft (0.66 m)1.4 ft (0.45 m)

Launch Weight 2,314 lb (1050 kg)



miles north of the Arctic Circle. During the test, the AUV used beams of blue photons to communicate with a seabed sen-sor at a distance of almost 200 ft (60 m). Called BlueComm, the technology was developed by Woods Hole Oceanograph-ic Institution, the largest oceanographic research facility in the US. The institution partnered with Sonardyne, a subsea communications systems maker, to bring the system to the offshore industry.

Wireless optical systems, such as BlueComm, will be used to establish an infield communication network between various subsea production systems, vessels, and AUVs. Blue-Comm transmitting and receiving units installed on an AUV and on subsea sensors can share data at a rate of more than 20 MB/s across almost 500 ft (150 m) of seawater. This broad-band data stream allows operators to receive high-definition video in real time when the system is integrated with a sea-to- shore link.

The technology is an evolutionary leap for subsea com-munications that for more than 40 years has relied on acous-tic sound waves to transmit much smaller bits of data. “With acoustics, we can transmit about 6 kB of data, which is pretty fast,” Ralph Gall, technical sales manager at Sonardyne, said. “Six kB is a lot, but 20 MB is massive and gives you the abil-ity to send video over 150 m, which is a big deal in the subsea.”

The technology also applies to data harvesting and signifi-cantly reduces the time it takes to upload data compared with current technology. With an optical communication system, sensors and AUVs that have been logging data for long periods of time, but are not connected to a subsea Internet, can upload gigabytes of information in minutes to a visiting surface vessel equipped with a lower bandwidth commutation system. By low-ering a communications device known as a depressor equipped with a receiver unit on its end, vessels and crews would not be required to spend valuable time at sea physically recovering the AUV or sensors, downloading the data, and then redeploying each system.

Saab Seaye is also testing other ways of communicating, such as electromagnetic antennas and short communications tethers. Electromagnetic communication has been used by var-ious branches of the military in both underwater and under-ground scenarios. Using this technology, the antenna can be built into the AUV and allow for high bandwidth communica-tion rates as high as 10 MB/s when the vehicle is in close prox-imity to a docking station. Other companies are also working to solve problems that will expand the applications of AUVs even further, such as how to communicate through layers of ice and improve the redundancy of subsea communication networks to make the vehicles more efficient and safe. JPT

Tested offshore Norway, a Sabertooth AUV used a BlueComm communications system to receive data at a rate of 6 million bits per second from a BlueComm transmitter (inset) across a distance of 200 ft (60 m). Photos Courtesy of Saab Seaeye and Sonardyne.


THE POWER OF COLLABORATION


The inaugural SPE Kuwait Oil and Gas Show and Conference (KOGS), held 7–10 October 2013 in Kuwait, attracted more than 3,000 delegates representing major oil and gas companies from all over the world.

The event, under the patronage of Kuwait’s Prime Minister Sheikh Jaber Mubarak Al-Hamad Al-Sabah, carried the theme “The Power of Collaboration... People and Technology in the Oil and Gas Industry,”

Hosnia Hashim, KOGS conference program chairperson and vice president

of operations at Kuwait Foreign Petro-leum Exploration Company (KUFPEC), said that the gathering allowed explo-ration and production professionals to network with colleagues from around the world and celebrate key successes in the industry. “For the first time ever in Kuwait,” she said, “we launched a techni-cal event with outstanding participation, having received more than 520 papers, from 104 organizations and 69 universi-ties, from 37 countries.”

In his opening remarks at the Con-ference Opening Ceremony, Kuwait Dep-

uty Premier and Minister of Oil Mustafa Al-Shimali, reiterated Kuwait’s unflinch-ing commitment, in its capacity as a main oil producer, to ensuring regular supplies to world markets. “This confer-ence is timely and logical, as the Kuwait oil sector is undertaking plans to ensure that it meets and fulfills its international role as a reliable supplier. We have allo-cated billions of US dollars to reach pro-duction capacity of 4 million BOPD by 2020. An international exchange of tech-nology and experience is critical to real-izing these plans,” Al-Shamali said.

Kuwait Unveils Upstream Opportunities Abdelghani Henni, Middle East Writer

Ali Rashed Al-Jarwan, CEO of Abu Dhabi Marine Operating Company (ADMA-OPCO), (left) and Kuwaiti Deputy Premier and Minister of Oil, Mustafa Al-Shimali, during the inaugural SPE Kuwait Oil and Gas Show and Conference.

KuwaitJan.indd 56 12/17/13 3:24 PM


At the Executive Plenary Session, Nizar Al-Adsani, chief executive offi-cer of Kuwait Petroleum Corporation (KPC), aentation titled “Kuwait Experi-ence: The Power of Collaboration, Peo-ple, and Technology in the Oil and Gas Industry,” that the challenges ahead for his country are great. “The emergence for new competitors, changes in supply and demand dynamics, social and envi-ronmental pressures, and demographic shifts, are transforming and reshaping our industry,” he said.

Al-Adsani said that technology has been the driving force behind the industry’s continued ability to deliver increased oil and gas production safe-ly, efficiently, and in an environmen-tally friendly manner, adding that he believes that the excellence required is only provided through the strength of human resources.

The CEO said that his company is proceeding with its ambitious plans to enhance KPC’s role in the international oil industry and to be more effective in supply security for the world’s energy, adding that KPC wants to focus on the upstream. “Achieving our crude oil pro-duction growth target of nearly 1 mil-lion BOPD by 2020, and maintaining it through 2030, depends on the success-ful implementation of advanced technol-ogy in both improved and enhanced oil recovery,” he said.

Kuwait aims to spend USD 100 bil-lion over the next 5 years on development projects, with 60% spent on upstream project expansion inside and outside of Kuwait. “This is in addition to escalat-ing operating costs as our fields mature. These great challenges can’t be met and overcome by ourselves,” Al-Adsani noted. “It is our strategy to invest to maintain excess capacity, which has proved so far to be a correct strategy.”

Moreover, the additional produc-tion capacity will come from geologically complex reservoirs, which require high-ly skilled people. “The skills required to develop such complex and difficult res-ervoirs and achieve such a production capacity are not sufficient in terms of

skills, or expertise, or know-how. We def-initely need the assistance of the differ-ent IOCs to work with us, in an acceptable form of win-to-win basis, to achieve all of these strategic targets,” Al-Adsani added.

Speaking about relationships with IOCs, the CEO of KPC said that these partnerships should fulfill overall Kuwait strategic interests and concerns. “In these relationships, we focus on several issues such as the transfer of technolo-gy, promoting the skills of our nationals in various disciplines, bringing in man-agement processes, and leveraging with them for maximum benefit. We are fully aware of the need to partner with IOCs but also we are very careful about ensur-

ing an effective future role of IOCs in the Kuwait oil industry that will eventually add value in our understanding and per-ception,” he said.

Despite the collapse of the USD 17 billion joint venture between Kuwait’s Petrochemical Industries Company (PIC) and the US Dow Chemical, where Dow subsequently sued PIC and was awarded more than USD 2 billion in damages by an international court in 2012, Kuwait will continue to explore and develop partner-ships with international oil companies on many industry fronts.

Al-Adsani said that the key for mak-ing the industry more efficient is, with-out doubt, technological advancement.

Cyber Security Thoughts

John Fridye, cyber security engineer at Ventyx, an ABB Company, says multi-layer systems are the best solution to counter cyber attacks.

As a cyber security engineer, what are your main duties within Ventyx?Ventyx offers enterprise software solutions for energy, mining, and other industries. Within Ventyx, I am focused on network control products, which include energy management and SCADA control systems. We have a broad focus on network control because it is critical for companies we deal with.

Outside of network control, ABB and Ventyx have a wider cyber security presence, where ABB has a cyber security council made up of members of different product lines. Ventyx is in charge of the power systems group, but there are people from all different groups like robotics, automation, and many other groups.

As an engineer specializing in cyber security, what are the challenges facing developers of cyber security solutions or technology?The challenge is to define a process, which means defining your design methodology, which we call a threat-modeling analysis. It aims mainly at looking for what could be avenues of attack at your product line. After that, the threat model analysis looks at what security controls you design that block those avenues of attack, and then you go through the test phase to ensure that these security controls are indeed effective against particular threats to your products, and then you can implement the product and deliver it to customers. It is an ongoing process.

Are there any specific security control systems that help you build the cyber security system? There are many types of security control and many of them are well defined; in addition, there are many defense mechanisms that can be used and one of them is called defense in depth. If you penetrate one security control there is another one behind it, and we call that the onion model, because you have to pile through the layers to get down to the core you want to attack. So, if you have that defense in depth, that is a key defense of your critical systems.


THE POWER OF COLLABORATION


“Technology is vital across the energy landscape and in the field of clean energy production in order to serve and preserve the environment. The oil industry has a long history of innovation to generate new sources of supply,” he said. “There is no country in the world that can insu-late itself from changes in the oil market, whether positive or negative.”

Hashem Hashem, CEO of Kuwait Oil Company (KOC) and chairperson of the KOGS Executive Committee, stated that his company is contributing to the country’s socioeconomic development and looks forward to the future through increasing oil output, meeting compa-ny development requisites while helping maintain the stability of world markets.

Khaled Al-Buraik, vice president for petroleum engineering and development at Saudi Aramco, said in his Plenary Ses-sion presentation that technology, peo-ple, and collaboration work together in the quest for business excellence. Tech-nology is the cornerstone of what oil and gas companies do, and major players

including Saudi Aramco are transform-ing into technology developers. “Our goals are for breakthrough, disruptive technologies,” Al-Buraik said.

As such, the goals are very long term and carefully calibrated to objec-tives. This research stresses fundamental science. It also calls for synergy among the sciences and other disciplines of Saudi Aramco’s business. “We are break-ing down organizational barriers in pur-suit of technology breakthroughs.”

Development of people is also cru-cial for oil and gas companies, particu-larly a commitment to lifelong learning, he said. Al-Buraik said that Saudi Aramco has a large program to cultivate science and engineering skills among high school students in Saudi Arabia. The compa-ny recruits directly from high schools, including apprentices for vocational careers and students whom it sponsors for university education and professional employment. “We send our professionals on to master’s and doctoral programs,” he said. “In-house programs such as the

new Upstream Professional Develop-ment Center are game-changers for on-boarding much-needed talent. All told, the company’s training and development budget is among the largest in the world.”

Collaboration is also key to the pros-perity of the industry, not only internal-ly among disciplines, but also external-ly with other institutions. “We operate numerous other joint ventures in the kingdom and abroad. Adjacent to our headquarters and King Fahd University of Petroleum and Minerals is the extra-ordinary new Dhahran Techno- Valley, a science park with a collaborative atmo-sphere housing research centers of GE, Honeywell, Baker Hughes, and many more,” Al-Buraik said.

Companywide, Saudi Aramco plans to increase research spending fivefold. It will also triple its manpower in sci-ence and technology. “Most—about 80%—of this growth will be in Dhah-ran, but we also are opening upstream and downstream satellite research cen-ters around the globe in partnership with the automotive industry and leading academic institutions.”

Patrick Pouyanne, president of refining and chemicals at Total, said the relationship between national oil com-panies and international oil companies is that they share a common objective, which is bringing energy to people. “In this type of collaboration, IOCs propose technology, project management, and financing, as well as acceptability to the market,” he said. “As an IOC, we always aim to bring value to host countries for win-win partnerships.”

As an IOC, Total works on answer-ing host countries’ expectations in terms of transferring know-how, accompany- ing NOCs in their ambitions beyond their boundaries.

Delegates attending the KOGS event agreed that collaboration is key to the industry’s success amid the growing chal-lenges facing the oil and gas sector. Over-all, the event offered the opportunity to network with industry peers, and also to learn more about oil and gas investment opportunities in Kuwait. JPT

Hashem Hashem, CEO of Kuwait Oil Company (KOC).


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TALENT & TECHNOLOGY


One could compile an extensive bibli-ography written about the “big crew change” over the past several years. The short story is that although the human resource “emergency” that the oil and gas industry has decried during the past decade has slowed, it has not dis-appeared but merely been delayed. The industry continues to face a shortage of skilled workers in the 10 to 20 years of experience category, which is affecting the staffing of midlevel management jobs and, subsequently, senior level manage-ment positions.

Estimates show a net outflow of 5,500 people at the petrotechnical pro-fessional level in the oil and gas indus-try. The immediate ramifications of this decline in experienced human capital will be heavy recruitment of staff from competitors, which will continue to drive salaries higher. With the cost of a barrel of both West Texas Intermedi-ate and Brent crude still around USD 100/bbl, projects will continue to be economic, thus increasing the need for experienced hires. But the 5,500-person net outflow says that companies may be unable to properly staff these projects, which could result in delays or the pos-sibility of less experienced staff running them, with potentially risky outcomes in safety and downtime. All of these fac-tors increase costs for oil producers.

However, quantity is not the only risk; quality (i.e., real-world experience) is also a factor. Could the overpromotion of less experienced professionals put projects at risk for safety and downtime problems? Many projects are only as good as the individual managing them. Project leaders must focus on the prop-er balance of the quality of work, tim-

ing, supply of equipment and people, safety, and the bottom-line profitability for all parties to be satisfied. These are all strong management and leadership skills that can be found in other indus-tries, which have devised and imple-mented best practices. If the proper general manager of a project is selected, he will surround himself with techni-cal experts, thus allowing a focus on the core skills and abilities that he brings to the company, rather than strictly the technical knowledge of the project. This opens up the industry to looking at mid-career leaders in the heavy industrial and civil construction industry, mining industry, or even the military.

Effect on Senior ManagementSo what do these midlevel staffing issues mean in the long term? For starters, the industry will have a smaller pool of talent to choose from when looking at senior management succession planning. There could also be the real possibility that there are no qualified employees from which to choose within a company. This may cause the company to look outside for talent, which could lead to higher wages, higher turnover due to compet-itors poaching from one another, and increasing one-time costs attributable to new hires.

If we do not fill the gap, we run the risk of perpetuating the problem from which the industry currently suffers. When those at the top retire, the pool of talent to choose from within the industry will be considerably younger. When this younger crop of talent is appointed to top positions, they will naturally remain in those roles for a longer period of time, making those behind them wait longer

to rise to executive roles. For some high-potential midlevel management individ-uals to reach the top, they may consider leaving the industry to see their career aspirations come to fruition.

A Balanced ApproachTo solve the skills gap cycle, a four-pronged approach is necessary. The approach incorporates short- and long-term strategies, thinking outside the norm when making hiring decisions, and implementing organizational develop-ment strategies that put the onus on both the company and employees.

Be open to hiring managers, both mid and senior levels, from outside the industry. By opening up manage-rial roles to those from other industries, the oil and gas industry can “import” best practices into the energy indus-try that it may not have knowledge of or experience with, as well as help fill some of the gap that exists in midca-reer employees. Consider an individual who currently works for a company that provides field development and produc-tion contracting services to the energy industry, and is particularly technology focused. This individual worked in the medical industry as an engineer leading groups of other engineers and provid-ing installation and operations support services to clients for almost a decade. He then moved on to provide engineer-ing and construction project manage-ment services to the construction and infrastructure industries. This large and technically complex project manage-ment background has proven invalu-able to the individual’s current employ-er and has given the company an edge

Taking a Balanced Approach to the Technical Skills GapJoy Brown Kirst, Managing Partner, Park Brown International

TalentTechJan.indd 60 12/17/13 3:01 PM


over some of its competitors with new approaches to old problems.

An example of an executive’s appointment is exemplified by the following:

Arthur Soucy is president for Europe, Africa, and Russian Caspian at Baker Hughes, and formerly was presi-dent of global products and services at the company. Before that, he was the company’s vice president of supply chain, responsible for sales and operations planning, manufacturing, purchasing, transportation and logistics, and qual-ity. Before joining Baker Hughes, he was vice president of global supply chain at Pratt & Whitney, a United Technology company. Soucy held a variety of man-agement positions at Pratt & Whitney. He also spent a decade working at Ham-ilton Standard, serving in various man-ufacturing, engineering, and product development management roles. Soucy has an MBA degree from the Massachu-setts Institute of Technology with a con-centration in global innovation and inter-national business and a bachelor’s degree in international business from Lesley University in Massachusetts. Soucy’s story proves that someone who is not an engineer by academic background and does not have energy industry experi-ence is capable of becoming an executive at one of the top oilfield service compa-nies in the world.

Use organizational and talent devel-opment as a strategic and competitive tool. Strategic human resources is the management of human resources aligned to the organization’s future direction, focusing on longer-term human capital issues and macro concerns about struc-ture, quality, culture, values, and match-ing resources to the future needs of the organization.

The Economist’s Talent Manage-ment Summit held in London in 2013 rec-ognized that “talent is no longer an issue confined to the HR department, but is rising to the top of the agenda for senior executives across the board” (www. economistconferences.co.uk/event/

talent-management-summit-2013/7232). Companies in the energy sector must facilitate the involvement of human resources at strategic decision-making levels to ensure that a culture is creat-ed that sends a clear message to current and future employees that leadership tal-ent is highly valued within the organiza-tion. This can be supported by leader-ship development programs tailored to meet both the employee’s specific devel-opment needs and the company’s profile for future leaders.

To facilitate the desired effect, human resources professionals must be seen as true strategic partners. Senior executives seeking a competitive advan-tage by attracting, developing, and retaining more than their fair share of the industry leadership talent must seek and hire the best strategic human resources practitioners regardless of sec-tor background.

For entry-level to mildly experienced hires, consider individuals with com-plementary skill sets from other indus-tries. There are a number of intelligent first-year college students who do not initially set out to become engineers or scientists. There is a good chance that a person with an undergraduate degree in mathematics or economics knows enough about crunching numbers and analysis that they could be taught how to apply those skills to the energy industry. Every company out there is courting the “fill-in-the-blank” engineers, and not everyone is going to get them. Why not consider look-ing at strong analytical types and putting them into a rotational development pro-gram in your company to find where they best fit? Also, companies should commit to leadership or leadership potential as a desirable skill when recruiting these indi-viduals. Selling upside career opportunity to new graduates may just net the orga-nization individuals who may have cho-sen another offer otherwise. In addition, using these criteria when recruiting less experienced employees may aid organi-zations in their quest for succession plan-ning in their ranks.

This is true for slightly more experi-enced people as well. Most military per-sonnel enter the energy industry without engineering degrees. Others have gone from civil engineering roles designing roads for government projects to sub-sea design engineering, and have done quite well for themselves and the compa-nies they joined. Many times in an expe-rienced hire, one needs to look more closely at the creativity and leadership capability of the candidates as opposed to checking the boxes of preferred hard skills and experiences.

Consider long-term options to increase the pipeline of talent into the industry. Looking for talent development at the collegiate level is not enough. While it can be helpful to recruiting efforts to pro-vide internships, scholarships, and work-study options to undergraduate students, more needs to be done to entice students to become science, technology, engineer-ing, and math majors. Companies should be looking at increasing awareness of this type of education at the middle and high school levels or potential engineers and scientists may be lost to another major in college.

ConclusionWhile these suggestions may be nontra-ditional and not easy to implement, com-panies that desire to get ahead in the war for talent could use them to have an edge over their competitors. The strategy will not produce immediate effects today or tomorrow, but will be advantageous in the long term. JPT

Joy Brown Kirst is a managing partner with Park Brown International. After positions with Western Atlas International and Heidrick & Struggles, she became vice president at an executive search firm overseeing energy industry searches in North and South America, Europe, and the Asia Pacific. She holds a degree in Russian and East European Studies and an MBA from Rice University.

TalentTechJan.indd 61 12/17/13 3:03 PM


Omer Gurpinar, SPE, is the technical director of enhanced oil recovery (EOR) for Schlumberger. He leads Schlumberger

in development of technologies and services to help improve recovery factors in oil fields. Gurpinar has more than 35 years of industry experience in various aspects of numerical reservoir modeling, with specific focus on naturally fractured reservoirs, reservoir optimization, and EOR. He has contributed to recovery optimization for numerous oil and gas fields globally. Since joining Schlumberger in 1998, Gurpinar has served as the vice president and technical director in various segments and has played a key role in building Schlumberger’s exploration and production consulting organization. He holds BS and MS degrees in petroleum engineering and holds several industry patents on reservoir and field optimization and EOR. Gurpinar is a member of the JPT Editorial Committee.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 162701 Geomechanics Considerations in Enhanced Oil Recovery by Tadesse Weldu Teklu, Colorado School of Mines, et al.

SPE 166597 BP North Sea Miscible Gas Injection Projects Review by Pinggang Zhang, BP, et al.

IPTC 17157 The Development of a Workflow To Improve Predictive Capability of Low-Salinity Response by B.M.J.M. Suijkerbuijk, Shell, et al.

SPE 166075 The Upscaling of Discrete Fracture Models for Faster, Coarse-Scale Simulations of IOR and EOR Processes for Fractured Reservoirs by Mun-Hong Hui, Chevron, et al.

This is the most exciting time for enhanced oil recovery (EOR) in recent memory. At last, almost everyone is talking about increasing recovery factors, and improved oil recovery (IOR) and EOR are being considered natural components of reservoir man-agement. Furthermore, many traditional philosophies are being openly challenged. EOR planning is happening as part of field-development plans. Proven technologies are being adapted in new, smart ways, and new technologies are constantly evolving from research to commercial applications, making EOR projects more economical. These new directions are the result of the following factors:

◗◗ Most fields, including the giant ones, are maturing, and producing liquid hydrocarbons is becoming more difficult in all types of reservoirs (conventional and unconventional).

◗◗ Leaving approximately 70% of the in-place reserves unrecovered has been challenged.

◗◗ There have been developments on many fronts (e.g., advanced reservoir characterization, multiphase-flow physics, smart-well and intelligent completions, recovery research, monitoring and control technologies, EOR chemicals, EOR pilot concepts, and observation-well concepts); the collective effect of all of those is going to make new EOR projects more successful.

◗◗ Increasing recovery factors has been considered a fully integrated multidomain activity (from pore space to separator and everything in between).

◗◗ Severe production decline in tight/light (unconventional) reservoirs is making the industry think about recovery challenges.

◗◗ EOR has been considered during field-development planning in most recent offshore oil developments.

We lived through the most active period of EOR—between the mid-1970s and the mid-1980s—and learned about recovery fundamentals then. However, if we look back at that era carefully, most of the wells were single and vertical; reservoir characteriza-tion was very elementary, with no digital geological modeling capabilities; and there were no concepts such as monitoring systems or intelligent completions. All of those factors created a significant gap between what was planned in the EOR laboratory and what was achieved in field application. Other than those implemented in extreme-ly viscous oils (heavy-oil EOR operations), projects recovered far less than planned. Overall, such recovery gave a stigma to EOR as inherently difficult and expensive. Most of the factors that made EOR difficult and expensive are gone today. That is why we will see more fields using EOR operations in upcoming years.

Broadening the scope of recovery challenge to all domains will make realizations of new reserves more likely, but this change will bring additional challenges.

TECHNOLOGY

eor performance and modeling

1EORFocusJan.indd 62 12/12/13 11:09 AM


Foam simulation brings various numerical challenges. Some of

these problems are largely cosmetic, creating, for instance, fluctuating fluxes and pressure gradient but no significant effect on final recovery. Others severely influence the whole progress of the flood. This paper discusses the origin of the challenges, how to recognize them, how they can be mitigated, and whether they arise from a correct representation of foam physics or are the unintended result of attempts to solve other numerical problems.

IntroductionInjected gas [carbon dioxide (CO2), hy-drocarbon gas, nitrogen, or steam] can be very effective at displacing oil in enhanced-oil-recovery (EOR) processes, but ultimate recovery suffers from poor sweep efficiency. Poor sweep efficiency arises from reservoir heterogeneity, vis-cous instability, and gravity override of gas. Foam can address all three causes of poor sweep efficiency. Foam is a dis-persion of gas separated by water films called lamellae that separate the gas into bubbles; the lamellae are stabilized by surfactant. Thus, foam requires the pres-ence of gas, water, and surfactant.

Two fundamental approaches exist for representing the effect of foam on gas mobility. Population-balance mod-els introduce lamella density (number of lamellae per unit volume of gas phase) as a separate variable and perform a balance on lamellae at each location in the formation, along with material bal-

ances on water, gas, surfactant, and oil. Thus, an additional partial-differential equation must be solved at each location and timestep, along with those for satu-rations of the phases. The model then represents gas mobility as a function of lamella density and other factors.

Local-equilibrium (LE) models as-sume that the processes of lamella cre-ation and destruction are always and everywhere at local steady state. It is possible to adapt a population-balance model to LE by setting the expressions for lamella creation and destruction equal to each other. Most LE models, however, represent the effect of bubble size implicitly in relations for gas mo-bility as a function of water and oil satu-rations, surfactant concentration in the aqueous phase, and other factors.

Foam can be injected in at least four ways:

1. In coinjection, gas and aqueous surfactant solution are injected simultaneously from a single well. Foam forms in the surface facilities where the fluids meet, in the tubing, or shortly after the fluids enter the formation.

2. In surfactant-alternating-gas (SAG) injection, gas and surfactant solution are injected in separate slugs from a single well. Foam forms in the formation where gas meets previously injected surfactant solution or when surfactant solution meets previously injected gas.

3. It is possible to dissolve some surfactants directly into

supercritical CO2. Then, there is no need to inject aqueous surfactant solution; injected CO2 with dissolved surfactant forms foam as it meets water in the formation.

4. Surfactant solution and gas can be injected simultaneously from different sections of a vertical well (gas injected below the surfactant solution) or from parallel horizontal wells (gas injected from the lower well). As far as we know, this approach has not been tested with foam in the field.

Simulating each of these injection methods involves particular challenges.

Challenges to Foam SimulationEffect of Water Saturation. Gas, as the nonwetting phase, is at higher pressure than water in the geological formation; this difference is (gas/water) capillary pressure. Capillary pressure draws water out of lamellae; therefore, high capillary pressure is destructive to foam.

Fig. 1 shows the gas relative perme-ability function with a large reduction in gas mobility.

SAG Injection: Fluctuating In-jectivity During Gas Injection. Fig. 2 shows total relative mobility λrt with foam (the sum of water and gas mobili-ties) as a function of water saturation Sw for the model in Fig. 1. During gas injec-tion in an SAG process, there is a shock front at the leading edge of the gas bank from the initial state of the reservoir to a point of very low water fractional flow, where foam has partially collapsed. Thus, the water saturations that would have the greatest mobility reduction with foam are not experienced in the reservoir ex-cept within the shock front of negligi-ble width. In a finite-difference simula-tion, however, each gridblock at the foam

Foam Simulation Faces Several Numerical Challenges

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166232, “Numerical Challenges in Foam Simulation: A Review,” by W.R. Rossen, SPE, Delft University of Technology, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September–2 October. The paper has not been peer reviewed.

EOR166232.indd 63 12/12/13 1:21 PM


front passes through all those satura-tions and, thus, the mobility reduction at the foam front is overestimated. At least one gridblock at the leading edge of the foam bank has a mobility computed to be below that anywhere in the foam bank itself. As this gridblock passes through the minimum in mobility in Fig. 2, the ef-fect on overall injectivity can be large. In extreme cases, where the foam collapses completely behind this shock, this one gridblock can mask the problem and give diversion of gas flow in the simulation that would not occur in reality.

This problem reflects the finite- difference formulation of the foam dis-placement, not an inability of the simula-tor to solve the finite-difference equations.

SAG Injection: Calculating Injec-tivity. The gridblock with the injection well likewise must pass through the min-imum in mobility in Fig. 2. Injectivity is conventionally calculated by assum-ing a uniform saturation and mobility in the injection-well gridblock and using the Peaceman equation. Therefore, for a time, injectivity in a simulation of an SAG process is extremely poor. In real-ity, the near-well region crucial to injec-tivity rapidly dries out and injectivity is much greater than estimated in a finite- difference simulation.

Fine-Scale Capillary Effects. Be-cause foam is sensitive to water satura-tion and capillary pressure, capillary ef-fects on foam near abrupt transitions

in permeability can be significant. Simi-larly, in flow parallel to an abrupt layer boundary, capillary pressure can draw water from the higher-permeability layer and weaken or destroy foam in a narrow zone near the boundary. In both cases, the affected region is small in width but influences flow over a much larger scale. Accurate modeling of the effects with larger gridblocks remains a challenge.

Effect of Water Saturation: Miti-gation. The sensitivity of foam to cap-illary pressure and water saturation in-troduces two problems: Individual gridblocks experience mobilities and sat-urations not present in the displacement except within the shock (Fig. 2); also, abrupt changes in mobility in individual gridblocks introduce oscillations that are unsightly and may challenge the stability of the simulator. Reducing the magnitude of the gas-mobility reduction with foam reduces both problems, if a smaller value is justified by the data.

Similarly, the overall effect of the artificially low computed injectivity de-creases as the size of the injection-well gridblock is reduced. Also, the fraction of overall injection-well pressure dissipated in that gridblock decreases (though more slowly) as gridblock size is reduced.

Finally, gas compressibility reduc-es the effect of fluctuating mobility at the foam front on injection-well pres-sure, especially as the size of the foam bank increases.

Effect of Surfactant Concentration. The effect of surfactant concentra-tion on gas mobility in foam is non-linear, with most of the effect coming at low concentrations. In the absence of dispersion (physical and numerical), two surfactant concentrations primar-ily matter to a foam process: the ini-tial concentration in the reservoir (i.e., zero surfactant concentration) and the injected concentration. In the absence of significant physical dispersion, nu-merical dispersion rapidly spreads the surfactant front from its initial sharp profile over many gridblocks, though surfactant adsorption (if modeled with a Langmuir isotherm) helps to sharpen the front.

If the true effect of surfactant on foam mobility is combined with numeri-cal dispersion of the surfactant front, the foam bank is extended beyond where it should lie, toward the leading edge of the dispersed front, and the arrival of foam at any location is earlier and more gradual than it should be.

Effect of Surfactant Concentra-tion: Mitigation. As with water satu-ration, the less abrupt the rise in gas mobility with decreasing surfactant con-centration, the smaller the effects. In this case, the artifacts arise from an abrupt change not required to match data but as the unintended consequence of trying to mitigate another problem, the effect of dispersion of surfactant concentration.

Fig. 1—Water and gas relative permeability (kri) with and without foam and for one foam model.

Fig. 2—Total relative mobility λrt as a function of water saturation Sw for the model in Fig. 1. In an SAG process, there is a shock from the initial state ahead of the shock past the water saturations with lowest mobility. In a finite-difference simulation, each gridblock passes through all of the intermediate water saturations as the foam front enters the gridblock.

k ri

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, dim

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rt

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S , dimensionlessw

EOR166232.indd 64 12/12/13 1:21 PM


Refining the simulation grid reduces the magnitude of the effect.

Effect of Oil Saturation and Compo-sition. The effect of oil saturation and composition on foam is complex and not fully understood, and there are many outstanding questions concerning how to represent the effect of oil on foam. The effect of oil on foam is sometimes repre-sented as an abrupt change as a func-tion of oil saturation. This leads poten-tially to the same sort of complications observed with water saturation, as oil saturation in gridblocks at a foam front pass through oil saturations where foam properties change abruptly. The pres-ence of a third mobile phase introduc-es an additional, different complication: Composition paths on the phase diagram may attempt to travel along a bound-ary in which foam properties change

abruptly. Maintaining the correct course in such cases is extremely difficult.

Effect of Oil: Phase Names. Simu-lators define foam as an interaction be-tween aqueous surfactant solution and gas. In a first-contact or multiple-contact miscible displacement, the identity of the nonaqueous phase changes from “oil” to “gas” as the miscible front passes a given location, and there are only two phases present at any location: water and gas or water and oil. Therefore, by definition, there is no effect of oil on foam: If oil is present, there is no “gas” and, therefore, no foam; if gas is present, there is no “oil” to affect the foam. In fact, the effect of oil on foam in such a case is to abruptly cre-ate foam (if surfactant is present) when the simulator changes the name of the nonaqueous phase from “oil” to “gas.” If the miscible front is ahead of the sur-factant front, then this effect is unim-

portant; however, in injection of lower-quality foam—or in an SAG flood, where surfactant injection precedes gas injec-tion and the miscible front lags the sur-factant front, at least at first—this ef-fect would control the propagation rate of foam.

Effect of Oil: Displacement Front. In an immiscible (or partially miscible) displacement, if oil saturation ahead of the foam bank is great enough to kill foam, foam may still displace oil if oil drains out the gridblock at the lead-ing edge of the displacement front fast enough for foam to build. Whether this would occur in reality depends on the traveling wave at the displacement front, where oil is displaced as foam arrives. Whether this would happen in the simu-lation depends on how well the simula-tor, in a single gridblock, represents the traveling wave. JPT

www.aapg.org/gtw/2014/houston/index.cfm www.aapg.org/gtw/2014/houston/index.cfm

Come See What's New Are Shales Still Exciting?Fifth Annual AAPG-SPE Deepwater Reservoirs Geosciences Technology Workshop28-29 January 2014 • Houston, Texas Norris Conference Center – CityCentre

Determining reservoir connectivity, calculating pore pressure,

understanding the structural subtleties, identifying hazards, and

developing accurate images (including subsalt), are deeply affected by

new multi-disciplinary discoveries in science and technology. While

new discoveries in the Gulf of Mexico, West Africa, East Africa, Brazil,

and the Mediterranean grab headlines, what is going on behind the

scenes affects everyone who works in deepwater offshore.

Exciting developments in our understanding of deepwater structure

and reservoirs, along with new developments in technology, have

helped propel the industry to a new level.

Third Annual AAPG/STGS GTW: Eagle Ford + Adjacent Plays and ExtensionsFebruary 24-26, 2014 • San Antonio, TX

This workshop focuses on prospectivity and producibility, with an emphasis on the conditions and characteristics of successful wells, and the technologies and techniques used in achieving success.

The productive extent of the Eagle Ford has expanded, thanks to new information and understanding of the factors that make the formation producible in a particular prospect or location. The same is true of adjacent formations such as the Buda and the Austin Chalk, along with Cretaceous extensions of the Eagle Ford, which extend from the Eaglebine to the Tuscaloosa Marine Shale.

Topics:• Geophysics, regional geology, and Eagle Ford Extensions• Sweet spots, reservoir quality, and the Eagle Ford• Petrophysics• Geomechanical considerations• Drilling the “new” zones: Lessons learned and “Must-Know” facts• Completions: Hydraul ic fracturing, proppant select ion, understanding

reservoir behaviors• The right kind of frac: How can geologists help? What can engineers explain? • Decline curves: Seeking and finding answers

Geosciences Technology Workshops 2014

EOR166232.indd 65 12/17/13 9:13 AM


BP has shown, by use of its reduced-salinity (RS) water-

injection technology, that incremental increases in oil recovery can be achieved across length scales associated with coreflood experiments (inches), field-based single-well chemical-tracer tests (feet), and field trials (interwell distances). This paper discusses the process undertaken by the Clair Ridge project in getting RS enhanced oil recovery (EOR) adopted as a Day-1 secondary waterflood.

IntroductionClair Ridge Field Overview. Contain-ing more than 6 billion bbl of oil in place, Clair is the largest oil accumulation in the UK continental shelf, and it lies 142 miles north of the Scottish mainland and 35 miles west of the Shetland Islands in 132–155 m of water.

The Clair A platform is a lightweight-steel-jacket development that was de-signed to be economic across the range of expected reservoir outcomes. The main risk at startup was whether waterflood of the fractured reservoir would work.

More than 5 years of production data indicate that the reservoir produc-tion mechanism in Clair Phase 1 is work-ing. There is evidence of displacement of oil from the matrix by a combination of viscous sweep, gravity drainage, and im-bibition of water from the fracture net-work into the matrix.

Success at Clair Phase 1 has paved the way for a much larger Clair Phase 2

development. The next phase of develop-ment will target roughly twice the oil in place of Clair Phase 1 in an area that has generally shallower and thicker reser-voir, known as Clair Ridge. During devel-opment, various EOR schemes were stud-ied. Gasflooding of the reservoir would be hampered by adverse relative perme-ability factors. These can be improved by enriching the gas with heavier com-ponents such as propane and butane; however, there is not a large source of these materials in the basin. Modeling has shown that the open fractures are ex-pected to provide a shortcut between gas-injection and production wells. Alterna-tives such as CO2 flooding and polymer flooding were also considered and reject-ed. Clair is a waterflood reservoir, and recovery depends on sweeping the large areas of matrix rock between the conduc-tive fractures.

What Is RS EOR? RS EOR can be defined as waterflooding of a sandstone oil res-ervoir using water with total- dissolved-solids (TDS) content of less than 2,000–8,000 ppm. The RS-flood TDS threshold shows some variation across different reservoir/fluid systems, with consistent enhanced recovery below the lower end of the range and varied effect within the range.

Full-reservoir-condition RS EOR corefloods have been performed on many reservoir systems across the world. All tests have shown similar char-acteristics, with increased oil produc-tion at water breakthrough and a de-

crease in remaining-oil saturation at the end of the waterflood tests. RS EOR re-covers additional oil after both second-ary (RS water injection from Day 1) and tertiary (RS injection following higher-salinity-water injection) waterflood ap-plications. Figs. 1 and 2 show typical secondary and tertiary responses to RS EOR, respectively.

The mechanism for release of addi-tional oil has been inferred from labora-tory tests. Organic components in crude oil are attracted to surfaces through a mechanism explained by the Derjaguin-Landau-Verwey-Overbeek theory of col-loid stability. The mechanism by which polar organic species in the oil become attached to charged surfaces involves, in several cases, cation bridges. RS brines are able to break the organic-molecule at-traction to the surface by exchanging the divalent cation for a monovalent cation such as sodium.

Selection and Description of Mem-brane Technologies for RS-EOR Fa-cilities. Facilities studies considered numerous desalination technologies and identified the most suitable, prov-en technology for the desalination of seawater offshore to be membrane de-salination protected upstream by mem-brane prefiltration to minimize effects on weight and space.

Membrane desalination relies on ion rejection by reverse osmosis. The process requires application of pressure to the seawater feed to drive water molecules through semipermeable ion-rejection membranes, overcoming the osmotic po-tential of the seawater and generating RS permeate and more-concentrated reten-tate (or brine) streams. Upstream, mem-brane filtration provides the high lev-els of suspended-solids, organic- matter, and bacteria exclusion necessary to limit fouling and maintain operability of the desalination process. The filtration-

UK Field Benefits From Reduced-Salinity Enhanced-Oil-Recovery Implementation


This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 161750, “Low-Salinity Enhanced Oil Recovery, Laboratory to Day-1 Field Implementation—LoSal EOR Into the Clair Ridge Project,” by Enis Robbana, SPE, Todd Buikema, Chris Mair, SPE, Dale Williams, Dave Mercer, Kevin Webb, SPE, Aubrey Hewson, and Chris Reddick, SPE, BP, prepared for the 2012 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11–14 November. The paper has not been peer reviewed.

EOR161750.indd 66 12/12/13 1:26 PM


membrane efficiency is maintained by regular, frequent backwash cycles.

Robust Laboratory AnalysisRS Coreflood Testing. In support of de-ployment of RS EOR in Clair, a num-ber of corefloods were performed. These tests were conducted at full reservoir- temperature and -pressure conditions with live fluids.

Core Characterization and Selection. Intact core pieces were scanned routine-ly with computed tomography to aid se-lection of plugging points and to ensure minimal heterogeneity (especially frac-turing and lamination). The plug sam-ples were cleaned by miscible solvent and had their permeability and porosity measured by flow-through methods.

Acquisition of Initial Conditions. The samples were set to initial water satu-ration by the porous-plate method, and the samples were then loaded into a test rig and degassed by injection of refined laboratory oil. The samples were then saturated with live (i.e., gassed) recom-bined Clair oil. The samples were aged for 3 weeks, with weekly refreshes of the resident oil.

Coreflood Experimentation. For sec-ondary recovery, the samples were water flooded with RS brine in an unsteady-state mode at a low rate of approximately 4-cm3/h injection in the laboratory. During this test, oil produc-tion was recorded and saturation was monitored in situ. At the end of the test sequence, the RS brine was displaced

with a doped brine to obtain good in- situ saturation endpoint data. The bene-fit associated with RS EOR in the second-ary mode was then assessed by running a regular coreflood using connate brine on a sample cut from the same core piece and exhibiting properties that were as similar as possible.

Experimental Results. Plugs from the main field experienced significant bene-fits from secondary flooding across both of the permeabilities tested, with a shift of 5.5 saturation units and 7.9 satura-tion units in the two tests. These benefits were observed at residual oil saturation and as an increase in dry-oil production.

Subsurface-Process Evaluation EfficiencyHaving seen evidence of a material RS EOR oil response from special core analysis of the Clair rock/fluid system, it was recognized that an upscaled view of the expected Clair Ridge RS EOR incremental-oil-recovery profile would be required to justify the incremental capital expenditure associated with RS EOR facilities.

An initial sensitivity study covering RS EOR residual-oil uncertainty, capil-lary pressure uncertainty, and reservoir-description uncertainty confirmed that reservoir description had the largest ef-fect on RS-EOR incremental oil recov-ery at Clair Ridge. Although a full-field model (FFM) of the Clair Ridge existed, 2-day FFM run times and the wide range in underlying reservoir-description un-certainty combined to drive the project toward adoption of sector modeling to investigate and upscale Clair Ridge RS-EOR oil-recovery predictions.

Sector-Model Description. A range of 48 reservoir-description types were defined as plausible across the Clair Ridge structure by combining possible joint and subseismic fracture descrip-tions. RS-waterflooding performance across this range was evaluated using a single-porosity sector-model volume cut out from Clair Ridge. The sector model contained a producer/injector pair at reservoir-scale interwell spacing. Across all reservoir-description types investi-gated, fractures and matrix were both modeled explicitly.

Fig. 2—Typical coreflood responses, tertiary. HCPV=hydrocarbon pore volume.

Fig. 1—Typical coreflood responses, secondary.

0

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EOR161750.indd 67 12/12/13 1:28 PM


The effect that this range of reser-voir fracture/matrix descriptions could be expected to have on RS EOR incre-mental oil recovery was investigated by simulated waterflood of each reservoir-description type. BP’s Top Down Res-ervoir Modeling technique was used to build a sector model for each reservoir description and then to execute separate-ly both a high-salinity and an RS water-flood through that same reservoir de-scription. Comparison of RS waterflood oil-recovery performance against high-salinity-waterflood oil-recovery perfor-mance allowed an incremental RS EOR type response to be generated for each reservoir description.

Sector-Model Results. Fig. 3 shows in-cremental RS EOR recoveries for the 48 models at end of field life ordered by in-creasing recovery. There is a positive RS EOR incremental oil recovery from 98% of the reservoir descriptions tested. The average incremental oil recovery across all descriptions is clearly positive.

Further investigation into the below-average recovery cases seen in Fig. 3 con-firmed that low-recovery cases are asso-ciated with matrix-dominated reservoir descriptions where the fracture density is low and the fracture network poor-ly connected. In such reservoir descrip-tions, injectivity is pressure limited and the flood-front progression under both high-salinity and RS waterfloods is slow. When such matrix-dominated reservoir descriptions are waterflooded across an interwell distance, the arrival time of in-cremental RS-EOR oil is delayed to the ex-tent that it is only just beginning to mani-fest itself at the end of field life.

Sector-Model-Results Upscaling. On the basis of core, seismic, and log data, a Delphi analysis (a systematic approach that started with individual experts’ views that were subsequently discussed and revised to achieve a consensus view) was completed by members of the Clair Ridge subsurface team to define the volumetric significance (within the Clair Ridge reservoir) of each of the 48 fracture/matrix descriptions considered in the RS-EOR sector-modeling study. Normalized RS-EOR incremental-oil- recovery profiles from each of the 48 sector models were then combined on a volume-weighted basis into a single nor-malized rock-volume-weighted (RVW) -type response.

With the aim to reinject produced water, an evaluation was conducted to determine the optimal location and tim-ing for injecting produced water and RS water across the various reservoir com-partments. Produced-water reinjection and RS-waterflood injection can be con-sidered to be mutually exclusive for a given water-injection well. Therefore, un-derstanding where produced water can be disposed of across the field defines the injectors that will not take produced water and, by implication, the injectors that can take RS-waterflood injection.

Having understood the sequence of Clair Ridge reservoir segments to ex-perience RS waterflood, a Clair Ridge upscaled RS-waterflood incremental-oil-recovery profile was created by apply-ing the normalized RVW-type response to the underlying high-salinity-flood oil-recovery profile associated with each Clair Ridge segment to experience RS flooding. JPT

Fig. 3—Sector RS-EOR recoveries in ascending order. IR=initial recovery.

-Dominated Recovery

Distribution of RS-Flood Responses at 2050

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Av 14.5%

25–26 March 2014

The Woodlands, Texas, USAThe Woodlands Waterway Marriott

Hotel and Convention Center

www.spe.org/events/ctwi

Register Now!

www.icota.com

EOR161750.indd 68 12/16/13 7:42 AM


Factors such as hydraulic gradients in the horizontal completion,

geologic and fluid variations in the reservoir, and well-placement issues can produce very poor steam conformance in steam-assisted gravity drainage (SAGD). Using proportional-integral-derivative (PID) feedback to control steam injection can lead to improvements in SAGD. Inflow- or injection-control devices (ICDs) can also improve SAGD performance. This paper examines detailed wellbore simulations of a SAGD process in which wells are equipped with a combination of ICD completions and feedback control to determine the physical mechanisms and outline practical procedures to determine an improved ICD completion and feedback-control design.

IntroductionSAGD is the most extensively used pro-cess for development of the bitumen re-sources in western Canada. Fig. 1 shows the concept of this process in which two closely spaced horizontal wells are placed such that the upper well injects steam and the lower producer collects reservoir flu-ids that drain mostly by gravity from a constantly evolving steam chamber. Ide-ally, the steam chamber evolves uniform-ly along the entire length of the well pair. However, the actual pattern of SAGD well pairs shows very irregular steam-

chamber development along the lengths of most of the pairs in the pattern.

For many years, SAGD operators in this region have been evaluating methods to improve conformance along well pairs. One such method is to install dual-tubing strings in the injector and producer. Pre-scribed injection and production rates from each tubing string may be deter-mined from a reservoir-engineering analysis of the formation around the pair, but such analyses are often inexact. In order to prevent the steam chamber from touching the lower producer, which would then remove hot steam instead of using it more efficiently in the upper reaches of the chamber, the injection and production rates are usually set to main-tain a prescribed temperature difference between fluids exiting the upper injec-tor and entering the lower producer. This temperature difference, also referred to as a “subcool” because it is set to be sev-eral degrees below a water saturation temperature, may be controlled at both the heel and the toe of the well pair by use of the ability to inject and produce from the two tubing strings that are landed at these points. However, setting these in-jection and production rates to reflect the current state of the reservoir and current subcool is difficult with conven-tional reservoir-engineering analysis. To improve on this, a proposal was made to use a feedback controller to monitor tem-peratures of produced and injected fluids

automatically, with a target subcool at the heel and the toe of the well pair. By tar-geting the same subcool at the heel and the toe, two objectives are accomplished: (1) achieving the subcool prevents steam from entering the lower producer, and (2) both toe and heel halves are encour-aged to produce uniformly because both are targeting the same subcool (i.e., if one-half temporarily operates at a lower or higher subcool than the target, steam injection is decreased or increased, re-spectively, in that half to compensate).

Another method to improve confor-mance is to install carefully constructed ICDs in either the injector or the produc-er, or in both. When placed in the injec-tor, these devices can equalize the out-flow of steam from heel to toe better, regardless of variations in reservoir mo-bility properties.

PID ControllerFor the dual-tubing cases examined here, the short tubing string in both wells is landed at the heel and the long tubing string is landed at the toe. Two separate controllers are used for the heel and toe tubulars, each with its own error term. See the complete paper for the controller and error term equations.

When a controller with an error term is used to control the injection rates of dual- injection-tubing strings, each of which is targeting a specified subcool to the near-est region in the lower producer, the ob-jectives of meeting a subcool target and of improving conformance are both met. Steam chamber uniformity is improved because each controller operating on dif-ferent regions of the well pair is attempt-ing to achieve the same specified subcool.

ICD Design To Control Conformance, Subcool, and Unwanted Water/GasFor this study, a high-temperature ICD design was chosen that combines a sand-

Simulation of Flow-Control Devices With Feedback Control for Thermal Operations


This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 163594, “Advanced Wellbore Simulation of Flow-Control Devices With Feedback Control for Thermal Operations,” by Terry Stone, SPE, Schlumberger Information Solutions; Carlos Emilio Perez Damas, Schlumberger Calgary Regional Technology Centre; Glenn Woiceshyn, SPE, Absolute Completion Technologies; David Hin-Sum Law, SPE, Schlumberger Calgary Regional Technology Centre; George Brown, Schlumberger Fibre Optics Technology; and Peter Olapade and William J. Bailey, SPE, Schlumberger-Doll Research, prepared for the 2013 SPE Reservoir Simulation Symposium, The Woodlands, Texas, USA, 18–20 February. The paper has not been peer reviewed.

EOR163594.indd 69 12/12/13 1:23 PM


control screen with a choke that is de-signed to give a linear production or in-jection profile throughout the length of the horizontal wellbore. These devices are installed in 7-in. base-pipe joints, each with a length of 46 ft. Each joint is equipped with flow-constriction noz-zles. Flow across the nozzles produc-es a Bernoulli relation (pressure drop vs. flow rate). Fig. 2 is a schematic of the device, including dimensions, outer screens, flow paths, and a picture of the nozzle.

Case StudiesFour cases were run. These included com-binations of dual-string injection with PID control and wells equipped with ICDs. The first case, PID injector/ICD pro-ducer, was configured with an injector containing dual 3-in.-inner-diameter (ID) tubing strings landed at the heel and toe and in which steam-injection rates to the heel/toe strings were PID controlled with a specified subcool target. The producer was equipped with ICDs and, hence, con-tained only a single 6.3-in.-ID tubular

with no additional tubing string landed at the toe. For the second case, PID in-jector/dual-string producer, the injector and producer both contained dual-tubing strings. The injector was PID controlled by a heel/toe subcool target, and the pro-ducer produced equally from both heel and toe tubing strings. The third case, ICD injector/ICD producer, contained both injector and producer fitted with ICDs along their entire horizontal length. Again, there was no additional tubing string landed at the toe for this case. The

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Fig. 1—An overview of a typical SAGD process. Shown are the location of the well pair relative to surface facilities (left), a cross-sectional view of the evolving steam chamber (center), and a plan view of a pattern of well pairs demonstrating nonuniform steam-chamber development along the well pairs (right).

Steam-ChamberExpansion

Steam Injection Oil Well

EOR163594.indd 70 12/12/13 1:24 PM

fourth case, dual-string injector/dual-string producer, was a base case in which the injector and producer both contained dual-tubing strings, steam injection rates were constant and equally split between the heel and toe strings, and production was split also between heel and toe.

ResultsOne of the benefits of installing ICDs in an SAGD injector is to allow a higher heel injection pressure, which means that there is higher enthalpy delivery to the reservoir for a given mass rate and that steam quality increases across the nozzle because of the pressure drop.

At 2 years, temperature and gas- saturation profiles are similar between the three cases—PID injector/ICD pro-ducer, PID injector/dual-string produc-er, and ICD injector/ICD producer. ICD injector/ICD producer displays a slightly greater coolness in the midregion and lower gas saturations although with simi-lar chamber growth near both ends, pos-sibly because injection and production are both occurring only at the heel, while the first two cases have injection at both the heel and the toe. All are showing

a good degree of uniformity along the length of the well pair.

By 7 years, the two PID-injector cases are showing equivalent steam-chamber growth along the entire length while the ICD-injector/ICD-producer case is showing slightly less growth near the toe. Temperatures in the first case (PID injector/ICD producer) are looking somewhat cooler than those for both the PID-injector/dual-string-producer and

ICD-injector/ICD-producer cases be-cause the PID controller in the former is just beginning to hit its subcool target at this time (7 years) and the second PID case will achieve this shortly after.

By 12 years, the first two PID cases are showing cooler steam chambers than the ICD-injector/ICD-producer case because both are achieving their subcool targets.

The two cases with dual-string pro-ducers, dual-string injector/dual-string

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Fig. 2—Schematic of the ICD, showing overall linear dimensions, outer screens, flow paths, and a picture of the nozzle.

Base Pipe Boss Ring (Cover) Media + Shroud

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EOR163594.indd 71 12/12/13 1:24 PM


producer and PID injector/dual-string producer, show very large, uncontrolled subcools up to approximately 5.5 years, while the two ICD cases show controlled subcool throughout the production cycle. The PID-injector/dual-string-producer case does eventually start to control the subcool. The base case, with dual strings in both injector and producer and no sub-cool control, shows very low subcools at times greater than 5 years, but this is be-cause the steam chamber is touching the producer at these times. The case with ICDs in both injector and producer ex-hibits very low subcool at times greater than 5 years; but, again, the steam cham-ber is getting close to the producer. The PID-injector/ICD-producer case shows good subcool control in the early stages and the ability to achieve a subcool target in the later stages.

At 2 years, the two cases with PID injection, PID injector/ICD producer and PID injector/dual-string producer, show similar pressure profiles around the well pair except that the case with the ICD producer shows flatter profiles than the case with the dual-string producer. This is expected because of the bene-fits of the ICDs in evening out inflow to the producer.

At 7 years, the PID-injector/ICD-producer case is showing lower pres-sures because the PID-injector has al-ready begun to achieve its subcool target, which the second PID injector case has not yet accomplished. Pressure profiles

for the other two cases, PID injector/ dual-string producer and ICD injector/ICD producer, are very similar.

By 12 years, the two PID-controlled injection cases are showing comparable low pressures around the well pair, while the ICD injector/ICD producer case is showing considerably higher pressures because steam has broken through to the producer and is causing higher pressure drops across the ICD nozzles.

Fig. 3 presents a comparison of cu-mulative steam/oil ratio for the three well-pair configurations and the base case.

DiscussionThe results suggest that a hybrid meth-od of using feedback- (PID-) controlled steam injection from dual- tubing strings with a producer equipped with ICDs may have several benefits. First, there are re-duced capital and operating expendi-tures because there is one less tubing string in the producer. Second, an ICD-equipped producer provides a more-even inflow, which results in better- controlled subcool throughout the production cycle, particularly in the early stages after switch over when it is more difficult (or impossible) for PID-controlled steam in-jection to achieve a subcool target. Third, later in the production cycle, the ability of the PID-controlled injection to force a specified subcool target appears to keep the steam chamber farther from the pro-ducer and improve the economics of the process. JPT

Fig. 3—Comparison of cumulative steam/oil ratio for three SAGD well-pair configurations and the base case.

Time, days

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Cumulative Steam/Oil Ratio vs. Time

ICDs in Injector/Producer

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PID Injector, Dual-String Producer

3

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Naturally fractured reservoirs (NFRs) contain a significant

amount of remaining petroleum reserves and are now being considered for water-alternating-gas (WAG) flooding as secondary or tertiary recovery. The authors face the challenge of reservoir simulation of WAG by building models at various scales, starting with pore scale and expanding to an intermediate scale and then to reservoir scale. They show how pore-network modeling and fine-grid modeling where the fractures and matrix are represented explicitly can be used to increase the accuracy of numerical simulations at field scale.

IntroductionA significant portion of the world’s re-maining petroleum resources is located in NFRs, including supergiant fields in the Middle East. A detailed understand-ing of the recovery processes involved in extracting hydrocarbons from NFRs by use of enhanced-oil-recovery techniques is key to increasing ultimate recovery for such reservoirs.

Waterflooding has been used with various degrees of success in NFRs. For unfavorable (i.e., mixed- to oil-wet) ma-trix wettability, however, waterflooding can be ineffective.

Gas/oil gravity drainage (GOGD) provides an important drive mechanism that can be effective irrespective of the rock wettability. In NFRs, fractures in-crease the exposure of the injected gas to oil in reservoir rock, which renders GOGD more effective than it is in unfrac-

tured reservoirs. Consequently, gas in-jection has been applied in many NFRs. However, because the gas mobility is very high compared with that of water and oil, so is the risk of bypassed oil and gravity override, which can lead to very early gas breakthrough. This is particularly true for NFRs.

WAG flooding combines the mer-its of the two injection fluids on mac-roscopic and microscopic scales while stabilizing the injection front, delaying breakthroughs, and, therefore, leading to increased oil recovery compared with continuous water or gas injection.

Reservoir simulation of WAG injec-tion is very challenging because a repre-sentative three-phase saturation model is required to predict relative permeability and capillary pressure as water and gas saturations increase and decrease alter-nately. Three-phase relative permeability and capillary pressure data are extremely difficult to measure experimentally. Even if experimental evaluation becomes fea-sible, an infinite number of saturation paths can occur in the reservoir. This ne-cessitates the use of empirical, or inter-polation, models to predict three-phase relative permeability and capillary pres-sure from two-phase experiments.

In NFRs, capillary pressure and rela-tive permeability functions have a major effect on fluid exchange between ma-trix blocks and fractures. Predicting the effects of the interplay of viscous, cap-illary, and gravity forces is challenging because fluid flow is viscous-dominated in the fractures while transfer between fractures and matrix blocks is dominated

by capillary and gravity forces. Because most of the oil is contained inside the ma-trix, capillary and gravity forces can be more important in NFRs than in conven-tional reservoirs.

This capillary-/gravity-driven exchange between fractures and matrix is commonly modeled by use of dual-porosity or dual-porosity/dual- permeability models.

The authors use a novel pore- network model to predict three-phase relative permeability and capillary pres-sure functions of arbitrary wettability to model fracture/matrix transfer processes during WAG flooding. While it is difficult, time consuming, and costly to obtain all hysteretic two- and three-phase relative permeability and capillary pressure func-tions experimentally for the same rock sample, pore-network models can gener-ate a complete saturation function for the same pore structure.

The authors attempted to preserve small-scale recovery processes at the field scale to ensure that they were well represented in porosity models. There-fore, they introduced a stepwise upscal-ing procedure (Fig. 1) to preserve these processes across various scales.

Pore-Scale Displacements To Predict Saturation FunctionsThe authors’ three-phase pore-network model accounted for all observed mi-croscopic displacement processes during three-phase flow, such as multiple dis-placement chains, layer formation and collapse, or film flow. The pore- network simulator has been benchmarked against published three-phase experiments for sandstones and micromodels of different wettability.

To generate relative permeabili-ty and capillary pressure data, the net-work was initially saturated with water followed by oilflooding to simulate a primary-drainage process. Then, a series

Multiscale Simulation of WAG Flooding in Naturally Fractured Reservoirs


This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 164837, “Multiscale Simulation of WAG Flooding in Naturally Fractured Reservoirs,” by Mohamed Ahmed Elfeel, Adnan Al-Dhahli, Sebastian Geiger, SPE, and Marinus I.J. van Dijke, Heriot-Watt University, prepared for the 2013 EAGE Annual Conference and Exhibition/SPE Europec, London, 10–13 June. The paper has not been peer reviewed.

EOR164837.indd 73 12/12/13 1:22 PM


of waterflooding (imbibition) simula-tions followed until the network water saturation reached a predefined value, at which gasflooding commenced (Fig. 2).

The Intermediate ScaleA fine-grid model was constructed to in-vestigate the effect of three-phase relative permeability and capillary pressure on matrix/fracture transfer for a gridblock scale of 50×50×50 ft with 27 (3×3×3)

matrix blocks that are 12×12×12 ft each. This resembles the classical but highly idealized sugar-cube array (Fig. 3). This model allows for results from the pore scale, in the form of relative permeabil-ity and capillary pressure tables, to be brought to the continuum scale where fractures and matrix are present. To sim-ulate WAG cycles, the fractures were in-stantly filled with water or gas when modeling recovery from the 27 matrix

blocks. Matrix blocks were assigned two- and three-phase data. For the fractures, linear relative permeability was used and zero capillary pressure was assumed.

During the first two water/gas cy-cles, recovery predicted for all empiri-cal models reasonably matches recovery predictions for the pore-network-derived three-phase relative permeability and capillary pressure. This is because the total average oil saturation is relatively high and, hence, close to two-phase rela-tive permeability and capillary pressure curves. However, empirical models pre-dicted that oil recovery continues to in-crease in subsequent WAG cycles where-as the pore-network-derived functions predicted no substantial increase in oil recovery after the first two flooding cy-cles. This is because relative permeabil-ity and capillary pressure functions from the pore-network model cause water and gas phases to displace each other but do not recover additional oil, leaving the oil phase undisplaced.

WAG-Flooding SensitivitiesOn the basis of the pore-network-derived saturation functions, the authors con-sidered a series of sensitivities to WAG-flooding-design parameters—WAG-cycle duration and -cycle order—as well as the effects of altering the matrix wettability.

Cycle Duration. For the nonviscous-dominated flow between matrix blocks and fractures, the authors observed that the overall WAG recovery exhibited little to no sensitivity to the WAG-cycle length. However, the results also show that the shorter the WAG cycle, the higher the speed of recovery. This is because most of the oil is produced during the first two

Fig. 1—Stepwise procedural upscaling of recovery processes in NFRs. Colors represent different phases (red=gas, green=oil, blue=water).

Fig. 2—Saturation paths during gasflooding at different initial water saturations after water imbibition into a water-wet sandstone. Color legends show relative permeability values of oil, water, and gas phases, respectively, from left to right.

Fig. 3—Fine-grid model used to simulate fracture/matrix multiphase transfer (green=oil, blue=water; left). Top view of the model (top right) and cross-sectional view of the model (bottom right) show the oil saturation in fractures and matrix.

Pore Scale Intermediate Scale

SinglePorosity

DualPorosity

Reservoir Scale

Oil Saturation

EOR164837.indd 74 12/17/13 9:21 AM


water/gas cycles because of a combina-tion of water imbibition and gas gravity drainage. During later WAG cycles, little additional oil recovery is achieved when using pore-network-model-derived rela-tive permeabilities.

Cycle Order. The order of WAG cycles also has an effect on oil recovery from the matrix. At first, oil displacement by spon-taneous water imbibition occurs faster than GOGD if the matrix is water-wet. Then, recovery by water imbibition be-gins to diminish because of the reduction in oil-phase mobility as water saturation increases at the boundaries of matrix blocks. Gas-gravity-drainage displace-ment continues to increase and eventu-ally outperforms recovery by spontane-ous water imbibition. The difference in recovery profiles during gas and water in-jection for the WAG cycles is an indication of the competition between the phases. This is because, when gasflooding occurs after waterflooding, the average initial water saturation is high. Hence, oil recov-ery is slow in the beginning because gas displaces water first. The water cycle fol-lows the same explanation.

Effect of Matrix Wettability. The rock-matrix wettability has a significant ef-fect on recovery from NFRs. To study this effect, three-phase relative perme-ability functions, capillary pressures, and saturation paths were recomputed with contact angles adjusted to represent oil-wet rock. As expected, water/oil capillary pressure values were negative in the oil-wet case. This dramatically changes the efficiency of water injection for recover-ing oil from matrix blocks; capillary forc-es act against water entering the blocks. However, gravity forces, because of the density difference between the water and oil phases, enable the water phase to start displacing oil in the matrix blocks from the bottom up. Recovery from water dis-placement by gravity alone in oil-wet res-ervoirs is significantly less than that from the combined gravity and capillary forces in water-wet reservoirs. However, water gravity displacement in an oil-wet res-ervoir is a cocurrent displacement and does not lead to the trapping of oil inside blocks by the low-oil-mobility region.

Discussion and Concluding RemarksThe application of three-phase satura-tion functions showed that the empir-ical interpolation methods to estimate three-phase saturation functions, which are commonly used in standard indus-try simulation practice, overestimated oil recovery during late WAG cycles by an absolute difference of 25% compared with physically consistent and pore- network-derived relative permeability and capillary pressure functions. The au-thors suggest that the reason for such a tremendous difference is the more accu-rate representation of intrapore displace-ment processes in relative permeabili-ty and capillary pressure functions that are computed from pore-network sim-ulation. A sensitivity analysis revealed that water imbibition during the water-injection cycles in WAG flooding creates a region of low oil mobility around ma-trix blocks. At such low oil saturations, empirical interpolation models over-estimate relative permeability, predicting more oil to be released from the center of matrix blocks.

The sensitivity analysis also showed that recovery speeds up with decreas-ing length of WAG-flooding cycles but that final recovery always converged to a similar value. Final recoveries were also similar for cases in which the order of the WAG cycles was changed. Surprising-ly, continuous gas injection in water-wet rocks yielded higher oil recoveries com-pared with WAG flooding, whereas con-tinuous water injection recovered less oil compared with WAG. Hence, the authors concluded that water imbibition has an adverse effect on recovery from matrix blocks if gas is available for injection. This is because of the low-oil-mobility region at the fracture/matrix interface.

The authors point out that the results cannot be used to evaluate WAG-flooding success in general because viscous dis-placement is not taken into consider-ation. The question, therefore, remains: Will heterogeneity in the viscous flow field, arising from nonuniform fracture networks, dominate recovery or will un-certainty in the fracture/matrix transfer prevail and control the overall recovery behavior during WAG? JPT

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Jesse Lee, SPE, is chemistry technology manager at Schlumberger. He holds a PhD degree in chemistry from Yale University and

conducted his post-doctoral research at the Massachusetts Institute of Technology. Lee joined Schlumberger in 1997 in Tulsa as a development engineer, focused on the development of polymer-based fracturing fluids. During 2000–10, he managed new-product development at Schlumberger product centers in Sugar Land, Texas, and Clamart, France. At Schlumberger, Lee is responsible for developing technical collaborations and managing relationships with external chemical companies. He is a member of the JPT Editorial Committee.


OTC 24092 A Mature Southern North Sea Asset Considers Conversion to Wet-Gas Operation, Which Requires the Development of Compatible and Novel Chemistries for Flow Assurance and Asset Integrity by J.F.L. Garming, Nederlandse Aardolie Maatschappij, et al.

SPE 166300 Reducing Brownfield Development Costs Through Improved Drilling Practice and Enhanced Understanding of Wellbore Instability in Weak Formations by N. Stevenson, Statoil, et al.

SPE 160429 Innovative Solution Successfully Recompletes Problematic Well in Malaysia by Chris Elliott, Petronas Carigali, et al.

Sustainable growth in oil and gas production must stem from a combination of new discoveries and optimized recovery from maturing fields. Therefore, development of mature oil fields has been, and will increasingly be, an attractive subject. Conse-quently, there is a large number of published studies describing the methodology of mature-field-development practices. However, it is also evident that optimizing the production of mature fields presents great technological challenges for the operators, who must manage production decline over the short term while increasing recovery factors over the long term. There are opportunities for quick wins, but, for long-term growth, a coherent strategy that integrates elements of technology, people, and pro-cess must be established.

A significant amount of information is available that covers almost all aspects of managing mature fields. It is critical to have access to the relevant information and to use the right tools to improve decision cycle time. This allows the operators to cor-rect course in a timely manner and to avoid implementing changes in a compartmen-talized fashion. It is straightforward to establish processes and follow best practices, but having people with multidisciplinary expertise is the glue that holds all the pieces together. Many in the industry have stressed the importance of properly developing experience and capacity for innovation. However, promoting the culture of innova-tion requires patience, which is challenging for public companies that are under quar-terly pressure.

It is exciting to see that there is no shortage of technological advances, but it is safe to say that there is still plenty of room for key enablers to continue to evolve and to synergize with each other. For instance, chemistry, as a basic science, could play a bigger role in the overall scheme and perhaps, in certain areas, should take the lead-ing role. Nature has designed countless examples of well-choreographed chemical reactions that support the complexity of life. It is conceivable that such intelligent chemistry can also be developed to broaden the role of chemistry in terms of manag-ing mature fields. I hope to see more and more chemistry-related publications in the coming years.

The decline of a field’s production curve is inevitable; good preparation helps to control the process. I remember reading this statement from one of the majors: “Prep-arations for field maturity must start with first oil.” In parallel, one must also keep in mind that social responsibility, especially the environmental aspect, should be one of the key considerations while establishing the development strategy.

Again, this is where chemistry can bring significant value. For instance, precise fracturing technology that uses less proppant is a good example of new technology that exhibits uncompromised performance that is one step in the right direction. I hope you enjoy reading the selected papers for this month’s feature. JPT

TECHNOLOGY

mature fields and well revitalization

2MFWRFocusJan.indd 76 12/12/13 8:34 AM


The new channel-fracturing technique is capable of increasing

fracture conductivity by up to two orders of magnitude. The channel-fracturing technique allows development of an open network of flow channels within the proppant pack, enabling fracture conductivity by such channels rather than by flow through the pores between proppant grains in the proppant pack. The successful implementation of the channel-fracturing technique in brownfield development is described in detail with the case study of the Talinskoe field in Russia.

IntroductionThe Talinskoe section (for simplicity, re-ferred to herein as the Talinskoe field) is part of the medium-sized, mature Kras-noleninskoe field, located near Nyagan, Russia. Exploration of this section began in 1982. It has more than 5,000 wells completed either in the Middle Juras-sic Tyumenskaya suite (Formations JK2 through JK9) or the Early Jurassic Sherka-linskaya suite (Formations JK10 through JK11). More than 1,500 wells have been fractured hydraulically. Approximately 60% of all wells are idle, mainly because of water breakthrough (the average water cut throughout the field is 90%). Most hydrocarbons are found in the Sherka-linskaya suite, but, currently, water cut in many wells producing from the JK10 and JK11 formations already exceeds the eco-nomic limit. These wells are recompleted

to produce from shallower formations in the Tyumenskaya suite.

The Tyumenskaya suite is character-ized by a complex geology. It is an argil-laceous facies with sandstone sublayers and lenses. Because of low permeabili-ties in the Tyumenskaya suite, most of the wells cannot be produced commer-cially without stimulation. To enhance well productivity in such conditions, the greatest possible fracture length is re-quired, but it is not always possible to achieve targeted half-length because of geological limitations and formation mechanical properties. While designing for the greatest length possible, the en-gineer is frequently limited by low-to-moderate stress contrast between the target formation and the barrier separat-ing the target interval from the possibly watered-out formation.

It is usually not a problem in low-permeability reservoirs to achieve tar-get dimensionless fracture conductivity (DFC) greater than 2. But this does not always provide the best productivity re-sults. Thorough analysis of the 3-year fracturing campaign in Nyagan showed that an DFC greater than 15–20 should be targeted for this region. Lower DFC values result in lower productivity. Lack of control over fracture-height growth (with the subsequent reduction in frac-ture width) is a possible reason for pro-duction underachievement.

Current fracturing practices in the Talinskoe field aim for height-growth control, longer effective fracture half-

lengths, and enhanced fracture conduc-tivity. For these purposes, several differ-ent fracturing technologies and pumping techniques were implemented. All of these technologies have demonstrated different levels of productivity increase. But all of them have a significant draw-back: The screenout ratio increases with a decrease in fluid viscosity and an in-crease in operational complexity. In the period between 2007 and 2009, when these technologies were implemented, the average screenout ratio for Talin-skoe field was 12%. Screen out affects production in several ways. When all the designed proppant is not placed in the formation, then the fracture geometry is compromised, possibly by a lower DFC, incomplete zonal coverage (the entire net pay is not covered), or smaller skin improvement (shorter fracture length). In addition, fluid and gel recovery might suffer from lengthy workover opera-tions, which may reduce the retained fracture conductivity.

A trial campaign for channel- fracturing technology was conducted on the Tyumenskaya suite. The campaign was aimed at increasing fracture con-ductivity and effective fracture half-length without an additional risk of premature screenout.

Channel FracturingThe concept behind the new fractur-ing technique may be described in one word: channels. The homogeneous prop-pant pack is replaced by a network of flow channels (Fig. 1); now, the frac-ture conductivity is created not by prop-pant, but rather by channels. Proppant is now grouped into clusters, support-ing fracture walls from closure around the channels.

Channels are created by a spe-cial pulsing pump schedule and a clus-tered perforation scheme. In contrast to the conventional pumping schedule, in

Channel Fracturing Applied in Mature Wells in Western Siberia


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 159347, “First Channel Fracturing Applied in Mature Wells Increases Production From Talinskoe Oil Field in Western Siberia,” by Rifat Kayumov, SPE, Artem Klyubin, SPE, Alexey Yudin, SPE, and Philippe Enkababian, SPE, Schlumberger, and Fedor Leskin, SPE, Igor Davidenko, SPE, and Zdenko Kaluder, SPE, TNK-BP, prepared for the 2012 SPE Russian Oil and Gas Exploration and Production Technical Conference and Exhibition, Moscow, 16–18 October. The paper has not been peer reviewed.

MFW159347.indd 77 12/12/13 1:38 PM


which proppant is added homogeneous-ly with incremental increases in prop-pant concentration, the new technique adds the proppant in short pulses. The proppant pulses will create the prop-pant clusters. The clean pulses (pulses without proppant) will promote the for-mation of channels. The last step of a treatment requires continuous addition of proppant, as in a conventional treat-ment. The goal of this step, referred to as the tail-in step, is to ensure a stable, uni-form, and reliable connection between the channeled fracture and the wellbore. It is important to design the tail-in step so that it is short enough to prevent it from having a significant negative im-pact on the overall fracture conductivity. As for the perforation scheme, it is nec-essary to create clusters of perforation shots separated by nonperforated inter-

vals. These clusters will separate prop-pant pulses into smaller slugs and will promote uniform distribution of prop-pant slugs across the fracture.

The special modeling workflow comprises proppant-transport models to calculate the placement of proppant slugs. After the proppant slugs (conglom-erates) are placed, the fracture walls will bend around the slugs (Fig. 2), which will reduce the effective volume of the channels. To model this phenomenon, a special fit-for-purpose mechanical model was developed and integrated into a com-mercial fracturing simulator. If the width profile of the channels is known, fracture conductivity can be calculated. The de-veloped engineering workflow thus al-lows us to relate what is performed at surface to what is obtained in the frac-ture. Furthermore, it allows optimiza-

tion of the fracture design to ensure that channels will stay open.

Many successful case studies of channel-fracturing implementation al-ready have been published; some of them are based on hydraulic fractur-ing in ultralow-permeability reservoirs, and others concern low- and medium- permeability reservoirs. Regardless, all authors show significant productivity in-creases in the wells with channel fractur-ing compared with offset, conventionally stimulated wells. These studies proved the benefits of this technology; how ever, all of them are related to gas and gas/ condensate reservoirs.

Before initiating the pilot channel-fracturing campaign, a similar experi-ence was reviewed carefully. A previously presented case study with the channel-fracturing technique implemented for medium-permeability oil formations in western Siberia in newly drilled wells of the Priobskoe field yielded two impor-tant conclusions:

1. The performance of the wells treated with the new technique was 10 to 15% higher than that of wells receiving conventional treatments.

2. The productivity index of the wells treated with the new technique was stable for 2 years, confirming the existence and reliability of the channel structures.

In addition to extraordinary fracture conductivity, improved fracture clean-up, and increased effective fracture half-length, there is another valuable bene-fit from the implementation of channel fracturing in Talinskoe field: a mini-mized risk of screenout. Currently, more than 6,500 stimulation treatments with channel-fracturing technology have been performed worldwide, and only three screenouts have occurred, which yields a success rate greater than 99.95%.

Candidate Selection and Design ConsiderationsSeveral criteria and considerations were applied in the candidate-selection pro-cess. One of the main objectives, besides those that relate to the technology itself, was to find candidates with several repre-sentative offset wells that were hydrauli-

Fig. 1—A conventional propped fracture (left) with respect to channel-fracturing technology (right).

Fig. 2—Channels narrowing around proppant slugs.

Conventional Fracturing Channel Fracturing

Xf effective

Xf propped

Xf hydraulic Xf effective Xf propped Xf hydraulic= =

Open Channel Open Channel

Stress

Stress

ProppantConglomerate

MFW159347.indd 78 12/18/13 8:19 AM

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cally fractured by use of conventional technologies and had enough production data to make correct comparison analy-sis. In addition, wells were screened on the basis of the following requirements:

◗◗ Cased-hole wells with no perforation in the target interval to allow cluster perforation

◗◗ Well deviation of less than 15° in the target interval to minimize risk of misalignment of fracture plane with the wellbore

◗◗ A certain degree of rock stiffness: ratio of Young’s modulus to closure stress at greater than 275

◗◗ Net height greater than 6 m◗◗ Lowest possible lamination of

the pay interval with a minimum number of separating shale or argillite streaks

◗◗ No additional risks of breaking into water-bearing formations in case of fracture-height growth

Channel fracturing is beneficial in two ways. First, the presence of clean pulses around proppant structures and fibers inside slurry provide bridging-free flow, which leads to increased prop-pant penetration inside the formation. Second, enhanced fracture permeability enables faster and more-complete re-covery of the fracturing fluid during well- cleanup procedures through channels, which results in increased effective half-length and unhindered hydrocarbon flow during production. A specially developed module in the commercial simulator was used for the designing and optimizing of channel formation. The effort was made to design treatments that ensure fully opened channels through the entire length of created fractures with maxi-mum possible conductivity.

After thorough candidate screen-ing, with several stimulation and pro-duction specialists involved from both the operator and the service company, five wells showed the best possible com-pliance with the screening criteria described and were chosen to be stimu-lated with channel-fracturing treat-ment (Wells X268, X118, X473, X430, and X373). Chosen wells were distrib-uted across the field. All were treated with water-based fracturing fluid with 3-kg/m3 (25-lbm/1,000-gal) guar- polymer

loading and borate-type crosslinker. A 16/20-mesh intermediate-strength prop-pant was used as the main treatment, and 3 tons per job of 12/18-mesh resin- coated proppant was used as tail-in mate-rial to ensure maximum conductivity in the near-wellbore region and control over proppant flowback at the same time. All treatments were pumped as per design without screen outs, despite a very ag-gressive schedule, proving the reliability of proppant placement in pulsating mode.

Production AnalysisAnalysis of production is based on the productivity-index value normalized on the net-pay thickness. For each well, the productivity index was recalculated from daily-liquid-production data, with applied Vogel’s correction for produc-tion below bubblepoint pressure. Net-pay thickness was derived from log data. A robust permeability value was not known for most of the wells, so it was not used for further data normalization. The productivity index at or above bubble-point can be simply calculated as a ratio of liquid production to applied draw-down. Wells in the Talinskoe field pro-duce with electrical submersible pumps. It is a common practice to keep bot-tomhole pressure below the bubblepoint pressure. (For a detailed discussion of the production-analysis process, please see the complete paper.)

Normalized productivity-index values for the five wells treated with the channel-fracturing technique were av-eraged into a single curve and com-pared with the averaged normalized productivity-index curve from eight off-set wells after stimulation with conven-tional fracturing treatments. The pro-ductivity of wells treated with channel fracturing was significantly higher than that of wells stimulated with conven-tional fracturing. Note that because of the low number of treated wells, nor-malized productivity curves suffer from “noise” induced by imperfections of daily production-measurement data from each well. But the general trend is obvious: Wells treated with the channel- fracturing technique display signifi-cantly higher productivity-index values during the entire production period cur-rently available. JPT

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As a field matures, there is a crucial need to focus on

integrity-related issues such as hazard prevention and mitigation. During the initial field development of D field offshore Terengganu in Malaysia, the well design was fit for purpose to meet production needs. However, extension of production requirements contrary to earlier plans, a production-driven operational philosophy, and irregular well-integrity surveillance have compounded integrity issues. To rectify this trend, a field redevelopment was based on a number of concrete steps.

Field OverviewD field is an oil- and gas-producing field that saw its first hydrocarbon discov-ery in 1981. After a series of apprais-al wells and the formulation of a field- development plan, the field’s first oil production was realized in March 1991. The field’s primary production is oil from multistack major reservoirs X1 and X2, with 30 to 70% CO2 concentration. D field has a total of four producing plat-forms, consisting of one main platform with three satellite platforms. The pro-duction streamlines from the satellites undergo separation processes at the main platform before collection at the floating storage and offloading facility.

Currently, the field is oper-ating with a total of 218 completion strings. The main platform consists of a separation-process unit, a water-

injection module, a gas-injection mod-ule, and a produced-water-treatment system. Dedicated gas and water pipe-lines run to each satellite platform, meeting the requirement of water and gas injection to the reservoir as part of the reservoir-management plan. In addition, enhanced-oil-recovery (EOR) implementation is being assessed as part of the effort to increase production.

Problem Statement From 2010 to 2012, a 60% decline in daily production rate was observed, largely as a result of integrity issues. Operating under a wide range of CO2 concentrations in hydrocarbons poses a challenge in the initial material se-lection for well completion, which can in turn greatly affect well integrity and life span. Furthermore, the early- optimization philosophy for water and gas injection led to the use of one well slot with dual-utility well completion, which complicates well intervention and deteriorating well-integrity assurance because of the difference in operating temperatures between the two strings in a wellbore.

Extensive diagnostic surveys and well-integrity logging were conducted from 2010 to 2012 in order to determine the condition of subsurface well integ-rity and safeguard the production and reservoir-management-plan require-ments for the EOR project. To ensure deliverables, the team has adopted a se-ries of systematic guidelines to diagnose well integrity.

Subsurface Integrity Diagnostics Rapid Increase in Water Cut. From the key observation wells, the team noted a steep increase in water-cut percent-age; in one example (Well AA), this per-centage rose from an initial 18 to 80% within 2 consecutive years of monitor-ing. From this observation, the team has initially estimated that leaks in comple-tion strings most probably have occurred because of an operating strategy of si-multaneous water injection and oil pro-duction in one well slot in most of the D-field wells.

Sudden Drop in Oil Production. In again considering the example of Well AA, the steep unexpected increase in water production has caused a significant reduction in oil production. This was be-lieved to be caused by the increase in hy-drostatic pressure in the annulus that sig-nificantly reduced the oil column in the production strings overtaken by water.

Abnormal Pressure Profile. Here we use the example of Reservoir X-3, which was simultaneously produced from the group of six observation wells that had shown a stable pressure profile in the course of 7 years of production. It is im-portant to note that Reservoir X-3 is not the main producing reservoir in D field. X-3 is a natural-depletion reservoir, a term used by the team to describe a res-ervoir with no water-injection support from the injector wells to maintain the pressure. However, the reservoir pres-sure monitored from these six wells ex-perienced a steady decline that ended in 1998, but in 2001, the pressure increased by 200 psia, with a steady increase until the end of 2007.

This phenomenon is probably caused by production-tubing leaks in sin-gle or multiple wells concurrently pro-ducing from and injecting to the other

Mature-Field Subsurface Integrity: Holistic Diagnostic Approach in Malaysia


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165634, “Mature-Field Subsurface Integrity: Formulation of a New Paradigm Through a Holistic Diagnostic Approach for D Field, Malaysia,” by Wan Rokiah Ismail and Almag Fira Pradana, Petronas Carigali, prepared for the 2013 SPE Latin American and Caribbean Health, Safety, Social Responsibility, and Environment Conference, Lima, Peru, 26–27 June. The paper has not been peer reviewed.

MFW165634.indd 82 12/12/13 1:38 PM


reservoirs in D field. The injected water, intentionally dedicated to support other reservoirs, has traveled to Reservoir X-3 because of leaks in completion strings, which in turn caused high water produc-tion recorded from the reservoir’s pro-ducing wells.

High Casing Pressure. Daily surveil-lance on well parameters such as flow-ing tubinghead pressure, production- casing pressure (PCP), intermediate- casing pressure (ICP), and flowing pro-duction-string-head temperature allows the team to identify anomalies in well conditions. Early signs of communica-tion between casings can be detected if PCP (Annulus A) exceeds 2,000 psi and ICP (Annulus B) exceeds 300 psi. The communication between casings is fur-ther confirmed by bleeding off the pres-sure at the respective annulus and moni-toring to see if the pressure builds up in the annulus by more than 50% within 24 hours after the attempt. Communica-tion between casings is treated as a high health, safety, and environmental prior-ity. Should the situation be encountered, the well is required to be secured and tested further to confirm the existence of leaks, and remedial action is to be taken.

Well Intervention In place of the requirement to perform field-performance analysis and reser-

voir studies by operating per a con-sistently optimum-condition reservoir- management strategy, the D-field team has initiated and executed routine reservoir-data gathering in all of its 170 wells, which further confirmed the ex-istence of poor well integrity after 20 years of production. For a detailed dis-cussion of these findings, please see the complete paper.

Well Workover Once the well-integrity condition is con-firmed through surface data and well-survey data, the condition is then eval-uated. If possible, internal patching (completion string and casing) will be conducted to rectify the integrity issues. However, in order to secure the well’s safety, ensure continuous production, and ensure reserves recovery, a work-over is required should the well present conditions indicating that it is beyond rectification, such as multiple holes and leaks in the completion string, annulus communication, and packer leak caus-ing crossflow between reservoirs.

Therefore, with multiple wells expe-riencing severe well-integrity issues be-yond rectification and in preparation for a future EOR program, a massive work-over campaign was carried out between 2009 and 2012 in D field. In the course of the workover campaign, the down-hole condition was confirmed further

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MFW165634.indd 83 12/12/13 1:39 PM


on the basis of the completion string and well accessories retrieved to surface from various wells (Fig. 1). Internal and external corrosion can be detected on the major completion accessories.

Casing Integrity On the basis of the severely corroded condition of the completion string re-trieved during the workover activity, the casing integrity becomes suspect. The team has initiated and executed a series of casing-integrity tests to ensure the ability of the casing to withstand pres-sure during production with no potential hazard to the environment. In addition to the casing- injectivity tests that were performed to ensure casing reliability, a series of cased-hole logs with sonic and ultrasonic capabilities was executed to ascertain not only the integrity of the casing but also the bonding quality of the cement behind the casing.

In one example from Well DD, the interpretation result of the survey’s cor-rosion mode was able to show a sig-nificant degree of metal loss ranging from 30 to 50%, mostly located near or between the fluid-entry points at the perforation area. In an instance from Well EE, the ultrasonic interpretation of a significant portion of the casing re-vealed the disturbing occurrence of a microannulus filled with gas (from the reservoir secondary gas cap) in the ce-ment above the main production zones. To ensure the safety of the environment with respect to the hazards caused by a potential leak of production fluids, the team decided to perform a remedial squeeze cementing on Well EE, resulting in a major improvement in the cement-bonding quality.

However, the poor casing condi-tion in Well DD made that well particu-larly hazardous for a new recompletion in the same slot. Hence, the team put forward a plan to reuse the slot by per-forming a plug-and-abandon operation

in the existing wellbore, starting from the poor-casing section and extending to the bottommost depth of the origi-nal slot, followed by a sidetracking of a new target above the abandoned section to secure and deliver the remaining re-serves of the well.

Controlling the Corrosion RateCorrosion is inevitable. Therefore, the only possible control that can be ap-plied in a completion string is control of the corrosion rate. The corrosion rate increases as the temperature, pressure, and stress increase during production. Corrosion will occur with the appear-ance of an anode, a cathode, and an elec-trolyte, which promote the oxidation and reduction processes of metal.

A high concentration of carbon dioxide, together with high-water-cut production, promotes the formation of carbonic acid. The acidic substance will then react with iron to form sidetrite scale, forming a protective film on the walls of the completion string because the scale is nonconductive in nature, thus preventing galvanic corrosion oc-currence. However, crevice and pitting corrosion will occur when carbonic acid is formed. Additionally, the presence of CO2 will cause embrittlement, which in turn results in stress-corrosion crack-ing, causing mechanical failure of the completion string (Fig. 1).

There are also biological factors to consider in corrosion-rate con-trol. Injection-water quality should be monitored for the presence of sulfate- reducing bacteria (SRB). SRB metabolize sulfate ions of an organic carbon source, thus introducing hydrogen sulfide (H2S) into an H2S-free system. This will then accelerate the occurrence of crevice cor-rosion in the completion string. Fur-thermore, other factors can influence the corrosion rate, including an erosive production environment and the selec-tion of completion metallurgy. JPT

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MFW165634.indd 84 12/16/13 3:32 PM

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VICO Indonesia is the operator of the Sanga-Sanga production-

sharing contract (PSC) in Indonesia. Against a backdrop of of 46% annual base decline, VICO generated and implemented an integrated and aggressive work program called the Renewal Plan. This is an integrated approach between reservoir management and technology application. This plan proved to be an efficient example of better reservoir management for optimum development of mature assets.

IntroductionThe Sanga-Sanga acreage is located on-shore in the Mahakam delta, East Kali-mantan, Indonesia. The acreage is lo-cated within the Kutai basin, which is characterized by the Samarinda anti-clinorium, with a series of highly pro-lific anticlines. Hydrocarbon accumu-lations are most often located within a series of mid-Miocene upper-delta and delta-plain sandstone reservoirs, and are principally characterized by four-way dip closure or two-way structural/stratigraphic traps.

VICO Indonesia has been explor-ing and developing this PSC acreage ac-tively since 1968. There are seven pro-ducing fields (Fig. 1): Badak, Nilam, Semberah, Mutiara, Beras, Pamaguan, and Lampake. These together produce 385 MMscf/D of gas and 14,500 B/D of liquids from 420 active wells, which have mixed wellbore completions (sin-gle, dual-selective, monobore, dual-

monobore, and horizontal). The sur-face facilities supporting the production include four main production centers, 12 gathering stations, and more than 90 compressors.

After 40 years of production, these fields have now reached a fairly mature stage; most of the penetrated reservoirs/tanks have been depleted from origi-nal pressures. Coupled with the annual production decline, this condition has resulted in significant challenges to de-livering a continuous economic and ef-ficient field-development strategy while maximizing field production.

Renewal PlanVICO carried out a reserves-reassessment study—an integrated approach involving reservoir management and technology applications conducted by a multidisci-plinary team. The seven components of the Renewal Plan are described in the fol-lowing subsections.

Securing Base Production. Secur-ing base production is one of the keys to achieving a production target. Well monitoring and surveillance are the primary methods by which base pro-duction is secured. Previously, VICO wells were monitored by frequent pro-duction tests, mostly depending on human surveillance.

In the Renewal Plan, automated real-time monitoring well surveillance of wellhead-pressure and flow-rate data on each well was impemented. This real-time wellhead surveillance (RTWHS) transmits the data from the wellsite to

the VICO server; then, it is stored in a data base. Operators and production en-gineers could monitor the behavior of the well in real time. This system has proved to minimize well downtime, lead-ing to aggressive well reactivation.

This installation has also become standard for new wells. Currently, 90% of VICO’s active wells are equipped with RTWHS.

Aggressive Drilling Plan. The multidis-clipinary team concluded that remain-ing potential reserves are high, even though the PSC acreage has produced 70% over 40 years. New well develop-ment can be carried out by means of conventional-well, grid-based-drilling, and cluster-drilling methods.

Previous VICO completion design used single-/dual-string 2⅞-, 2⅜-, and 3½-in. completion with multipackers installed for single/multiple perforation. This led to commingled production from several zones, reducing the maximimum potential of each individual zone. The single 4½-in. monobore offered bet-ter reservoir management and a single production tubing, with the annulus ce-mented up to surface. The downside of the 4½-in.-monobore completion, how-ever, includes less flexibility to catch up with the deliverability target.

A dual 3½-in.-monobore comple-tion was implemented, and flexibility of the production strategy was achieved by use of long strings for maximizing reserves recovery, and short strings for optimizing production. This dual 3½-in. monobore has become a stan-dard well completion in VICO Indone-sia’s portfolio.

Aggressive Rigless Development. While maintaining base production, op-timization of existing wells is the prior-ity for meeting the production target. To that end, on a routine basis, the multi-

Optimum Development in Mature Fields: Sanga-Sanga Assets, Indonesia


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 158716, “Renewal Plan: Efficient Strategy for Optimum Development in Mature Fields—A Success Story From Sanga-Sanga Assets, Indonesia,” Andre Wijanarko, Bambang Ismanto, and Robhy Permana, VICO Indonesia, and Italo Pizzolante, Eni, prepared for the 2012 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 22–24 October. The paper has not been peer reviewed.

MFW158716.indd 86 12/12/13 1:37 PM

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disciplinary team evaluated potential wells along with underperforming wells, idle wells, and bypassed zones.

For underperforming wells, a de-tailed review was conducted to determine the causes of production decline. Static/ flowing bottomhole and production- logging data are useful in this task; nodal-analysis and material-balance software were used to support review findings. For idle wells, a detailed re-view is performed to evaluate existing producing zones and remaining poten-tial zones.

A bypassed zone is a potential pro-ductive zone that was not interpreted as a hydrocarbon zone in the past. These zones are reviewed on the basis of log data, offset-well production, and mud-log data compiled during drilling.

Low-Permeability Exploitation. One of the Renewal Plan objectives is to re-gain production and increase the re-serves recovery from low-permeability zones. Because most of the fields have reached a mature stage at which the shallow and middle layers have been

produced and depleted significantly, the remaining reserves are spread over the deeper low-permeability sands, where previous completion approaches have not effectively depleted the reserves.

A comprehensive approach was identified that ranks the candidate reser-voirs for low-permeability development. Additionally, several low- permeability gas-development strategies and technol-ogies have been evaluated and execut-ed since 2006. These low- permeability technology applications pertained to horizontal wells, hydraulic fracturing, and radial drilling/jetting.

Deliquification. A large proportion of VICO’s existing well production is sub-ject to liquid loading, leading to prema-ture abandonment of producing zones; and some wells have to be in cyclic pro-duction. Liquid loading of a gas well is the inability of produced gas to re-move the produced liquids from the wellbore, leading to excessive backpres-sure on the production interval, which in turn reduces productivity. This situ-ation is influenced by tubing size, sur-

face pressure, and the amount of as-sociated liquids being produced with the gas.

Historically, VICO’s approach to well reactivation/deliquification includ-ed low-cost, low-technology solutions such as venting, cycling, gas injection, and soap sticks, used with mixed suc-cess. In 2006, in new-technology trials, the installation of capillary-string injec-tion in liquid-loaded wells was tested.

The capillary-string-injection con-cept introduces a foaming agent into the wellbore through ¼-in. capillary strings and injects the surfactant across the perforation. The foaming agent is then mixed with produced fluids, reduc-ing the density of the liquid, increasing the gas velocity, and improving the abil-ity of the well to produce liquids and have stabilized gas flow. This capillary-string chemical injection was chosen because its relatively simple application also can be implemented in a wide range of VICO’s completions (monobores, dual-string completions with nipple profiles, and selective completions pro-duced through sliding sleeves).

Fig. 1—Sanga-Sanga PSC. Fig. 2—Wellhead compressor.

0 10 20 km

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Fieldwide capillary-string-injection installation has been implemented since 2006. Currently, there are 65 capillary-string-injection installations, which have successfully main-tained liquid-loaded-well production with continuous flow (in-stead of a cyclic mode) to deliver 16 MMscf/D.

Oil Development. The aggressive drilling program in Mutiara and Pamaguan fields resulted in an increase of oil reservoirs to be produced. A gas lift system is the preferred method used to achieve artificial lift because VICO has abundant gas resources. Because monobore wells have no annulus (they are cemented up to surface), there is no gas-lift-valve/side-pocket-mandrel configuration available to introduce gas lift into the produc-tion tubing.

A solution for developing oil in a monobore well com-pletion involves use of smaller-inside-diameter coiled tub-ing (normally 1½-in. diameter) inside the production tub-ing, which includes special bottomhole assemblies (nozzle, dual-flapper check valve, and nipple). A special tubing hanger is attached to the top of the tree to hold the inserted coiled tub-ing. This application is known as permanent-coiled-tubing gas lift (PCTGL), which allows gas lift injection into the produc-tion tubing.

This method does not require the well to be recomplet-ed with a rig, thus having significant cost savings and deliv-ering desired oil production. During 2010–2011, 16 units of PCTGL were installed, successfully sustaining 3,500 B/D of oil production.

Facility Optimization. To maximize reserves recovery with the condition that most of the production comes from deplet-ed reservoirs, several attempts to lower abandonment pres-sure were made. Lowering the flowing wellhead pressure will keep the well flow above the critical and liquid-loaded rates for a longer period of time. To assist in this effort, VICO has cat-egorized four different pressure systems:

1. High-pressure compressor with an inlet pressure of 700 psi and an outlet pressure of up to 1,500 psi

2. Medium-pressure compressor with an inlet pressure of 280 psi and an outlet pressure of up to 710 psi

3. Low-pressure compressor with an inlet pressure of 100 psi and an outlet pressure of up to 320 psi

4. Very-low-pressure (VLP) compressor with an inlet pressure of 25 psi and an outlet pressure of up to 120 psi

Before 2006, only a few VLP compressors were available. Consequently, some of the wells prematurely ceased flowing because of an inability to flow in lower-pressure systems. Sev-eral studies were performed to determine how to lower field- abandonment pressure, improve well productivity and re-serves, and better manage a gas field’s natural decline. These studies resulted in additional VLP compressors and indeed in the categorization of another compressor with pressure lower than that of a VLP system—called an extreme-low-pressure compressor (wellhead compressor). Having wellhead compres-sors installed at the wellsite reduces the flowing wellhead pres-sure further (Fig. 2). JPT

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Otto Luiz Alcantara Santos, SPE, is the coordinator of the well-control training and certification

program of Petrobras, instructor of deepwater and advanced well-construction technologies at Petrobras University, and a senior technical advisor of Petrobras. He holds a BS degree in civil engineering and an MS degree in petroleum engineering from the Colorado School of Mines and a PhD degree in petroleum engineering from Louisiana State University. He has written several technical papers in well-construction technology, especially on well integrity and directional and horizontal drilling, and he coauthored the book Directional Drilling. Santos is editor of the SPE book Drilling and Production Operations in HPHT Wells. He was an SPE Distinguished Lecturer for 2009–10. Santos is the current chairperson of the SPE Bahia/Sergipe Section and has served on several SPE committees. He is a member of the JPT Editorial Committee.


SPE/IADC 163417 Detection of Kicks Prompted by Losses and Direct-Measurement Well-Control Method Through Networked Drillstring With Along-String Pressure Evaluation by Daan Veeningen, NOV IntelliServ

SPE/IADC 163445 Feasibility Study of Applying Intelligent Drillpipe in Early Detection of Gas Influx During Conventional Drilling by Karimi Vajargah, The University of Tulsa, et al.

SPE/IADC 163438 Analysis of Potential Bridging Scenarios During Blowout Events by S.M. Wilson, Apache, et al.

Statistics on well-integrity incidents are difficult to find in the literature. There are some examples of kick and blowout events, but normally they are scarce and focus on the number of incidents and their root causes. There is, however, one example of statistics that has been inspiring me throughout the years when I prepare my lectures on how we can drill, complete, and produce wells safely. It is one that is presented in the excellent textbook on high-pressure/high-temperature wells published by Aber-deen Drilling Schools that shows human factors related to offshore blowouts. On the basis of those statistics, I divided these factors into four groups: (1) inattention to operations (25%) and inadequate supervision/work supervision (20%); (2) improper maintenance of equipment (20%) and improper installation/inspection of equipment (2%); (3) inadequate documentation (2%) and improper method or procedure (11%); and (4) improper planning (12%). No direct human error involved was stated for the remaining 8%. Here, I will show how these factors can be addressed to make a well-integrity system efficient.

The first group represents 45% of the human factors related to offshore blow-outs. One efficient way to address it is through training and assurance of personnel competence. A well-integrity system implemented by any company of the oil industry can be robust only if it strongly considers this aspect. Regrettably, this topic only bare-ly appears in the literature and conferences on the topic of well integrity. Recently, the International Oil and Gas Producers Association presented appropriate recommenda-tions for technical enhancements to well-control training, examination, and certifica-tion that can be extended to other activities related to well integrity.

The second group encompasses well-equipment-related issues. An adequate well-integrity system should have the necessary safety barriers in place, understood, test-ed, verified, and maintained. It should also have proper contingencies in case of failure of these primary barriers.

The third group refers to documentation. Currently, there is a strong movement toward elaborating or revising regulations related to well integrity by entities such as the American Petroleum Institute and the International Organization for Standardiza-tion. Creation of new or improvement of existing design and operational procedures that result in safer operations throughout a well’s life cycle is mandatory for an effec-tive well-integrity system. It is also important that any well-integrity anomaly be docu-mented, analyzed, and transmitted to all involved parties.

The last group refers to planning. Many well failures are a result of poor well design and operation planning. A strong well-integrity system should rely deeply on approaches such as risk assessment, management of changes, action plans, and design basis. JPT

TECHNOLOGY

well integrity

3WIFocusJan.indd 90 12/12/13 8:53 AM


The purpose of this work is to investigate typical fracture

and collapse models with respect to accuracies in the input data. Uncertainties in the input data will be considered to show how they contribute to the cumulative uncertainties in model predictions. In this approach, the input parameters are assigned appropriate probability distributions. The distributions are then applied in the wellbore-stability models. By means of Monte Carlo simulation, the uncertainties are propagated and outputs, which follow a probability distribution, are generated.

IntroductionWellbore-stability analysis is necessary for safe drilling operations, especially now that oil and gas operators venture into more-challenging environments. A wide range of parameters is required for accurate study, many of which are subject to uncertainties caused by measurement errors. Error also can be introduced into data through the methods of interpreta-tion used. Epistemic error, arising from imperfect human knowledge of a system, is another source of input uncertainties. Analytical models used for wellbore- stability analysis are also often associ-ated with uncertainties. Mathematical modeling algorithms only try to approxi-mate physical processes and are not true representations of the problems under study. The modelers should be aware of the imprecision and limitations of these physical models. Thus, output uncertain-ty stems from the variations in input data

and uncertainties caused by wellbore-stability-modeling processes.

Expected values give no information about uncertainty. Deterministic estima-tion of the downhole pressure limits pro-vides only single-point values that lack variability information. Instead, proba-bility distributions can be used. With this approach, cumulative uncertainties in the output predictions can be quantified, leading to a more-informed decision.

In-Situ Stress FieldFor a given formation, the starting point in wellbore-stability analysis is the in-situ or pre-existing stress state. Knowledge of the stress state is key to handling borehole problems such as fracturing, lost circula-tion, collapse, and sand production. The in-situ stress state is normally assumed to coincide with vertical and horizontal di-rections. In relaxed depositional basins, the values of these horizontal stresses are usually lower than those of the vertical stress. The horizontal-stress magnitudes, however, may exceed those of the vertical stress in strongly tectonic regions.

A stress state can be defined as normal- fault, reverse-fault, or strike/slip-fault state of stress. The normal-fault stress state is assumed in this work. If the magnitudes of the three principal stresses and the direc-tion of one of the stresses are known, then the stress state can be specified. The stress concentration is usually very high around the borehole wall. This effect decreases rapidly away from the hole. At a long dis-tance from the wellbore, the principal in-situ stresses are undisturbed and lie along their in-situ directions.

Wellbore InstabilitiesWellbore instabilities include such phe-nomena as breaking of intact rock around the wellbore because of high stress con-centration or sudden temperature varia-tions; loosening of rock fragments; and fracture extension from the wellbore into the formation, sometimes with a signifi-cant loss of drilling fluid. They also con-sist of such mechanisms as failure of rock around the borehole because of inter-action with drilling fluid, squeezing of soft rocks such as salt and shales into the wellbore, and activation of pre-existing faults that intersect the wellbore.

A significant amount of break-outs resulting from mechanical failure around a wellbore can cause severe sta-bility problems such as excessive torque and drag, sudden increase in bottomhole pressure, and stuck pipe. By application of good drilling procedures, cavings can be removed efficiently and safely. How-ever, borehole instability remains the major cause of lost drilling time and lost downhole equipment.

Mechanisms of Wellbore Failure. Shear Failure. The von Mises yield condition and the Mohr-Coulomb shear-failure cri-terion are the most commonly used hy-potheses for evaluating rock shear fail-ure. The von Mises condition considers the three principal in-situ stresses as ac-tive participants in wellbore compressive failure. Well planners frequently use the position of the stress state relative to the failure envelope as a yardstick for evalu-ating wellbore stability.

The Mohr-Coulomb model for shear failure neglects the intermediate principal stress but captures the effect of the direc-tional strengths of shales. The maximum stress is the tangential stress, followed by the axial stress and the radial stress (well pressure). This model predicts a mini-mum well pressure that can cause well-bore collapse in the direction of least in-

Uncertainty Evaluation of Wellbore-Stability-Model Predictions


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166788, “Uncertainty Evaluation of Wellbore-Stability-Model Predictions,” John Emeka Udegbunam, Bernt Sigve Aadnøy, SPE, and Kjell Kåre Fjelde, SPE, University of Stavanger, prepared for the 2013 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Dubai, 7–9 October. The paper has not been peer reviewed.

WI166788.indd 91 12/12/13 1:46 PM


situ stress. Wellbore collapse is a result of shear failure of rock around a borehole. To prevent this from occurring during drilling, mud pressure must be such that it will effectively carry the load caused by the in-situ stresses around the wellbore.

Tensile Failure. Generally, rock for-mations are weak in tension. In most cases, the tensile strength of rock is set to zero on the premise that drilling-induced fractures initiate in flaws, joints, or pre-existing fractures around the wellbore.

The analysis of tensile failure involves application of the effective-stress concept. This implies that a formation fails in ten-sion when the least effective principal stress exceeds the rock tensile strength. Increase in a wellbore pressure will cause the effective tangential stress to decrease. The effective radial stress remains con-stant, while the effective axial stress in-creases. At a certain well pressure, the value of the hoop stress becomes zero, and a vertical fracture initiates as the stress goes into tension. Thus, drilling-induced fractures are associated with minimum tangential stress. Critical fracture pres-sure is the well pressure beyond which a wellbore will fracture in tension.

Considering the two wellbore- failure mechanisms, the absence of suffi-cient well pressure capable of supporting the load caused by high stress concen-tration around the wellbore can lead to a wellbore collapse, but an excessive mud weight will cause borehole fracturing, sometimes with a loss of drilling fluid into the formation.

Wellbore-Stability ModelingBoth numerical simulators and analyti-cal models are used for wellbore- stability analyses. These tools do not provide accu-rate descriptions of geological processes, mainly because of limited human knowl-edge of subsurface strata. However, on the basis of geomechanical principles, drilling engineers can estimate fracturing and collapse pressures by use of mathe-matical approximations, which describe the relationships among input variables.

In this work, a vertical-well con-figuration is considered. The formation around the wellbore is assumed to be lin-early elastic. Therefore, complex mate-rial behavior such as nonlinear elastic-ity or elastoplasticity is not treated. If an inclined wellbore is assumed, the in-situ

stress field must reflect borehole inclina-tion and direction.

Uncertainty in the Input DataMeasurement and interpretation errors are the major causes of input-parameter uncertainties. This section briefly pres-ents some important parameters affect-ing wellbore stability and their assumed measurement or prediction uncertainties.

Pore pressure can be estimated with direct measurements. For a very-low-permeability rock such as shale, indirect methods, which use drilling data and well logs, are used. If a nonpermeable barrier exists over an interval, a discontinuous pore-pressure profile is expected. There-fore, higher uncertainty is associated with the indirect pore-pressure measure-ments than with the direct estimations.

We have mentioned that the determi-nation of the in-situ stress state is crucial to wellbore-stability analyses; stress mag-nitudes will ultimately affect the accuracy of the model predictions. These should be considered uncertain parameters because there are no existing methods to measure the stresses accurately. However, the in-situ stresses can be estimated by use of several methods. The overburden stress is calculated by integrating the bulk density of drilled cuttings over the depth interval, with values obtained every 30 m. At great-er depths, density or sonic logs are used to estimate overburden stress.

The minimum horizontal stress can be estimated with leakoff-test (LOT) data, by interpreting the slope change (deviation from linearity) on an LOT plot when pres-sure drops after a mud pump is stopped. In a relaxed depositional environment, equal horizontal stresses are normally assumed. The value of maximum horizontal stress is more difficult to estimate with direct methods. With the inversion technique, an improved accuracy in the estimations of both magnitude and direction of the two horizontal stresses can be obtained. In addition, the rock-mechanical properties such as cohesive rock strength and rock-friction angle are often derived from indi-rect measurements by interpreting sonic logs. There is higher uncertainty in the es-timation of cohesive rock strength than in the estimation of internal friction.

For a discussion of the example case and simulation results, please see the complete paper.

Sensitivity AnalysisA sensitivity analysis is conducted to as-certain input factors that are most re-sponsible for output variability and that require further research. A mod-eler can thereby justify whether input- parameter estimates are accurate enough for a model to give reliable predictions. If not, more work will be directed toward improving the estimations of these un-certain parameters.

The sensitivity analysis is required to understand how the model predictions re-spond to changes in input variables, there-by complementing the analyses presented so far in this work. This allows determi-nation of the parameters that contribute most to the cumulative uncertainties in the critical fracture- and collapse- pressure predictions. The results from the analyses will be useful when calibrating the models against offset-well data.

For a full discussion of the differen-tial method used in this analysis, please see the complete paper.

Monte Carlo Sensitivity Analysis. In this analysis, the input parameter that is considered uncertain assumes a prob-ability distribution, while other param-eters are treated as fixed factors. This is done to quantify the individual contri-bution of each parameter to the cumu-lative output variances. The base-case scenario, in which all the input data are treated as random variables, serves as a standard for measuring the degree of the output variability caused by the uncer-tainty in a given parameter. In the prob-abilistic approach, only triangular distri-bution will be considered.

In each run, both the uncertain pa-rameter and fixed factors are applied in the wellbore-stability models. The out-puts, which follow a probability distri-bution, are generated after 600,000 simulations. In the results, the fracture-pressure distribution for the minimum-horizontal-stress uncertainty has the highest spread or variance compared with other input parameters; therefore, minimum horizontal stress is the most influential factor. For the collapse pres-sure, the sensitivity determined for the cohesive rock strength shows that that parameter is the most important input factor responsible for the uncertainty in the pressure. JPT

WI166788.indd 92 12/12/13 1:46 PM

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Deepwater cementing becomes increasingly challenging as

drilling operations move to greater water depths and more-remote locations. Before the first exploration well for an operator offshore Tanzania was spudded, an extensive cementing-operations risk analysis was performed. The risks determined were low temperatures at seabed, unconsolidated formations close to seabed, potential shallow gas, and likely presence of hydrates. To drill further sections successfully, objectives were identified as zonal isolation across the shallow-flow and hydrate zones, cementing back to seabed, and good cement around the casing shoe.

IntroductionBlock 2 (Fig. 1) is located south-east of Tanzania’s capital, Dar es Sa-laam. The water depths in Block 2 vary from 1000 to 3000 m. The target is an excellent-quality sandstone gas reser-voir with very large potential. The sea-bed consists of soft clays and silts with minor sandy intervals. Shallow hazards were identified for this block from seismic data.

Preparation for the exploration phase started in 2007 when the license for Block 2 was awarded. Two explo-ration wells have been drilled in Block 2 offshore Tanzania to date. The wells were drilled in ultradeep water, with respective water depths of 2419 and 2627 m. Both wells were drilled suc-cessfully and have found commercial gas reserves.

Well DesignThe well design for both wells was jetting a 36-in. conductor casing to provide suf-ficient well-bearing capacity. The surface casing was set deep enough to isolate all shallow zones with potential hydrates and shallow water and gas flow. The in-termediate string was set above the top of the target reservoir, and the reser-voir was drilled and plugged after the reservoir was evaluated. Both explora-tion wells were drilled vertically to total depth. The riserless section was drilled

with seawater and water-based mud, while the deeper sections were drilled with a synthetic-based mud.

Challenges The main challenges for the two wells were related to the great water depth (low fracture gradients and low temperatures) and the risk of encountering hydrates and potential shallow flows, which would need to be isolated by the surface casing.

Gas Hydrates. Gas hydrates are crystal-line solids (Fig. 2). They consist of a gas molecule surrounded by a cage of water molecules. Many gases have molecular sizes suitable to form hydrate, including such naturally occurring gases as car-bon dioxide, hydrogen sulfide, and sev-eral low-carbon-number hydrocarbons,

Zonal Isolation Through Gas Hydrates Offshore Tanzania


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163462, “Zonal Isolation Through Gas Hydrates Offshore Tanzania,” by J. Vølstad and T. Tveit, Statoil, and P. Aguilar, N. Hurtado, and M. Bogaerts, Schlumberger, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5–7 March. The paper has not been peer reviewed.

Fig. 1—Location of Block 2, offshore Tanzania.

Tanzania

Block 2

Dar es Salaam

Zafarani

Lavani

0 50 km

WI163462.indd 94 12/12/13 1:47 PM


but most marine gas hydrates that have been analyzed are methane hydrates. Gas hydrates are naturally found when three conditions are found at the same time and place: (1) the presence of gas- hydrate formers, (2) the presence of water, and (3) pressure and temperature within the domain of stable gas hydrates.

Shallow Flow. The risk of shallow flow was highlighted for both wells after the interpretation of seismic data. Thin sand layers were identified as potential zones for shallow gas. Also, the slight risk of shallow water was identified for each well.

Remote Operations. Logistics were very challenging because of the remote-ness of the operations. Engineering sup-port for the project was provided out of Dar es Salaam. The operating base is in Mtwara, located in the south of Tanzania. Slurry laboratory testing was initially performed at service-company laboratories in Cape Town, South Af-rica, and Aberdeen. During the project, the laboratory in Mtwara was upgraded and became able to perform most tests required for deepwater cementing. All equipment and materials had to be or-dered in advance; lead times for com-mon items are 3 to 6 months and are lon-ger for specialty products.

Cementing DesignA study was initiated to determine optimum slurry design and ensure that annular tem-peratures stayed within the gas-hydrate- stability zone during cement placement and the cement-hydration period.

Slurry Design. The formation-pressure and -strength prognosis indicated a nor-mal pore pressure of 8.6 lbm/gal in the upper sections of the hole. The over-

burden and fracture gradient followed a normal trend, with an expected fracture gradient of 8.6 lbm/gal at seabed and 9.8 lbm/gal at the surface-casing setting depth. To avoid losses close to seabed, the density of the lead slurry was opti-mized at 12.0 lbm/gal.

The temperature at seabed was de-termined to be 3°C. The geothermal gra-dient in the first 1000 m below seabed was 5.4°C/100 m, and the gradient would decrease after that. The expected bot-tomhole static temperature (BHST) at the surface-casing setting depth was 34°C. Computer simulations showed a BHST of only 7°C. For the cement to develop com-pressive strength quickly, to be able to con-tinue drilling operations, a neat 15.8-lbm/gal tail slurry was placed around the shoe. Special low-temperature additives were used to enhance the development of com-pressive strength at low temperatures.

The slurry design for the surface casing needed to (1) be lightweight to avoid losses, (2) develop quick compres-sive strength at low temperatures, (3) be gas-tight to overcome the potential shallow-flow hazards, and (4) have a low heat of hydration to avoid destabiliz-ing the hydrates. The main focus during the early design stages was on select-ing the proper slurry for cementing the gas- hydrate zone.

Higher temperatures or lower pres-sures than those under equilibrium can destabilize gas hydrates. This can happen during and after cementation. The param-eters to consider include the following:

◗◗ The total heat released during cement hydration, which depends on the amount of reactive material per volume of slurry

◗◗ The speed at which the heat is released, which depends mainly on wellbore temperature and additives

◗◗ The dissipation flow, which depends on well geometry and fluid and formation thermal properties

A number of techniques exist for determining the heat of hydration of a setting-cement system, some of them being standardized. Studies show that for the same slurry density, the heat of hydration of extended slurry is 1.5

times higher than that for an optimized- particle-size-distribution (OPSD) cement or for a foamed cement, both of which have very similar heat of hydration.

Some guidelines exist for design-ing slurries for the case of shallow-flow zones. The slurry must be stable, with zero free fluid and no sedimentation. It must have good fluid-loss properties; less than 50 mL/30 min is generally rec-ommended. The transition of the critical hydration period must be minimized for the cement to develop from the critical static gel strength (CSGS) to a static gel strength of 500 lbf/100 ft2 in less than 45 minutes. The OPSD blend was optimized to meet these criteria. Liquid additives were used to provide low fluid loss at the anticipated bottomhole circulating tem-perature (BHCT).

On the basis of these results, an OPSD-cement system was selected to cover the hydrate zone offshore Tanzania.

Temperature Simulations. To en-sure that the temperatures in the an-nulus stayed within the stable zone, the temperature in the annulus of the 26-in. open hole (OH) was simulated. Ocean temperatures and current ve-locities were derived, and a worst-case, higher-than-actual geothermal gradient of 6.4°C/100 m was assumed. Actual job design and slurry properties were used for the simulation, and an experimental measured heat of hydration was used to estimate the change in temperature dur-ing the cement-setting phase.

Results for the 26-in.-OH section show that the upper bound slightly ex-ceeds the gas-hydrate-transition temper-ature in the case of very high pore-water salinity. Thus, unless unusual salinity ex-ists, the risk of gas-hydrate dissociation while cementing the 26-in.-OH section appears to be low.

ExecutionZafarani 1. After jetting the conductor casing, the 26-in.-OH section was drilled from seabed at 2627 m to 3098 m, with a maximum deviation of less than 1°. The top section was drilled with seawa-ter to minimize the disturbance of the hydrates. Extra care was given to keep the salinity of the seawater and sweeps as low as possible to avoid dissolution of hydrates. The well was displaced to a

Fig. 2—Methane hydrates.

WI163462.indd 95 12/12/13 1:48 PM

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weighted pump-and-dump (PAD) mud before drilling through the potential overpressured zone.

Because the wellbore was drilled nearly vertically, centralization focused on a good shoe and good standoff across the potential flow zones and the hydrate interval. The casing was centralized by use of five centralizers, with a minimum standoff of 61%.

The cement job was executed as an inner-string job. The casing was run with seawater, and, after landing, the inner string was displaced with PAD mud. After landing the casing, the well was circu-lated to break any gels in the PAD mud to ensure good flow around the casing. Volumes were based on OH plus 150% annular excess. A volume of 150 bbl of a 10.9-lbm/gal weighted spacer was pumped ahead of the slurry, followed by 510 bbl of gas-tight 12.0-lbm/gal OPSD-blend slurry. A 144-m section of tail slurry was placed around the casing shoe. Soft-ware simulation showed good cement coverage across the entire wellbore.

Lavani 1. A pilot hole was drilled before spudding to investigate the presence of overpressured sands; when none were encountered, the section was drilled with seawater. Only the last 15 m of the hole was drilled with a 10.9-lbm/gal PAD mud. The 26-in.-OH section was drilled from seabed at 2419 m to 3015 m, with a maximum deviation of 1.4°.

The casing was centralized by use of 20 centralizers, with a minimum stand-off of 59%. The casing was run with sea-water, and, after landing, the inner string

was displaced with PAD mud. After land-ing the casing, the well was circulated to break any gels in the PAD mud to ensure good flow around the casing.

The cement job was executed as an inner-string job. Volumes were based on OH plus 150% annular excess. A volume of 150 bbl of a 10.9-lbm/gal weighted spac-er was pumped ahead of the slurry, fol-lowed by 797 bbl of gas-tight 12.0-lbm/gal OPSD-blend slurry. A 100-m section of tail slurry was placed around the casing shoe. Software simulation showed good cement coverage across the entire wellbore.

Cement-Job EvaluationZafarani 1. The job was executed as per design, except for a small pump-rate de-crease caused by bulk-transfer conditions on location. Cement returns were con-firmed by a remotely operated vehicle (ROV) during the job (Fig. 3), and no gas was observed during the setting of the cement. The wellhead was stable, and the blowout preventer (BOP) was con-nected without problems. The formation- integrity test showed a value sufficient to allow drilling of the next section to con-tinue safely without any remedial work.

Lavani 1. The job was executed as per de-sign. Cement returns were confirmed by the ROV during the job, and no gas was observed during the setting of the ce-ment. The wellhead was stable, and the BOP was connected without problems. The leakoff test showed a value suffi-cient to allow drilling to continue, en-abling the elimination of one intermedi-ate string from the well design. JPT

Fig. 3—The ROV confirms cement returns to seabed on Zafarani 1.

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WI163462.indd 97 12/18/13 8:51 AM


ADMA-OPCO had integrity problems in one of its gas wells,

and abandonment was the only option available to restore the integrity of the offshore multiwell jacket and revive adjacent wells. Integrity problems included oil/gas bubbles observed on the seabed around the conductor pipe and high sustained pressures in the outer cemented casing annuli. Because the leak was determined to be located outside the casing, the perforation of several intervals was required. Some of the intervals were perforated through three casing strings, and the rest through four strings of casing, before being squeeze cemented.

BackgroundThe example well, designed as a 7-in.-monobore gas-production well (see Fig. 1), was due for abandonment. The surface leaks in the different casing annu-li had to be resolved before proper aban-donment could occur. It was clear from the prejob analysis that cement-squeezing operations would be required at different depths through three and four casing an-nuli. Techniques for exposing these annu-li for remediation included underreaming with a milling tool, abrasive jetting, and perforating. Underreaming would have been a very costly operation, and abrasive jetting is not reliable to penetrate through more than one casing string; therefore, perforating was chosen as the method for accessing the required annulus.

Perforating through four strings of casing is not typical, and many questions were raised concerning the reliability of this technique and how its effectiveness would be measured. With the need to ac-cess up to four different annuli, conven-tional circulation and pressure-testing techniques could not confirm that all cas-ings had been penetrated. Modeling and testing were performed to improve confi-dence in this technique.

Perforating Gun and Charge SelectionModeling. A 4½-in. gun was selected for carrying a premium deep- penetration charge in the 7-in. liner. Two charge op-tions were available for this: a 5-shots/ft (spf) 72°-phase version carrying 38.8-g HMX (a nitroamine high explosive) per-foration charges and a 12-spf 45°-phase version carrying 22-g HMX charges. The model was set up with the casing and other well parameters and run with various perforation-charge/gun combinations.

The modeling results show that all charges in all phases will penetrate the four casing sizes; however, the outer-most-casing entry-hole size with the 12-spf gun is very small, ranging from 0.16 to 0.09 in.

Laboratory Testing. There was con-cern over the modeling results because the casing entry-hole prediction is not considered accurate beyond two cas-ing strings; therefore, to improve confi-dence in the results, a series of tests was

conducted in the laboratory. The labora-tory tests were set up to simulate offset casing, and each phase of the perforat-ing gun was tested with the same types of charges that would be used in the field.

For the 5-spf 72°-phase perforat-ing gun, shots were made at 0, 72, and 144° phases; for the 12-spf 45°-phase gun, shots were made at 0, 45, 90 135, and 180° phases. Single shots were made in the desired phase directions.

The results confirmed the necessi-ty for performing the physical testing to verify the charge performance under these actual field conditions. The 12-spf gun is unsuitable because it does not penetrate through the outer casing in the 180°-phase shot, and the entry-hole sizes for the other phases are unacceptable.

The 5-spf results were more encour-aging but also show considerable devia-tion from the model results in the 9⅝- and 13⅜-in. casings.

The discrepancies between the model and laboratory-test results are not

Perforating Through Casing Strings To Remediate Annulus Gas Leak


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166729, “Perforating for Squeeze Through Four Casing Strings To Remediate Annulus Gas-Leak Problem,” by Mohamed El-Sayed Ibrahim, SPE, Ahmed Khalifa Al-Neaimi, SPE, Mohamed Abdelsalam Hassane, SPE, Abdul Salam Mohamed Al-Mansoori, SPE, Shanof Mohamed, SPE, and Omar Al-Mutwali, SPE, ADMA-OPCO, and Alan Salsman, SPE, Schlumberger, prepared for the 2013 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Dubai, UAE, 7–9 October. The paper has not been peer reviewed.

Fig. 1—Casing diagram.

Annulus: ABCD

Formation 1

Reservoir A

Reservoir B

Reservoir C

Sea Level

Sea Bed

30 in.(Depth 1)

7-in. Casing (Depth 5)

9⅝-in. Casing (Depth 4)

18⅝-in. Casing(Depth 2)

13⅜-in. Casing (Depth 3)

13⅜-in. DV

9⅝-in. DV

WI166729.indd 98 12/12/13 1:46 PM


unexpected. At the moment, the three- and four-casing-string entrance-hole prediction in the model is based on extrapolation techniques only. This will be updated in the model once more tests are completed.

On the basis of these results, the 5-spf 72°-phase gun with the 38.8-g HMX charge was chosen for this job.

Gun Phasing. The requirement for the most-powerful deep-penetrating perforating charge to be run meant that the phas-ing had to be a compromise. The 5-spf gun is available in only the 72° phase, as indicated in Fig. 2. A gun system could have been developed with some engineering modifications, but time and financial constraints prevented this. To improve the effec-tive phasing of the gun system and increase the possibility that all channels would be accessed, special orienting adapters were used. These adapters have locking keys that allow for a 90° off-set between the perforating guns. The perforating intervals were 20 ft in length, so with four 5-ft-long perforating guns three of the orienting adapters could be run. This would then offset the phase between the guns by an effective phasing of 18°. A side view of the assembled gun with the adapters is shown in Fig. 3.

Job ExecutionSeveral zones were selected to be perforated and squeezed: two zones with three casing strings and two zones with four casing strings. The guns were loaded in the onshore gun shop and shipped to the rig, where they were assembled at the wellsite as four 5-ft gun assemblies. Because of local regulations requiring pipe in the well at the time of perforating operations, these guns were run on drillpipe with a tubing-conveyed-perforating pressure- actuated firing head and were shot in overbalanced conditions.

To further improve the chances of reaching all of the leak paths behind the pipe, each zone was perforated twice, making the final shot density 10 spf in the perforated interval. There was no attempt made to alter the phasing of each run; thus, the relative shot phasing for each run was random and was likely to be different from that of the initial run, further improving the chances of a successful squeeze job.

Special fine cement designed for cement-squeeze opera-tions addressing small channels was pumped at an acceptable rate into the perforations and then allowed to set.

The first perforating operation was though three cas-ing strings in which two zones were shot 30 ft apart to allow

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Fig. 2—72° phasing.

0°

WI166729.indd 99 12/16/13 7:51 AM

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for a circulation squeeze. Once the sec-ond gun was removed from the well, a cement-squeeze pipe string with packer was run and a circulation squeeze and block squeeze were executed. This oper-ation was repeated until the zone exhib-ited a good pressure test.

The second and third perforating operations were through four casing strings, and a block squeeze was carried out. After the cement was set, a pres-sure test was performed in the squeezed-off intervals, which often showed an in-complete squeeze. Consequently, more cement was pumped to squeeze the re-maining channels. This operation was re-peated until the interval showed a good pressure test, confirming that the zone was sealed.

ResultsCare was taken to completely seal off each of the four zones that were squeezed. While it was not possible to determine the cement placement with respect to the different annuli, an assumption was made that the special squeeze-type ce-ment together with the multisqueeze method would place cement into the channels where gas was leaking and would seal them.

The annulus pressure was moni-tored during the operations and contin-ued to be monitored after the job. The pressure was monitored for a period of 3 months after the job was completed. The results prove that the abandonment job was successful and that the objectives were achieved. JPT

Fig. 3—Side view of the four-gun assembly.

5-ft guns each offset by 90°

90° offset adapter

180° offset adapter

270° offset adapter

WI166729.indd 101 12/12/13 1:46 PM


Win Thornton, SPE, is vice president of decommissioning, global projects organization, at BP. He has more than 35 years of

experience in offshore construction and decommissioning projects working as an operator for BP, Chevron, and Oxy; a contractor from Brown & Root and WorleyParsons; and a consultant for Winmar and TST. Thornton holds a BS degree from the Georgia Institute of Technology and an MS degree from the University of Houston. His recent work includes offshore decommissioning and reuse projects in the Gulf of Mexico, west Africa, California, Alaska, southeast Asia, and South America. Thornton has championed the environmentally sound and cost-effective disposal of obsolete platforms through placement in state-sanctioned “Rigs to Reefs” programs. He is a member of the JPT Editorial Committee.


IPTC 16945 Environmental Liabilities in the Oil and Gas Industry and Life-Cycle Management by Lian Zhao, Integrated Environments, et al.

OTC 24461 Advances in Autonomous Deepwater Inspection by D. McLeod, Lockheed Martin, et al.

SPE 161556 Axis of Success: A Unique Professional Plug-and-Abandonment Project in a Populated Town Area by Hazem Abdelsalam, ADCO, et al.

Industry perceives decommissioning projects as more risky and uncertain than capi-tal projects. Several recent decommissioning projects delivered in an immature mar-ketplace seem to support this view. What can be done to change this perception and enable delivery of safe and cost-effective decommissioning projects?

I have always been a fan of this quote from Irving Fisher: “Risk varies inverse-ly with knowledge.” I believe it can provide insight into a strategy that can improve the delivery of decommissioning projects. What can be done around decommission-ing projects to gather knowledge of the asset to facilitate better planning and delivery and reduce the risk and uncertainty associated with decommissioning? The select-ed papers and additional reading listed here illustrate the use of knowledge to plan decommissioning more effectively and to understand the risks associated with select-ed end states. The following are a few thoughts on the use of knowledge to reduce risk and uncertainty in decommissioning:

◗◗ Decommissioning differs from a capital project in that we know (or think we know) what the asset looks like. The critical uncertainty is the condition of that asset at end of life. What diagnostic information do we gather routinely over the life cycle that can provide clarity on the condition of that asset for decommissioning? Perhaps we need a key performance indicator analogous to front-end loading in capital projects that addresses the quality of our decommissioning and condition knowledge of that asset.

◗◗ Identify the responsible party in an organization for gathering, distilling, and using asset knowledge for decommissioning. Asset information comes from various sources over the life cycle of the asset but needs a decommissioning set of eyes to identify and manage these risks. An analogy could be how we typically view and manage regulatory or asset-integrity information. This is an accountability that spans the life cycle of the asset through to decommissioning.

◗◗ When planning the actual decommissioning work, identify and perform diagnostic work in cooperation with the supply chain as part of your market-engagement strategy. It is better to know the condition of what needs plugging and decommissioning than to find out halfway in. The unknowns become planned work activities instead of risks. This optimally is a cooperative effort between the owner and contractor to identify and manage uncertainties of the project, not just a set of contractual terms and conditions.

◗◗ Share detailed experience, case studies, and lessons learned through professional forums such as SPE. JPT

TECHNOLOGY

decommissioning and abandonment

4DAFocusJan.indd 102 12/12/13 11:08 AM


Advances in modeling techniques allow quantitative prediction

of long-term trends in cuttings-pile characteristics and environmental risks, providing firm direction in mitigating risks. Modeling involving fluid dynamics, soil mechanics, scientifically verified 3D dispersion modeling, contaminant degradation, and seabed recovery was used in several scenarios: the extant pile, moving the pile across the seabed using suction pumps, backflush discharges related to retrieving the pile, and disturbance from remaining jacket footings ultimately falling into the pile after several hundred years.

IntroductionThe Murchison platform is located in 156 m of water in the northern North Sea and is operated by CNR International. Drilling operations had been conduct-ed at the field since the 1970s, ending in 2008. Discharges of drill cuttings and drilling mud have resulted in the forma-tion of a drill-cuttings pile beneath the platform jacket structure. Between 1980 and 2000, oil-based muds were used and oil-contaminated discharges took place in line with normal permitted opera-tions, and the cuttings pile now in place is consequently oil-contaminated. Fig. 1 shows the location of the Murchison plat-form and the local bathymetry, and Fig. 2 illustrates the jacket base.

The Convention for the Protection of the Marine Environment of the North-East Atlantic (OSPAR) Commission Rec-ommendation 2006/5 sets out a manage-ment regimen for such oily-cuttings piles,

depending largely on thresholds against which the level of pollution attributable to a historical cuttings pile may be measured in order to determine whether the level of pollution could be significant. An assess-ment of the Murchison pile was submit-ted to the commission in 2008 as part of the regulator’s implementation report, concluding that the Murchison pile did not exceed the relevant criteria and that it could be left to degrade by natural pro-cesses. For those piles that can be dem-onstrated to have characteristics below OSPAR thresholds, the recommendation states that no further action is required and that the cuttings piles may be left in situ to degrade naturally.

The Murchison field is in the process of being put forward for decommission-

ing, and the assessment made in 2008 regarding the rate of oil loss and the per-sistence footprint has been re-evaluated. By use of records of the discharges made from the platform, survey data from the Murchison cuttings pile, and industry data sources on the composition of drill-cuttings piles, a model of the existing pile has been constructed and used to under-stand the present condition and long-term fate of the pile.

ApproachThe original drilling discharges were modeled by use of the dose-related risk and effect assessment model (DREAM) published by SINTEF, which incorporates the ParTrack submodel used for model-ing dispersion and settlement of solids. The model predicts the fate of materials discharged to the marine environment.

DREAM can also calculate an esti-mate of risk to the environment by use of a metric known as the environmental-impact factor (EIF), based on the ratio of the predicted environmental concentra-

Modeling Options for Drill-Cuttings Management


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164983, “Modeling the Options for Managing Drill-Cuttings Piles on Decommissioning,” Sean Hayes, SPE, Genesis, and Liz Galley, CNR International, prepared for the 2013 SPE European HSE Conference and Exhibition, London, 16–18 April. The paper has not been peer reviewed.

Fig. 1—Plan view and relief view of Murchison drill-cuttings pile.

–139–140–142–143–144–145–146–148–149–150–151–152–153–155–156

DA164983.indd 103 12/12/13 2:14 PM


tion to the predicted no-effect concentra-tion (PEC/PNEC ratio). A species sensitiv-ity distribution is applied to each stressor to identify a PNEC, and PEC/PNEC ratios are calculated for the individual stressors identified as relating to drill cuttings (e.g., toxicity of chemicals and oxygen deple-tion). This allows the model to combine and compare the contributions of differ-ent stressors to the overall risk, known as the potentially affected fraction (PAF). The level of 5% PAF is a generally accept-ed risk level, and as such, the EIF value is taken as the spatial extent over which the multistressor PAF exceeds 5%.

The model has been developed to calculate the dispersion and deposition on the seabed of drilling mud and cut-tings as well as the dispersion of chemi-cals in the free-water masses and has been validated in the field. The calcula-tions are based on a Lagrangian, or “par-ticle,” approach combined with a near-field plume model and the application of external current fields for time- and depth-resolved currents.

ApplicationThe data set comprises 4 years of single-point current data (1989–92) for the Murchison location at eight depth bands through the water column. The data set is repeated in the model to pro-duce currents spanning the period from 1980 to 2001. Wind-driven forcing of the surface currents is not included in the modeled currents, and the cuttings de-position in water depths of 156 m is not

expected to be affected by the shallow surface conditions. The model takes into account the thermocline and halocline. (For a detailed discussion of the Murchi-son mud and cuttings discharges, please see the complete paper.)

Oil Composition. A variety of differ-ent oil types have been used throughout the Murchison drilling program. Within each type, there might be several possi-ble formulations. There are no definitive records available to identify what was used. Therefore, assumptions have been made about the general type of oil used on the basis of the years when drilling took place (i.e., diesel-based, low- toxicity oil, and synthetic oil). Each of these ge-neric types is composed of a variety of specific oil components. Typically, these can be categorized into groups with sim-ilar properties, including aliphatic oil, benzene and alkylated benzene [ben-zene, toluene, ethylbenzene, and xylene (BTEX)], naphthalenes, and polycyclic aromatic hydrocarbons (PAHs).

ResultsRe-Creating the Extant Pile Within the Model. Predicted Sedimentation Lev-els. Predicted deposition thickness of the drill cuttings and drilling mud over an area of approximately 8×8 km around the release point is shown in Fig. 3. This indicates that the majority of the cuttings deposits are close to the discharge point while a smaller proportion distributes over a wide area to a low thickness. The

greatest accumulation of cuttings is be-neath and slightly to the southeast of the release point, reflecting the prevailing currents in the area.

Oil Concentrations in the Sedi-ment. Concentrations are predicted at the end of the discharge period, and then at a number of years subsequently (1, 2, 5, 10, and 20 years). It is possible to view each hydrocarbon type separately in the model, and it can be seen that overall, after 20 years, the concentrations of oil are still dominated by aliphatic hydro-carbons, which are an order of magni-tude higher in concentration than PAHs. The model predicts that BTEX and naph-thalenes degrade relatively quickly, and that hydrocarbons in the thinner areas of deposition degrade much more quickly than those in the deposits of several cen-timeters or more.

Mass of Oil Lost From Pile Over Time. The amount of oil loss from the pile (i.e., from all the deposition with-in an 8×8-km area around the dis-charge point) is seen to begin at a rate of 119 t/a over the first year after discharg-es ceased, dropping rapidly over time to less than 5 t/a at Year 20 and beyond. The high initial rates could reflect the rela-tively high biodegradation rates of BTEX and naphthalene and the fact that most oil reduction appears to take place in the thinner areas of deposition.

Area of Seabed With an Oil Con-centration Above 50 mg/kg. Because a gradually reducing footprint remains on the seabed, the area multiplied by the du-ration (footprint×persistence) will in-crease slowly over time. To understand whether this might, at some point in the future, reach the OSPAR criterion, the trend was translated into a power rela-tionship with time and then predicted into the future. It was calculated that the forecast of footprint×persistence over time would not exceed the 500 km2×years criterion, even project-ing over thousands of years.

Environmental Risk to the Seabed. The modeling predicts that, at the end of the simulation (i.e., the end of 2019), areas where the risk is greater than 5% are predicted to be contained within ap-proximately 1 to 2 km of the well. Over-all environmental risk is predicted to be dominated by PAH content, reflect-ing its modeled persistence and toxic-

Fig. 2—Cuttings pile and jacket base.

50

40

30

20

10

0 m

True North

Platform North

DA164983.indd 104 12/12/13 2:14 PM


ity. Oxygen depletion (and consequential increase in sulfide concentration) is also significant, reflecting the concentrations of biodegradable oil present. Other fac-tors are predicted to be much less sig-nificant, including heavy metals, burial thickness, and grain-size change.

Moving the Cuttings Pile. Because the cuttings pile obscures part of the jacket, certain jacket-decommissioning issues are contingent on the removal of the pile to allow access to the jacket.

A second modeling exercise exam-ined the effects of pumping drill cuttings from below the Murchison platform to an area on the seabed located 70 m from the center of the platform. In this scenario, the pile is modeled with a degree of deg-radation of the oil and a distinction be-tween the main layers of degraded mud on the surface, a relatively undegraded oily core, and a bottom layer represent-ing the original tophole and water-based-mud cuttings. Two pumping regimens were modeled in relation to the number of locations to which the pile is being pumped, and for each of these, a range

of water/solid ratios and work timespans was modeled to account for the uncer-tainty associated with this procedure.

Collapse of the Structural Piles. The possibility exists that, even during de-commissioning, the jacket footings may remain. A further modeling exercise was undertaken to examine the effects of disturbance of the existing cuttings pile below the Murchison platform caused by the ultimate collapse of the struc-tural piles that surround each jacket leg should both the structural piles and the cuttings pile be left in situ. This collapse is something that could happen in sev-eral hundred years’ time, given expected corrosion rates. The cuttings themselves would be significantly weathered and de-graded by this time.

An exercise in fluid mechanics was undertaken to calculate the velocity of a falling pile as it strikes the cuttings pile, taking drag into account. A second ex-ercise in soil mechanics was undertaken to model the displacement of cuttings as the energy of the falling pile is convert-ed into mechanical movement of the pile

and ejection into the water column. The approach taken was expected to lead to an order-of-magnitude estimation of the potential effects.

The majority of resuspended ma-terial was predicted to deposit within 1 km of the cuttings pile, while finer com-ponents will travel considerably farther. The peak thickness of deposition was ap-proximately 3.5 mm from a single pile failure, and 27.5 mm for all the piles fail-ing, which is predicted to occur within 40 m of the discharge point. Thicknesses rapidly diminish with distance.

For a scenario in which all the struc-tural piles collapse within 1 year of each other, risks to the seabed above a level of 5% are predicted to occur initially up to 1 km from the cuttings pile in the most-pessimistic scenario, reducing over time to within 500 m after approximate-ly 1 year. A small area of contamination is predicted to persist for more than 20 years within 200 m of the cuttings pile. This is also likely to be the area that re-tains historical contamination and there-fore might not represent a significant change to the underlying conditions. JPT

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Fig. 3—Predicted deposition pattern of the existing cuttings pile.

Sediment Thickness, mm<0.0010.001–0.010.01–0.10.1–1.01–1010–100100–1000>1000

DA164983.indd 105 12/16/13 8:37 AM


The great majority of wells do not pollute. With that fact in mind,

the purpose of this paper is to explain basic concepts of well construction and illustrate differences between single-barrier failure in multiple-barrier well design and outright well-integrity failure that could lead to pollution, using published investigations and reviews from data sets taken from wells worldwide. Ultimately, it is clear that there is absolutely no one-size-fits-all well-failure frequency.

IntroductionFor purposes of focus and brevity, this work is limited to the failure poten-tial of the constructed barriers remain-ing in the producing well after drilling (e.g., casing, cement, packers, tubing, and wellheads) and of other downhole equipment that remains part of the pro-ducing well at the handover from drilling to production operations.

Well-Design Overview: Establishing Redundant BarriersBarriers may be active, passive, or, in some cases, reactive. Active barriers such as valves can enable or prevent flow, while passive barriers are fixed struc-tures such as casing and cement. When barriers are used in series (nested one inside the other), a multiple-barrier sys-tem is created, essentially a “defense- in-depth” barrier system. Reactive barriers are invisible or unobtrusive in normal op-

erations, but they deploy a containment response when a pressure, flow-rate, or other behavior limit is exceeded. In the oil and gas industry, a reactive barrier may be a human or mechanical response to an activating or triggering event.

The difference between drilling and production-well barriers is that most pro-duction-well barriers are static (available continuously over an extended period of time, usually without requiring human observation or action), whereas most drilling and completion-activity barriers are dynamic (control is variable with time and activity). Production barriers require less-continuous monitoring compared with drilling and completion barriers that are dependent on correct human activity.

Important Concepts in Understanding Well-Construction FailureBarriers and Well Integrity. Oil- and gas-producing wells are a nested collec-tion of pipe, cement, seals, and valves that form multiple barriers between pro-duced well fluids and the outside environ-ment. Barriers are containment elements that can withstand a specific design load. These may consist of pipe that is effec-tively cemented, as well as seals, valves, and pressure-rated housings.

Multiple barriers are nested individ-ual barriers designed and built to with-stand a specific load without help from other barriers. If an inside (or outside) barrier fails, the next barrier will provide isolation so that a leak path will not form.

Well-integrity failure is an undesired result where all barriers in a sequence fail in such a way that a leak path is created. Whether pollution occurs depends on the direction of pressure differential. Be-cause subsurface pressure in many wells is actually lower inside the well than out-side, the leak path is often into the well and therefore environmental-pollution potential is minor or absent.

Risk. The definition of risk used here includes the recognition that, although there is a degree of risk in every action, the frequency of occurrence and the im-pact of a detrimental outcome create a risk or threat level that we can under-stand and accept or reject on the basis of what we believe, hopefully from an assessment of facts. When solid occur-rence numbers are not available, prob-ability is used as a proxy.

Wells are designed and built as pres-sure vessels using exact data on as many variables of the formations and produc-ing conditions as we know while con-sidering how they will change as subter-ranean forces are altered by producing or injecting fluids into rocks that have reached equilibrium in nature. One chal-lenge to well design is that every inch of a depositional formation is differ-ent from the inch above and the inch below, hence the need to design for the unknown and the worst load. Well de-sign is a geomechanical, fit-for-purpose engineering effort and definitely not a one-size-fits-all approach.

All phases of the well design must consider loads placed and forces exert-ed on the well from the first cementing operation through fracturing and to the end of production. Well-failure causes in-clude simple, one-variable induced fail-ures and more-complex failure scenar-ios. Whenever possible, a failure should be traced back to a root cause. Although examining surface failures is a practi-

Environmental Risk Arising From Well-Construction Failure


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166142, “Environmental Risk Arising From Well-Construction Failure: Difference Between Barrier and Well Failure, and Estimates of Failure Frequency Across Common Well Types, Locations, and Well Age,” by George E. King, Apache, and Daniel E. King, WG Consulting, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September–2 October. The paper has been peer reviewed. Published: November 2013 SPE Production & Operations, page 323.

DA166142.indd 106 12/12/13 2:11 PM


cal approach (in which pollution can be more quickly and unambiguously doc-umented), determining the root cause of subsurface failures, where the failed equipment cannot always be retrieved, is more difficult, and the direct or indirect environmental damage, if it occurs at all, may not be seen until months after the incident. The most important element of risk control is to prevent barrier failure by predicting performance of barriers in any operating condition.

To work with risk requires an as-sessment of the impact and the probabil-ity of an undesirable outcome. For this reason, the actual expression of risk must be made on the basis of a quantitative risk assessment and may be compared to other industries where significant risk is an issue. The concept of “as low as rea-sonably practicable” (ALARP) is widely accepted in risk-based industries and by the public (Fig. 1).

For a thorough discussion of other well-construction-failure concepts, such as barrier effectiveness and age vs. era of construction, and the results of existing well-failure studies, please see the com-plete paper, which also contains a discus-sion of cementing issues and sources of naturally occurring gas and oil pollution.

Sustained Casing Pressure (SCP). One of the first signs of a compromised bar-rier is SCP, described as development of a sustained pressure between the tub-ing and casing or between a pair of cas-ing strings that is not caused solely by heating of the well when placed on pro-duction. A sustained pressure may be bled off quickly but returns over hours or days after the annulus is shut in. Each of the annular spaces is a separate pressure vessel, and the casing strings are nest-ed to give redundant barriers. Although one barrier may develop a leak, second-ary barriers will contain the pressure and prevent a leak to the outside.

The presence of sustained pressure in the annulus area indicates that there may be a seepage-rate flow through at least one tubing string or casing string or through the cement; it also indicates that the pipe and cement on the outside of the annulus are containing the pressure (and fluids) and that there may be no signifi-cant leak to the environment outside of the well.

Why Well-Integrity Failures Produce Few Pollution IncidentsAs opposed to loss of control during drill-ing in high-pressure reservoirs, such as occurred on the Macondo well, actual losses from completed and producing wells are very low for several reasons.

◗◗ Many drilling failures are the result of unexpected high pressure or other drilling-related factors where the pressure barriers are mostly dynamic (mud-weight and blowout-preventer control) and before the full range of permanent barriers is installed that exists in a completed well. The expected frequency of surface releases in production wells (completed wells) is between one and two orders of magnitude lower during production than during drilling. Workovers during the life of the producing wells do raise the risk of a release, although the frequency is still approximately one order of magnitude lower than it is during drilling activities.

◗◗ Completed wells are constructed of multiple barriers that have been tested and are monitored where applicable.

◗◗ Most importantly, the pressure inside a completed producing oil or gas well drops constantly during primary production, sharply decreasing the potential from fluids inside the well to flow to the outside of the well, considering the outside fluid gradients that increase outside (leak-opposing) pressure with increasing depth.

Groundwater VariationGroundwater, brine zones, and produced water from oil and gas operations in a spe-cific area do not have a constant composi-tion. According to groundwater experts, overdrawing or overdrafting a ground-water reservoir (withdrawing water fast-er than it can be recharged) can produce notable changes in the reservoir-water composition, including pulling in contam-inants from above and salt from below. This variance makes single-point compar-isons of water quality practically worth-less. Many fresh groundwater reservoirs are laterally or vertically connected to more-saline water sources. Salinity within a single reservoir often varies with depth.

Sudden changes in pressure within a groundwater reservoir will also change the amount of free methane gas by caus-ing gas breakout into the free-gas phase. The only way to assess changes in a

Fig. 1—Schematic of the ALARP concept.

Unacceptable

MarginalAcceptability

Target Level or Risk=0

ProfessionalAcceptance

Widely Accepted by Public Very Low Impact and Low Occurrence

Low Impact andModerate Occurrence

High Impact and Low Occurrence

High Impact and Occurrence

Level of Risk

ALARPAs Low As Reasonably Practicable

DA166142.indd 107 12/12/13 2:11 PM


groundwater source is to establish a trend range and include seasonal factors, with-drawal rates, and other variables. Inves-tigations of stray natural-gas incidents in Pennsylvania, for instance, reveal that incidents of stray-gas migration were not caused by hydraulic fracturing of the Mar-cellus shale. The possibility of some gas-migration events being related to drilling cannot be dismissed, how ever, because air drilling, when practiced, may be a cause for temporary upsets in shallow-well color and odor, although the worst of these mi-grations appear to be in areas with known examples and a known history of shallow-gas flows that predate drilling.

Gas migration in the subsurface oc-curs principally by advective transport from areas of high pressure and is influ-enced by temporal changes in baromet-ric pressure, soil/bedrock porosity and permeability, and precipitation that in-fluences pore-water levels. Methane is the most common gas in groundwater. Shallow methane may be from sources both thermogenic (maturation of deposi-tional organics in the reservoir) and bio-genic (biological breakdown of organ-ic materials carried into the reservoir). Free (nondissolved) methane gas exists in many water reservoirs under the cap-rock or in rock layers, and methane gas is frequently desorbed from organic forma-tions such as coal or shale as the pressure is reduced by producing the water from these formations.

Bubbles Around a WellheadThe presence of bubbles in well cellars or through soil around the wellhead may or may not be an indicator of leaks from the well. Any disturbance of soil by drill-ing, digging, pile driving, or even walking (e.g., through a swampy area) is frequent-ly accompanied by release of methane gas, particularly where natural methane in the soil is more highly concentrated. This type of seepage is usually short-lived except in the presence of natural seeps fed by deeper reservoirs along an estab-lished seep path. Depending on the depth of disturbance, the bubbles may decrease or stop in seconds to days. Composition of this gas may be biogenic or thermogen-ic, because composition of natural-seep gas indicates that this gas is commonly from deeper reservoirs and is therefore overwhelmingly thermogenic. JPT

OFFSHORE TECHNOLOGY CONFERENCE ASIA

25-28 March 2014

Kuala Lumpur Convention Centre

Kuala Lumpur, Malaysia

“Meeting the Challenges for Asia’s Growth”

OFFSHORE TECHNOLOGY CONFERENCE ASIA

25-28 March 2014

Kuala Lumpur Convention Centre

Kuala Lumpur, Malaysia

“Meeting the Challenges for Asia’s Growth”

For more information, please contact:

Li Ping Chwa, OTC Asia Marketing Manager

Tel: +60.3.2182.3133 Fax: +60.3.2182.3030 Email: [email protected]

DA166142.indd 108 12/16/13 8:38 AM


Slicklines often play a vital role in offshore plug-and-abandonment

(P&A) operations, either in those phases of the operation that require slickline conveyance or because logistical, footprint, operational, economical, environmental, or regulatory parameters of a P&A necessitate full reliance on this small, light, cost-effective conveyance offering. P&A activities using digital slickline increase equipment, logistic, and marine-support efficiency.

IntroductionSlickline-conveyance services have long been used in the exploration and produc-tion industry, with much of the slickline equipment, processes, and capabilities remaining relatively unchanged. Me-chanical services have remained slick-line’s mainstay. Evolutionary enhance-ments resulting from developments in metallurgical engineering are applied to the line itself and the mechanical tools deployed, along with improvements in pressure-control and winch technology used to deploy the tools and services safely in live wells. Oilfield application of battery-powered electronics in downhole tools began in the late 1970s, eventually including electronics-based devices such as gauges, firing heads, bottomhole-fluid samplers, and production-logging and caliper tools, as well as hydraulic tools. Slickline services were soon offered to both remedial services (pipe cutting, tub-ing punching, and perforating) and mea-

surement services (production, pipe, and cement-bond-integrity logging). The de-mand for slickline services has remained steady over the years because of its many inherent advantages: minimal footprint; ease of logistics to, from, and on the well-site; operational simplicity; and overall cost-effectiveness.

The demand for hydrocarbons and the resulting effect on oil prices led to active developments in the subsea and deepwater arenas in past years, resulting in an increased complexity of well place-ments and associated well completions. This has led subsequently to new and innovative well-intervention capabilities being devised (and the associated equip-ment being engineered, developed, and deployed) as the need for intervention in these well types has grown.

Cost management is also a key part of P&A operations, along with safe ex-ecution and quality outcomes. Enhance-ments to existing (and development of new) purpose-built vessels and equip-ment, coupled with an intervention workforce that is growing in relevant and multiskilled capabilities, are in high de-mand. Lightweight, low-footprint inter-vention systems can lower cost signifi-cantly if they can offer a broad range of services and can be deployed on lower-cost vessels.

Slickline services have most recently seen a move toward on-command services and job-recording capability through te-lemetry enablement of the slick wire, com-bined with purpose-built downhole tools

and a computer command-and- acquisition system. With telemetry- enabled slickline, its real-time data acquisition and con-trol capabilities enhance and expand not only the remedial and measurement ser-vices on offer through slickline convey-ance, but also the more-routine mechani-cal services that make up the majority of slickline applications.

These capabilities of digital slickline are leveraged in the P&A arena, where advanced levels of clarity, certainty, and recordability are fully expected from all services used. These factors are also par-ticularly sought after in high-cost, highly sensitive environments such as the Gulf of Mexico and for the more-complex sit-uations of subsea completions and deep-water applications.

The digital-slickline trigger device used for all explosives-related servic-es such as device activation (e.g., plugs and cement bailers), pipe cutting and punching, and perforating has been de-signed with a number of intrinsic safety features that were not previously avail-able with slickline conveyance. The trig-ger is designed to ensure that triggering of the explosives cannot occur without a positive command from the surface-acquisition system. The correlation and eventual firing is managed with a single descent in the well. In addition, clear and concise shot detection is available on surface. This is visualized and re-corded in real time from multiple sen-sors in the basic control cartridge as well as from additional sensors that may be included, depending on the tool-string configuration deployed.

Case ExamplesThe following examples discussed in this paper are from two single-well subsea P&A operations and a subsea- intervention operation recently carried out for two different customers in the Gulf of Mexico. In the P&A examples,

Digital-Slickline Capability on Plug-and-Abandonment Conveyance Phases

The complete paper is available for purchase at OnePetro: www.onepetro.org.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 23916, “Impact of Digital-Slickline Capability on Slickline-Conveyance Phases of Plug-and-Abandonment Operations,” by Stuart Murchie and Matthew Billingham, Schlumberger, and Douglas Guillot and Chuck Esponge, Production Wireline, prepared for the 2013 Offshore Technology Conference, Houston, 6–9 May. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.

DA23916.indd 109 12/12/13 2:13 PM


where natural depletion and water en-croachment had killed the well, there were no additional zones above to bring on line. Hence, it was concluded that the economic life of the well was spent, and as such the well was to be perma-nently abandoned. The overall well P&A process was typical: downhole sequence of cement-plug placement in the tub-ing and across the perforations; place-ment of bridge plugs and associated ce-ment plugs in the tubing, casing, and associated annuli at the required depth points within the well; subsea-tree re-moval and the cutting and recovery of

some completion components; casing cutting and removal at the prescribed depth below the mudline; and final site-clearance survey and completion cer-tificate. The riserless intervention operations featured here required coor-dination of multiple service companies, each involved in a number of phases of the operation, working off a dynamical-ly positioned multipurpose vessel with remotely-operated- vehicle capabilities for equipment placement and removal of the subsea components. In addition to the setting of the bridge plugs, there was also the need to punch the tubing

or casing to enable the circulation nec-essary for the cement placement. Gauge cutter drift runs were also performed at various steps in the P&A sequence. High precision for the plug setting and perfo-ration depths was needed to place the cement barriers successfully. However, limited deck space, coupled with the desire to minimize the time taken and logistics needed for equipment change out for certain service providers, led the customer to choose digital slickline above standard slickline, using this ser-vice to complete slickline and equivalent electric-line tasks.

Fig. 1—Surface-readout-screen capture of the log-vs.-time record for the bridge plug.

Fig. 2—Surface-readout-screen capture of the log-vs.-time record of the lower-crown-plug pulling.

Bridge-Plug vs. Time

Shock

Plug Set

Force

Slips Starting to Set

Line Tension

Digital Slickline (DSL)Tension DSL Shock DSL Force

2012-05-2704:36:10

2012-05-2704:36:20

2012-05-2704:36:30

2012-05-2704:36:40

2012-05-2704:36:50

2012-05-2704:37:00

2012-05-2704:37:10

2012-05-2704:37:20

2012-05-2704:37:30

2012-05-2704:37:40

350

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50

60000

40000

20000

0

lbf

lbm

Time, days

Pulling Lower-Crown-Plug vs. Time

Shock

Force

Hanging Weight Hanging Weight

Pressure Increase

DSL Shock DSL Force DSL DHTE DSL Pressure

2012-11-1914:56:00

2012-11-1914:58:00

2012-11-1915:00:00

2012-11-1915:02:00

2012-11-1915:04:00

2012-11-1915:08:00

2012-11-1915:06:00

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DA23916.indd 110 12/12/13 2:13 PM


The first operation was performed in 315 ft of water with a riser. Magna range bridge-plug placement and cement-dump bailing was carried out, with several runs performed to place the desired cement column. A number of gauge-ring drift runs were carried out, primarily for tubing-access confirmation while simultaneously capturing the bottomhole-temperature infor-mation needed for the design of the ensuing cement plugs. In addi tion, the requisite number of tubing-punching and -cutting operations were conducted. When initial plans to use the riser had to be changed for operational reasons, the client was able to quickly switch to a digital-slickline-deployed riserless operation for the final tubing-puncher and tubing-cutter runs.

The plot in Fig. 1 is a screen capture of the information seen on surface in the slickline unit in real time during one of the bridge-plug-setting operations. As the plug-setting device is triggered, the resulting tool-string shock and the change in the line tension displayed clearly indicate that the device has been set.

For all digital-slickline runs, the accurate depth correlation required was provided during the same descent in the hole from the depth-correlation cartridge in the tool string. The depth tie-in requirements were related to the completion architec-ture rather than to the formation. Hence, only the casing- collar-locator measurement was used for this purpose.

The second operation was performed in 550 ft of water, this time using a riserless intervention system for pressure control. In this operation, regular slickline was used to pull the crown plugs, and digital slickline was used for the major-ity of the P&A operations. Again, bottomhole-temperature and - pressure information was captured during gauge-ring drift runs to assist in the cement-slurry design. Obtaining this infor-mation was a critical requirement for the overall P&A operation. Capturing these data during the slickline operation eliminated the need to swap out seal-flow tubes in the riserless interven-tion system for the electric-line cable, saving much time and op-erational effort. This was performed using the digital-slickline tool run in memory mode on standard slickline. Digital slickline was used to carry out a number of tubing-puncher runs, as well as to trigger a 10-ft, 6-shots/ft hole puncher used to penetrate both the tubing and the 9⅝-in. casing.

In a separate recent subsea-intervention operation, also in the Gulf of Mexico, digital slickline was used throughout the operation, including the removal and replacement of the upper and lower crown plugs in the subsea tree. Here, the water depth was almost 4,000 ft.

The plot in Fig. 2 captures the pulling of the lower crown plug. For this operation, a spring-set power jar was used to man-age the jarring in a slow and controlled manner, and was set to activate at 600 lbf. As can be seen, the initial line weight drops as the tool tags the crown plug. The subsequent pickup line ten-sion indicates that the pulling tool was engaged successfully, and jarring was started. After six jar attempts, as seen by the increase in line tension coupled with the shock measurement, the pres-sure steps up slightly, indicating that the seal on the crown plug is broken as the well pressure equalizes. With one final jar, the plug comes free, as confirmed by the corresponding increase in hang-ing weight of the tool string. JPT

The Endowed Leone Family Chair in Energy and Mineral Engineering

The Department of Energy and Mineral Engineering (EME; http://www.eme.psu.edu) in the College of Earth and Mineral Sciences (EMS) at The Pennsylvania State University invites applications for a faculty position at the full professor level. The candidate will also hold the John and Willie Leone Family Chair in Energy and Mineral Engineering. EME is home to Penn State’s undergraduate degree programs in Energy Business and Finance, Energy Engineering, Energy and Sustainability Policy, Environmental Systems Engineering, Mining Engineering, and Petroleum and Natural Gas Engineering. At the graduate level, the department offers MS and PhD degrees in Energy and Mineral Engineering with options in energy management and policy, environmental health and safety engineering, fuel science, mining and mineral process engineering, and petroleum and natural gas engineering. With the support of the Leone Endowment, the EME department is strengthening its combination of engineering/physical science and business education and research in a variety of energy fields.

The successful applicant for the Leone Chair is expected to further scholarly excellence through contributions to instruction, research, and public service that fosters a combined business and engineering education. The candidate will be expected to teach undergraduate and graduate level courses, supervise graduate students at the MS and PhD levels, and pursue a world-class research program in his/her area of specialization and the integration of business and engineering.

The successful candidate should be an accomplished international scholar with a sustained record of professional achievement; possess an outstanding research and publication record, teaching, and/or industrial leadership record; have demonstrated ability and willingness to establish and lead externally funded research programs; and have an earned PhD in either an energy-related engineering/physical science or business discipline or the combination thereof. The candidate should be either an engineer/physical scientist with extensive business experience or a business expert with in-depth knowledge of energy, technology, and engineering; have superior communication, collegial, and interpersonal skills; possess leadership ability in building interdisciplinary teams for collaborative research; demonstrate an ability to motivate and inspire faculty and students in the integration of engineering and business; be an individual who thinks broadly about energy and minerals and the associated environmental, health and safety, and management challenges; and exemplify the ideals promoted by the Leone Family gift. Potential candidates with high-level engineering/physical science and business experience in an energy-intensive industry are encouraged to apply. Penn State has added at least 25 new faculty in energy in the last three years (http://www.psiee.psu.edu, and http://www.psiee.psu.edu/publications/EnergyReport.pdf). EME has hired seven new faculty under this initiative. The successful candidate for this position will be expected to collaborate with other energy-related faculty in the EME Department, the EMS College, and across the University.

Applications should include: (1) a curriculum vitae with educational background, employment history, and publications; (2) a statement concerning research and teaching interests as well as the integration of business and engineering education; (3) names and addresses of at least three referees; and (4) samples of refereed publications. Send applications at the earliest via regular mail or electronically to: Chair of the Leone Chair Search Committee, Department of Energy and Mineral Engineering, 117 Hosler Building, University Park, PA 16802, USA; Fax: (814) 863 5709; E-mail: http://apptrkr.com/409390. Review of applications will begin in early January 2011 and continue until the position is filled.

Employment will require successful completion of background check(s) in accordance with University policies.

Penn State is committed to affirmative action, equal opportunity and the diversity of its workforce.

DA23916.indd 111 12/12/13 2:12 PM

SPE NEWS


SPE Donates to Disaster ReliefSPE donated USD 5,000 to the Philippines Red Cross to support relief efforts for the victims of typhoon Haiyan, one of the most powerful storms on record. The storm hit the central Philippine islands on 8 November 2013, leaving a wide swath of destruction. Thousands were killed and millions displaced.

SPE has an active Philippines Section, which was established in 1981, and two stu-dent chapters, at Batangas State University and Palawan State University. The Palawan State University in particular is very active, with a large number of students traveling recently to Jakarta to participate in the Asia Pacific Oil & Gas Conference and Exhibi-tion PetroBowl competition.

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Americas Office 222 Palisades Creek Dr., Richardson, TX 75080-2040 USA Tel: +1.972.952.9393 Fax: +1.972.952.9435 Email: [email protected]

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Moscow Office Perynovsky Per., 3 Bld. 2 Moscow, Russia, 127055 Tel: +7.495.268.04.54 Email: [email protected]

Jeff Spath, 2014 SPE president, recently met with Karen Agustiawan, president, director, and chief executive officer of PT Pertamina, during the SPE/IATMI 2013 Asia Pacific Oil & Gas Conference and Exhibition (APOGCE), held in October in Jakarta, Indonesia. The conference was a collaboration between SPE and the Society of Indonesian Petroleum Engineers (IATMI). Pertamina is Indonesia’s state-owned oil and gas company, and has been a strong supporter of SPE and IATMI, as well as the APOGCE in Jakarta since its inaugural event in 1999.

SPENewsJan.indd 112 12/17/13 2:33 PM

PEOPLE


Athabasca Oil Corporation’s board of direc-tors appointed ROB BROEN, SPE, to the recently created position of chief operating officer (COO). As COO, Broen now leads all the company’s operations, including operat-ing asset areas (light oil and thermal oil) and all technical functions. Broen joined Atha-

basca in November 2012 as senior vice president light oil with responsibility for the Light Oil Division; Drilling and Comple-tions Services; and Health, Safety, and Environment. He has more than 20 years’ industry experience. Before joining Atha-basca, he managed a capital budget of over USD 1 billion and a 120,000-BOEPD North American shale gas portfolio (Montney, Duvernay, Marcellus, and Eagle Ford) for Talisman Energy.

Broen began his 18-year career with Talisman as an oper-ations engineer in Chauvin, Alberta, Canada. At Talisman, he held increasingly more senior roles, including president, Talis-man Energy USA, based in Pittsburgh, Pennsylvania; and senior vice president, North American shale, based in Calgary. He was an officer and member of the board of directors of Talisman Energy USA. Before joining Talisman, Broen was a production and completion engineer with Wascana Energy, stationed in Swift Current, Saskatchewan, Canada. He earned a BS degree in chemical engineering from the University of Alberta, and is a graduate of the Ivey Executive Program at the Richard Ivey School of Business, University of Western Ontario.

STEPHEN I. CHAZEN, SPE, Occidental Petroleum Corporation’s president and chief executive officer (CEO), was elected chair-man of the American Petroleum Institute’s board of directors. This elected 1-year posi-tion was effective 1 January 2014. He has more than 40 years’ industry experience.

Chazen joined Occidental Petroleum in 1994 as executive vice president–corporate development. Since then, he has held numerous positions within the company. He was named COO in 1999 and elected president and chief financial officer in 2007. Three years later, he was named president and COO and elected

Member Deaths John D. Albright, Tulsa, Oklahoma, USAW.A. Downie, Banchory, ScotlandVan B. Goff, Spring, Texas, USAWilliam W. Liddell Jr., Baton Rouge, Louisiana, USADana G. McCarty, Bellevue, Washington, USADouglas Paul Taylor, Corpus Christi, Texas, USARoy K. Valla, Odessa, Texas, USADon G. Whitten, Houston, Texas, USA

In Memoriam MICHAEL J. ECONOMIDES, SPE, died 1 December 2013. He was 64. At the time of his death he worked in several capacities, including professor at the Cullen College of Engineering, University of Houston; world-wide petroleum consultant; and editor-in-chief of two energy-related publications.

Economides was born 6 September 1949 in Cyprus. A Greek national, he became a US citizen in 1982. At age 19, he came to the US as a Fulbright scholar, earning BS and MS degrees in chemical engineering at the University of Kansas.

From 1980 to 1984, he and his wife, Christine Ehlig- Economides, SPE, designed curricula for and established a petroleum engineering program at the University of Alaska. In 1984, he received a PhD in petroleum engineering from Stanford University.

From 1984 to 1989, Economides worked at Dowell Schlum-berger, then for 3 years as director of the Institute of Drilling and Production and petroleum engineering professor at Leoben Mining University in Leoben, Austria.

In 1993, Economides was principal founder of the Global Petroleum Research Institute at Texas A&M University, serving as its director and chief scientist for 5 years, while also a petro-leum engineering professor at A&M. He joined the University of Houston in 1998.

Economides consulted on petroleum projects in more than 70 countries and taught more than 300 advanced petroleum-related short courses worldwide. He authored or coauthored close to 300 technical papers and several book chapters and encyclopedia entries. He edited or wrote around a dozen tech-nical books on topics such as hydraulic fracturing and natural gas engineering. His best-known popular book, The Color of Oil: The History, the Money and the Politics of the World’s Big-gest Business, co-written with R.E. Oligney, was published in 2000 and became a bestseller. Economides also coauthored several other general books centering on geopolitics and the petroleum industry.

He served SPE as session chairperson at numerous confer-ences and forums worldwide and member of several technical and editorial review committees. He was chosen as a Distin-guished Lecturer for 1991–92.

Economides became an SPE Distinguished Member (1994) and received the SPEI Production and Operations Award (1997). The Russian Academy of Natural Sciences awarded him the Kapitsa Medal of Honor and the Albert Einstein Medal of Honor (2004). He received two honorary doctorates.

Economides is survived by his wife Christine and his sons John and Alexander.

PeopleJan.indd 113 12/17/13 2:38 PM

PEOPLE


to the company’s board of directors. He became president and CEO the following year.

Chazen also serves on the boards of directors for Eco-lab Incorporated, the Aquarium of the Pacific, and the Cata-lina Island Conservancy. Before joining Occidental, he was a managing director in the investment banking group of Merrill Lynch & Co. Chazen earned a PhD in geology from Michigan State University, a master’s degree in finance from the Univer-sity of Houston, and a bachelor’s degree in geology from Rut-gers College.

Denbury Resources appointed JOHN P. DIELWART, SPE, to its board of directors, thereby increasing the number of Denbury directors to 10. Dielwart has 35 years’ oil and gas industry experience, which includes being a founder, former CEO, and current member of the board of directors of ARC

Resources, a Calgary-based, midsized, dividend-paying oil and gas company. He oversaw the growth of ARC from a USD-200-million startup in 1996 to an USD-8-billion company at the time of his retirement in January 2013. Dielwart is cur-rently vice chairman of ARC Financial Corp., a Canadian, energy-focused private equity manager, a position he assumed after his retirement.

Before joining ARC, he spent 12 years with a major oil and natural gas engineering consulting firm, as senior vice presi-dent and director. Dielwart began his career at a major oil and

natural gas company, where he spent 5 years. He served two separate 3-year terms as a governor of the Canadian Association of Petroleum Producers, including 18 months (2002 to 2004) as its chairman. Dielwart earned a BS degree (with distinction) in civil engineering from the University of Calgary. He is also a member of the Association of Professional Engineers and Geo-scientists of Alberta (APEGA).

Strategic Oil & Gas appointed DOUGLAS WRIGHT, SPE, as vice president, engineer-ing and corporate development. He has been with Strategic since June 2013 as vice president, business development. In his new role, Wright is now responsible for engi-neering, reserves, and developing corporate

strategy. Additionally, he oversees the planning and execution of Strategic’s capital spending budget.

Wright has over 29 years’ experience in western Canada’s energy industry, with expertise focused on reserve evaluations for both annual reporting and acquisition/disposition analy-sis. He has worked for several major international companies, including Texaco, Imperial Oil, ConocoPhillips, and Anadarko. Most recently, he served in a senior management role at Per-petual Energy. Wright graduated from the University of Calgary with a BS degree in chemical engineering and from Athabasca University’s Centre for Innovative Management with an MBA. He is also a member of the APEGA and Society of Petroleum Evaluation Engineers.

2014 SPE International Conference onHealth, Safety, and Environment

17–19 MarchLong Beach Convention & Entertainment Center

Long Beach, California, USAwww.spe.org/events/hse/2014

Register Now!

PeopleJan.indd 114 12/17/13 2:38 PM


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Email: [email protected] Web: www.tdsolutions.com.au

Tarek Ahmed & Associates Ltd.Taking Petroleum Engineering Training

to a New LevelFor dates & descriptions

of courses held worldwide, please visit us at

www.TarekAhmedAssociates.com

EUROPE

To advertise in Professional Services contact [email protected] or call +1.713.457.6828.

PROFESSIONAL SERVICES

AVASTHI & ASSOCIATES, INC.Worldwide Petroleum Consultingwww.AvasthiConsulting.com

Since 1990

EOR/IOR, CO2 EOR/CCUS, Thermal EOR, Reservoir Engineering and Simulation, IAM, Geosciences and Geomechanics, Fracturing/Stimulation, and Facilities Consulting and Training Services for

Development and Optimization of Conventional and Unconventional,

Oil, Gas, Gas-Condensate, and Heavy Oil Fields around the World

[email protected] Head Office: 800 Rockmead Drive, Suite 212

Houston, Texas 77339, U.S.A. • Phone: +1-281-359-2674

Worldwide Petroleum Consulting

HOT Engineering

Exploration / Field Development / Training

Integrated Reservoir Studies • Lead & Prospect Generation • Reservoir Characterisation • Field

Development Planning • Enhanced Oil Recovery • Underground Gas Storage • Reserves Audits • Training

& HR Developmentwww.hoteng.com

Parkstrasse 6, 8700 Leoben, Austria Phone: +43 3842 430530 / Fax: +43 3842 430531

[email protected], [email protected]

International Reservoir Technologies, Inc.

INTEGRATED RESERVOIR STUDIES

Seismic Interpretation & Modeling Stratigraphy & Petrophysics

Reservoir Simulation Enhanced Oil Recovery Studies

Well Test Design & Analysis Well Completion Optimization

300 Union Blvd., Suite 400 Lakewood, CO 80228

PH: (303) 279-0877 Fax: (303) 279-0936 www.irt-inc.com [email protected]

KUWAIT

NIGERIA

flowgrids limitedPetroleum Engineering, Geosciences & Training Consultants

• Integrated Reservoir Studies & Field Development Planning• Reservoir Characterization, Evaluation & Simulation • Production Logging, Well Testing & Training

No. 1 Odi St (Old GRA) PMB 5034 Port Harcourt Nigeria

[email protected] www.flowgridsltd.com

SPE BookstoreSPE books and publications cover all aspects of the oil and gas industry and are considered the leading source of industry technical applications, information, and reference material.

Visit www.spe.org/store to view all available titles and current prices.

Subscribe to

SPE Drilling & Completion

Call +1.972.952.9393 or subscribe online at www.SPE.org.

ProCardsJan2014.indd 115 12/16/13 1:30 PM

PROFESSIONAL SERVICES


RUSSIA

SERVING THE OIL AND GAS INDUSTRY FOR OVER 60 YEARS

MILLER AND LENTS, LTD.INTERNATIONAL OIL AND GAS CONSULTANTS

Specializing in All Phases of Reserves Evaluations, Including Petroleum Economics,

Reservoir Engineering, Geology, and Petrophysics

Two Houston Center Phone: (713) 651-9455 909 Fannin St., Ste. 1300 Fax: (713) 654-9914 Houston, TX 77010 e-mail: [email protected]

Web pages: http://www.millerandlents.com

UNITED KINGDOM

esandarapid field development

planning and costing (QUE$TOR) economics and commercialisation

London +44 (0) 20 7558 [email protected] www.esandaengineering.com

UNITED STATES

CG ACawley, Gillespie & assoCiates, iNC.

Petroleum ConsultAntssinCe 1960

Fort worth Houston austin (817) 336-2461 (713) 651-9944 (512) 249-7000

www.cgaus.com – [email protected]

&

RALPH E. DAVIS ASSOCIATES, INC.International Consultants — Petroleum and Natural Gas

www.ralphedavis.comReserve Evaluation • Reservoir Studies • Geologic Studies

Coalbed Methane Development • Property Acquisition and Sales • Expert Witness

1717 St. James Place, Suite 460 - Houston, TX 77056 Tel: 713-622-8955 Fax: 713-626-3664

Proudly serving the industry for over 80 years.

COUTRET AND ASSOCIATES, INC.petroleum Reservoir engineers

Property evaluation, reservoir engineering Fluid injection, Property management

401 edwards street, suite 810 Phone (318) 221-0482 shreveport, lA 71101 Fax (318) 221-3202

www.coutret.com

Chemor Tech Int’l, LLCMaximizing Oil Recovery by

Applying Chemical IOR

• EOR Process Selection• Reservoir Evaluation• Facility Design & Fabrication• Field Operations

Harry L. ChangTel: (972) 599-1315 • Mobile: (214) 906-7682

www.chemortech.com [email protected]

4105 W. Spring Creek Pkwy, Plano, TX 75024

WILLIAM M. COBB & ASSOCIATES, INC.

— WORLDWIDE PETROLEUM CONSULTANTS —

Waterflood & EOR Studies Geological & Petrophysical Analysis

Reservoir Simulation Unconventional Resource Evaluation

Reserves & Property Valuation Gas Storage & CO2 Sequestration Analysis

Expert Witness • Technical Training

12770 Coit Road, Suite 907, Dallas, TX 75251 Phone (972) 385-0354 www.wmcobb.com FAX (972) 788-5165 [email protected]

M.J. ENGLAND, P.E.CONSULTING PETROLEUM ENGINEER

Reserve Reports Estate Appraisals Fair Market Value Expert Witness

215 Union Blvd., Suite 350 Lakewood, CO 80228-1840 Telephone: 303/298-0860 Facsimile: 303/298-0861

FORREST A. GARB & ASSOCIATES, INC.

International Petroleum Consultants

Reservoir Engineering Expert Witness Economic Evaluation Reservoir Simulation Geologic Studies Due Diligence Forensic Engineering Technical Staffing

5310 Harvest Hill Road, Suite 275 Dallas, Texas 75230-5805

Tel: 972-788-1110 Fax: 972-991-3160 Email: [email protected]

Web pages: www.forgarb.com

HAAS PETROLEUM ENGINEERING SERVICES, INC.

Robert W. Haas, P.E., President2100 Ross Ave., Suite 600 Office (214) 754-7090 Dallas, TX 75201 Fax (214) 754-7092

Email: [email protected] www.haasengineering.com

H.J. Gruy and Associates, Inc.

oil and Natural Gas Reserve advisors

reserve Determinations market Valuations Geologic studies expert testimony Petrophysical Analysis Arbitration seismic interpretation Commercial models reservoir simulation risk Analysis stochastic evaluations Acquisition screening

three Allen Center Plaza of the Americas Bldg. 333 Clay street, suite 3850 600 n. Pearl street, suite 2230, lB 150 Houston, texas 77002 Dallas, texas 75201 tel: (713) 739-1000 tel: (214) 720-1900 FAX: (713) 739-6112 FAX: (214) 720-1913 [email protected] [email protected]

www.hjgruy.com

T. Scott Hickman & Associates, Inc.Consulting Petroleum Engineers

Experienced Throughout U.S.A.

Due Dilligence Prospect Screening Reserve Evaluation Property Acquisition Reservoir Studies Litigation

505 N. Big Spring, Suite 105 Energy Square Bldg. Midland, TX 79701 TEL (432) 683-4391 www.tshickman.com FAX (432) 683-7303

Email: [email protected]

Huddleston & Co., Inc.Domestic and International

Petroleum & Geological Engineers1221 McKinney, Suite 3700

Houston, TX 77010 Ph: (713) 209-1100 Fax: (713) 209-1104

e-mail: [email protected]

NORWAY

Lyngaas TMCTrainingMentoringConsultancy

WellCat simulationsHPHT csg/tbg design, Wellhead movement,

Transient thermal effects, Packer load envelopes, VIT tubing, Steam injection analysis

BLOWOUT & KILL simulationsBlowout potential, Kill scenarios, Relief well analysis

Other software expertise: Drillbench Kick/Presmod, OLGA for wells, Prosper, SafeVision, WellScan, Cwear

Hanegaten 9, Pirsenteret N-7010 Trondheim, NorwayPhone: +47 90090989

[email protected] / www.lyngaastmc.com

PERACurtis H. Whitson

& Associates

EOS Fluid Characterization Design & Analysis of PVT Data

Gas Condensate Specialists Compositional Simulation Expertise

Pipe-It Integrated-Model Optimization

Granåsvei 1, 3rd floor • 7048 Trondheim Norway Phone 47 7384 8080 / Fax 47 7384 8081

[email protected] / www.pera.no

enhance your Career—Get Certifiedwww.spe.org/certification

Oil and Gas Facilities Magazine

Our bimonthly magazine dedicated to Projects, Facilities, and Construction professionals.

Learn more at www.spe.org/ogf.

spe CoNNeCtSPE Members Come Together Online With SPE ConnectA virtual place where you can meet, collaborate, and discuss specific technical challenges and resolutions, SPE Connect is now your link to SPE members worldwide.

www.spe.org/go/connect

spe web eventsJoin our industry experts as they explore solutions to real problems and discuss trending topics.

www.spe.org/events/webevents



LONQUIST & CO. LLCPetroleum Engineers • Energy Advisors

www.lonquist.com

Austin Houston Wichita3345 Bee Cave Rd., Suite 201 1001 McKinney, Suite 420 727 North Waco, Suite 275Austin, Texas 78746 Houston, Texas 77002 Wichita, Kansas 67202Tel: 512.732.9812 Tel: 713.559.9950 Tel: 316.854.8402Fax: 512.732.9816 Fax: 713.559.9959 Fax: 316.854.8404

• Reservoir Engineering • Reserve Determinations • Economic Evaluations • Underground Storage Engineering • Salt Cavern Engineering • Supply Studies • Mining Engineering

• Merger & Acquisition Support • Mineral and Royalty Management • Regulatory Filings and Testimony • CO2 Sequestration • Disposal Well Design • Graphical Information Systems

LARANCE ENGINEERING COMPANY LANE OPERATING COMPANY

Consulting Petroleum Engineers Reserv. Eva., Sec. Recovery, Unitiz.

Drilling & Completion Supervision Property Management

719 Scott Ave., Suite 420 Wichita Falls, TX 76301 940/322-0744

LEE KEELINGAND ASSOCIATES, INC.


Economic Evaluations Reservoir Engineering Reserve Estimates Secondary Recovery Reservoir Simulation Gas Storage Expert Witness S.E.C. Appraisals

15 East 5th Street, Suite 3500 Tulsa, Oklahoma 74103-4350

Phone: (918) 587-5521 - Fax: (918) 587-2881www.lkaengineers.com

e-mail: [email protected]

KMS TechnologiesElectromagnetic (EM) hardware, software & system solution which includes acquisition system / transmitter / fluxgate & induction coil magnetometer / electrodes / marine node cable EM combined seismic system / custom borehole systems / permanent sensors technology development & transfer / evaluation petrophysics & geophysics advisory

KJT Enterprises Inc. 6420 Richmond Ave., Suite 610 Tel: 713.532.8144 Houston, TX 77057 USA Fax: 832.204.8418

www.KMSTechnologies.com

LaRoche Petroleum Consultants, Ltd. 30 Years of Professional Service

Petroleum Engineering, Geological, and Geophysical Services

2435 N. Central Expressway www.larocheltd.com Suite 1500 Phone: 214-363-3337 Richardson, TX 75080 Fax: 214-363-1608

International Reservoir Technologies, Inc.

INTEGRATED RESERVOIR STUDIES

Seismic Interpretation & Modeling Stratigraphy & Petrophysics

Reservoir Simulation Enhanced Oil Recovery Studies

Well Test Design & Analysis Well Completion Optimization

300 Union Blvd., Suite 400 Lakewood, CO 80228

PH: (303) 279-0877 Fax: (303) 279-0936 www.irt-inc.com [email protected]

iReservoir.com, Inc. Geophysics / Geologic Modeling Petrophysics / Reservoir Simulation

Unconventional Resources

iReservoir.com provides world class 3D reservoir characterization and simulation studies along with secure Web hosting of results using state-of-the-art geoscience and engineering technology.

1490 W. Canal Ct., Ph. 303-713-1112 Ste 2000 Fax. 303-713-1113 Littleton, CO 80120 E-Mail: [email protected]

www.iReservoir.com

Long Consultants, Inc.Since 1988

D. R. (Russ) Long — Petroleum EngineerOredigger of ‘67

13231 Champion Forest Drive, Houston, Texas 77069P 281-397-8500 F 281-397-8506

www.longconsultants.com [email protected]

NITEC LLC


Fractured Reservoir Characterization/Modeling Gas Storage • Unconventional • EOR • CO2 CCS Black

Oil/Compositional/Thermal Reservoir Simulation

Provider of LYNX®, MatchingPro®, PlanningPro® and ForecastingPro® Software

Denver, Colorado 475 17th Street, Suite 1400

Ph. (303) 292-9595 www.NITECLLC.com

SERVING THE OIL AND GAS INDUSTRY FOR OVER 60 YEARS

MILLER AND LENTS, LTD.INTERNATIONAL OIL AND GAS CONSULTANTS

Specializing in All Phases of Reserves Evaluations, Including Petroleum Economics,

Reservoir Engineering, Geology, and Petrophysics

Two Houston Center Phone: (713) 651-9455 909 Fannin St., Ste. 1300 Fax: (713) 654-9914 Houston, TX 77010 e-mail: [email protected]

Web pages: http://www.millerandlents.com

MK Tech Solutions, Inc.EOR Evaluation and Simulations, Gas and Air Injection, Miscible, Thermal, Surfactant Enhanced Waterflooding

12843 Covey Lane, Houston, TX 77099 Ph: 281-564-8851, Fax: 281-564-8821

www.MKTechsolutions.com

D.F. NORTH AND ASSOCIATES, INC.PETROLEUM AND NATURAL GAS CONSULTANTS

• Reserve Appraisals • Prospect Evaluations • Economic/Risk Analysis • Gas/LPG Storage Studies

• Pipeline Design • Expert Witness • Computer Software

[email protected] P.O. Box 7335 Off. (281) 298-1167 The Woodlands, Texas 77387 Res. (281) 367-1767

MHA Petroleum Consultants LLC

730, 17th Street, Suite 410 Denver, CO 80202

(303) 277-0270 www.mhausa.com

A client oriented consulting firm providing practical solutions to reservoir

management problems.

MHA California LLC4700 Stockdale Hwy, Suite 110

Bakersfield, CA 93309(661) 325-0038 Denver: (303) 271-1478

VolunteerWould you like to be more involved with SPE?

Become a volunteer! To learn more visit www.spe.org/volunteer

SprouleWorldwide Petroleum Consultants

• Reserve Evaluations• Reservoir Engineering/Simulation• Resource Assessments• Geological Evaluations/Interpretations• Heavy Oil/Mining/In-Situ Oilsands• CBM/Shale Gas• Educational Courses

Calgary, Alberta, Canada (403) 294-5500 • 1-877-777-6135

Website: www.sproule.com • E-mail: [email protected]

JAmES E. SmITH & ASSOCIATES, INC.SPARTAN OPERATING CO., INC.

310 South Vine Avenue, Tyler, TX 75702903-593-9660 • 903-593-5527 (FAX) • 800-587-9660

[email protected] • http://www.jes-engineer.com

James E. Smith, P.E., Registered Professional Engineer

PRAPetrotechnical Resources of Alaska, LLC Alaska’s Oil and Gas Consultants

Geology, Geophysics, and Engineeringwww.Petroak.com

3601 C Street (907) 272-1232 voice Suite 1424 (907) 272-1344 fax

Anchorage, AK 99503

PLATT, SPARKS & ASSOCIATES CONSULTING PETROLEUM ENGINEERS, INC.

www.PlattSparks.com

• ReservoirEngineering • ReservoirSimulation • ReservoirCharacterization • OilandGasReservesEvaluation • FairMarketValueandAcquisitionValuation • EnhancedOilRecovery • EconomicEvaluation • OilandGasProduction • GasStorageDesignandScreening • RegulatoryFilingsandDatabaseAcquisition • ExpertPetroleumEngineeringTestimonyAUSTIN OFFICE MIDLAND OFFICE 925-A Capital of Texas Highway S. 800 North Marienfeld, Ste. 100 Austin, Texas 78746 U.S.A. Midland, Texas 79701 U.S.A. Telephone: (512) 327-6930 Telephone: (432) 687-1939 Facsimile: (512) 327-7069 Facsimile: (432) 687-1930 [email protected] [email protected]

Sharpen your Competitive Edge with SPE’s

SPE Training CoursesRegister online at www.spe.org/training

Subscribe to

SPE Reservoir Evaluation & Engineering

Call +1.972.952.9393 or subscribe online at www.SPE.org.

HSE NowSPE’s new web app for healthy, safety, and environment professionals.

www.spe.org/hsenow



THE STRICKLAND

GROUPVoice 817-338-0800

www.tsg.net Over 30 years experience offering

comprehensive reservoir engineering consulting services to the oil and gas

industry and legal community worldwide.

WELL COMPLETION TECHNOLOGY

William K. (Bill) Ott, P.E. • Sand Control • Well Completion • Stimulation

• Formation Damage Control • Cementing • Technical Schools • Equipment Trading • Consulting

7903 Alamar Drive Tel: 281-859-6464 Houston, TX 77095-2840 Fax: 281-855-3004 USA E-mail: [email protected]

W.D. Von Gonten & Co.Petroleum Engineering

Domestic and International808 Travis, Suite 1200 Tel: (713) 224-6333 Houston, TX 77002 Fax: (713) [email protected] • www.wdvgco.com

SURTEKChemical Flooding Technology

35+ Years of Chemical Flood ExperienceAlkaline-Surfactant-Polymer

Alkaline-Polymer Surfactant-Polymer

Mobility Control Polymer

Practical CEOR CoursesEOR ScreeningPilot and Full Field DevelopmentSimulation Field Evaluation

1511 Washington Ave., Golden, CO 80401 (303) 278-0877, Fax (303) 278-2245

www.surtek.com email: [email protected]

TSA, Inc.Consulting Petroleum and Environmental Engineers

Fluid Injection/Disposal, CO2-EOR and CO2-GS, FSI/CRI Wells, Produced Water/Frac Fluid Management, Technical Training, E&P Operations & Regulatory Compliance

6551 S. Revere Pkwy., Suite 215 Tel: 303.969.0685Centennial, CO 80111 www.talibsyed-assoc.comTalib Syed, P.E. e-mail: [email protected]

Wallace International, LLCUnconventional resource studies

Integrated reservoir description projectsDetailed petrophysical analyses

www.wallace-international.comOffice: 972-386-4581

• StrataStimSM – Stimulation design and reservoir optimization • StrataShaleSM – Shale completion development implementation• Data and Neural AnalysisSM – Development of best Practices from well files • Field supervision

575 N. Dairy Ashford, Suite 300 Houston, TX 77079

[email protected]

• Houston • Dallas • Denver, CO• Bakersfield, CA• Moscow• San Antonio, TX

StrataGen E n g I n E E r I n g

eMentoringSPE eMentoring Program

Are you looking for a way to get more involved with SPE and the next generation of the industry? If so, SPE’s eMentoring program may be the right choice for you.

Learn more at www.spe.org/ementoring.

SPE BookstoreSPE books and publications cover all aspects of the oil and gas industry and are considered the leading source of industry technical applications, information, and reference material.

Visit www.spe.org/store to view all available titles and current prices.

STEPHENS ENGINEERINGConsulting Petroleum Engineers & geologists

Waterflood—Evaluations Field Supervision

Cost Estimates—Design—Installation Reservoir Studies

Lease Operations by Stephens & Johnson Operating Co.P.O. Box 2249 (940) 723-2166 Wichita Falls, Texas 76307 Fax: (940) 723-8113

Update Your Member Profilewww.spe.org/members/update

www.spe.org/events/wmceFor more information, please visit

REGISTERTODAY

14–15 APRIL 2014HILTON KUWAIT RESORT, KUWAIT

FULL CYCLE WATER MANAGEMENT CHALLENGES AND SOLUTIONS



ADVERTISERS IN THIS ISSUE

JPT ADVERTISING SALES

ADDRESS CHANGE: Contact Customer Services at 1.972.952.9393 to notify of address change or make changes online at www.spe.org. Subscriptions are USD 15 per year (members). JPT JOURNAL OF PETROLEUM TECH NOLOGY (ISSN 0149-2136) is pub lished monthly by the Society of Petroleum Engineers, 222 Palisades Creek Drive, Richardson, TX 75080 USA. Periodicals postage paid at Richardson, TX, and additional offices. PoStmAStER: Send address changes to JPT, P.O. Box 833836, Richardson, TX 75083-3836 USA.

AAPG Pages 65, 89

Aramco Services Co. Page 33

Baker Hughes Inc. Page 37

Cameron Pages 2, 81

Cansco Well Control Page 101

CESI Chemical Page 83

CGG Page 31

Department of Chemical & Petroleum Engineering Page 16

Dragon Products, Ltd. Page 4

Friedrich Leutert GmbH & Co. KG Page 75

FmC technologies Page 11

Greene tweed Page 17

Halliburton Pages 5, 59

m-I SWACo Page 13

mewbourne College of Earth & Energy—University of oklahoma Page 15

mohawk Energy Page 8

momentive Page 29

National oilwell Varco Page 47

Noetic Engineering Page 71

oneSubsea Page 25

Packers Plus Page 7

Pennsylvania State University Page 111

Petrolink Cover 2

Rushmore Reviews Page 41

Schlumberger Pages 3, 21, Cover 4

Solvay Novacare Page 19

Statoil Page 9

t.t. & Associates Inc. Page 75

tAm International Cover 3

trican Well Services Page 23

Weatherford International Ltd. Page 85, 93

Wellbarrier AS Page 97

Welltec Page 87

AMERICAS

10777 Westheimer Rd., Suite 1075Houston, Texas 77042-3455 main tel: +1.713.779.9595Fax: +1.713.779.4220

Craig W. MoritzAssistant Director Americas Sales & Exhibitstel: [email protected]

Evan Carthey (Companies A-L)Sales Manager Advertisingtel: [email protected]

Dana Griffin (Companies M-Z)Advertising Salestel: [email protected]

CANADA

Mark HoekstraSales Manager - Canadatel: +1.403.930.5471 Fax: [email protected]

EUROPE, AFRICA, MIDDLE EAST, AND ASIA PACIFIC

Rob TomblinAdvertising Sales Managertel: +44.20.7299.3300 Fax: [email protected]

Society of Petroleum Engineers

Society of Petroleum Engineers

TRAINING COURSES

Rewarding.

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Courses are available for all levels of professionals.Attend an SPE training course to

learn new methods, techniques, and best practices to solve the technical

problems you face each day.

Find out more at www.spe.org/training.

Get the current schedule—wherever you are. Scan here with a QR code reader.

Setting the standard for technical excellence.

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AdIndexEH_Jan14.indd 119 12/17/13 9:38 AM

SPE EVENTS


WORKSHOPS

28–29 January 2014 ◗ Houston—AAPG/SPE Deepwater Reservoirs Geosciences Technology Workshop

10–11 February 2014 ◗ Moscow—Decision-Making Under Uncertainty

16–19 February 2014 ◗ Limassol—EAGE/SPE Workshop on Subsalt Imaging

16–19 February 2014 ◗ Kota Kinabalu—Innovative Technology for Reservoir Surveillance to Improve Reservoir Management

16–20 February 2014 ◗ Bangkok—SPE Managing Complex Capital Projects in the 21st Century: Paradigm Shift in Project Management

18–19 February 2014 ◗ Austin—SPE Production Chemistry and Chemical Systems

23–26 February 2014 ◗ Phuket—Underbalanced Drilling, Managed Pressure Drilling, and Well Controls

24–25 February 2014 ◗ Muscat—SPE Mature Assets—Learning from the Past, Planning for the Future

24–25 February 2014 ◗ Dubai—Completion and Stimulation of Maximum Reservoir Contact and Complex Wells

24–26 February 2014 ◗ Dubai—Reservoir Nanoagents: Taming Complexities on Road to Deployment

4–5 March 2014 ◗ London—SPE Effective Waterflooding—An Integrated Approach

4–7 March 2014 ◗ Kyoto—Nanotechnology & Nano-Geoscience in Oil and Gas Industry

5–6 March 2014 ◗ Baku—Sand Management in Poorly Consolidated Formations

9–12 March 2014 ◗ Bangkok—SPE Hydraulic Fracture—Building on the Past to Create the Future

9–12 March 2014 ◗ Langkawi—SPE EOR Stimulation: Are We There Yet?

11–12 March 2014 ◗ San Antonio—SPE/AAPG/SEG Pore Pressure Workshop

17–19 March 2014 ◗ Dubai—Petroleum Economics: Optimizing Value throughout the Asset Life Cycle

19–20 March 2014 ◗ London—SPE Petroleum Reserves and Resources Estimation—Petroleum Resources

Management System (PRMS) Applications Guidelines Document and Case Studies

18–20 March ◗ Moscow—SPE/EAGE Joint Workshop on Static and Dynamic Modelling

19–20 March 2014 ◗ Guadalajara—SPE Geomechanics

25-27 March 2014 ◗ Lyon—Cementing, Filling the Gaps

26–27 March 2014 ◗ Lima—SPE Oil and Gas Facilities

30–31 March 2014 ◗ Basra—Iraq Field Development Experiences

1–2 April 2014 ◗ Austin—SPE/ASPE Downhole Precision Tools in HPHT Applications: Filling the Gaps

6–9 April 2014 ◗ Kota Kinabalu—SPE Formation Damage Mitigation & Remediation

8–10 April 2014 ◗ Banff—Land Well Integrity: Current Challenges

COnFeRenCeS

4–6 February 2014 ◗ The Woodlands—Hydraulic Fracturing Technology Conference

10–12 February 2014 ◗ Houston—Arctic Technology Conference

25–27 February 2014 ◗ Vienna—SPE/EAGE European Unconventional Resources Conference and Exhibition

26–28 February 2014 ◗ Lafayette—International Symposium and Exhibition on Formation Damage Control

4–6 March 2014 ◗ Fort Worth—IADC/SPE Drilling Conference and Exhibition

17–19 March 2014 ◗ Long Beach—SPE International Conference on Health, Safety, and Environment

25–26 March 2014 ◗ The Woodlands—Coiled Tubing and Well Intervention Conference and Exhibition

25–28 March 2014 ◗ Kuala Lumpur—Offshore Technology Conference Asia

31 March–2 April 2014 ◗ Muscat—SPE EOR Conference at Oil and Gas West Asia

1 April 2014 ◗ Calgary—Slugging It Out

1–3 April 2014 ◗ Utrecht—SPE Intelligent Energy Conference and Exhibition

1–3 April 2014 ◗ The Woodlands—SPE Unconventional Resources Conference–USA

2 April 2014 ◗ Bergen—SPE Bergen One Day Seminar

8–9 April 2014 ◗ Madrid—SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition

12–16 April 2014 ◗ Tulsa—Improved Oil Recovery Symposium

14–16 April 2014 ◗ Kuwait City—Oilfield Water Management Conference and Exhibition

17–18 April 2014 ◗ Denver—Western North American and Rocky Mountain Joint Meeting

21–24 April 2014 ◗ Al Khobar—SPE-SAS Annual Technical Symposium and Exhibition

FORUMS

16–21 February 2014 ◗ Vilamoura—Zonal Isolation to the Extreme

23–28 February 2014 ◗ Newport Beach—Numerical Modeling in Unconventional Reservoirs

17–20 March 2014 ◗ Abu Dhabi—Overcoming Challenges in Developing Shale and Tight Gas Reservoirs

1–6 June 2014 ◗ San Diego—Exploiting Tight Carbonates

27 July–1 August 2014 ◗ Newport Beach—Low Carbon Intensity Processes for Low-Mobility Oil Recovery

CALL FOR PAPeRS

SPe Annual Technical Conference and exhibition ◗ Amsterdam, The Netherlands Deadline: 27 January 2014

SPe Artificial Lift Conference & exhibition—north America ◗ Houston, Texas, USA Deadline: 3 February 2014

Middle east Health, Safety, environment, and Sustainable Development Conference and exhibition ◗ Doha, Qatar Deadline: 6 February 2014

International Petroleum Technology Conference ◗ Kuala Lumpur, Malaysia Deadline: 12 February 2014

Find complete listings of upcoming SPE workshops, conferences, symposiums, and forums at www.spe.org.

SPEEventsJan.indd 120 12/16/13 7:30 AM

WELL INTERVENTION DRILLING & COMPLETIONS UNCONVENTIONAL RESOURCES RESERVOIR OPTIMIZATION

www.tamintl.com

TAM Big Packers for Deepwater Operations:The stakes are high in deepwater operations.

TAM SOLUTIONS

MTM cementing PortCollars up to 30 in.

Swellablepackersup to 30 in.

Casing annulus packers up to 24 in. casing and30 in. open hole

Infl atable plug and storm packers upto 30 in. casing oropen hole

DEEPWATER — BIG PACKERS TO AVOID BIG PROBLEMS

Threatening storms? Depend on TAM’s drill pipe Single Set infl atable plug and storm packer.Cement integrity? Count on TAM’s casing annulus packers (TAMCAP), metal-to-metal Port Collars, and FREECAP® swellable packers to solve your most difficult problems. Casing leaks and wellbore integrity issues? Trust TAM’s exclusive multi-set infl atable TAM-J for reliable casing testing. Lost time in testing BOP/riser connections? Rely on TAM’s TripSAVR® to surface-test these critical connections before a costly run in the hole.

Trust TAM for Big Solutions that are safe, reliable, and critical to your success.

DEEPWATERDEEPWATERDEEPWATERDEEPWATERDEEPWATER

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Vx Spectra is a mark of Schlumberger. © 2014 Schlumberger. 13-TS-0206

Find out more at

slb.com/VxSpectra

Full-spectrum, single-point measurement for the most accurate production fow rates.Only the Vx Spectra fowmeter captures the complete spectrum of gamma energy levels at high frequency from a

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SURFACE MULTIPHASE FLOWMETER

Vx Spectra

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Documents

2014-01