Oilfield Review Autumn 2008

Autumn 2008

Subsalt Play

Circular Seismic Acquisition

Drilling Through Salt

HPHT Technologies

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The area offshore Brazil has been an exciting new frontierfor exploration and development during the past few years.To date, Petrobras has discovered eight deepwater fields inthe area called the presalt cluster of the Santos basin. Inthe Tupi discovery, an extended well test will be performedin March 2009, and a commercial pilot project will begin atthe end of 2010. This activity is part of a company goal toachieve a significant production rate in the presalt cluster,to be added to the current domestic oil-production target of2.8 million bbl/d [450,000 m3/d] by 2015. We believe thisgoal, established in the Petrobras 2007 Strategic Plan, isaggressive but attainable. To achieve this, we anticipate asignificant increase over the currently forecasted capitalexpenditure of US $112 billion for the next five years, andwe foresee a positive impact on future proven reserves.

Following our corporate vision led us to look beyond thewell-known reserves that were above the salt in this off-shore region. Our exploration in the Santos basin took usinto waters deeper than 2,100 m [6,900 ft], targeting car-bonates that are beneath 2,000 m [6,600 ft] of salt (forrelated concerns in the Gulf of Mexico, see “Meeting theSubsalt Challenge,” page 32).

The successes to date in this presalt province have resultedfrom application of existing technologies by Petrobras, itspartners and suppliers. In particular, we relied on propri-etary seismic interpretation software and high-definitionnuclear magnetic resonance (NMR) tools. In theseexploratory wells, the NMR tools provided vital identifica-tion of portions of the reservoir rock with sufficient porosityto indicate good production potential. However, we mustaddress specific challenges to guarantee optimum produc-tion from these presalt carbonate formations.

Better characterization and imaging of the formation arenecessary to map reservoir continuity and recognize its het-erogeneity. Facies from seismic interpretation, internalpore distribution and connectivity are all keys to ensure thebest well geometry to increase production, improve fielddrainage and minimize the number of floating platforms. Inaddition, we need to address technological gaps for achiev-ing well deviation in the salt, for optimizing hydraulic oracid fracturing of horizontal carbonate wells and for under-standing the wettability of the carbonates so we can injectwater or gas, or both, effectively.

With long pipelines and low reservoir temperature, waxand hydrate tend to precipitate, creating flow-assuranceproblems that must be addressed. Further, the productionenvironment is conducive to scaling of carbonates and sul-fates. The company envisions an increased need for workoversthat may lead to the use of light intervention vessels, andeven of dry completion facilities that bring a positive collat-eral effect by reducing demand for floating drilling rigs.

Conquering a New Frontier

The carbon dioxide [CO2] produced from these forma-tions ranges from 8% to more than 30%, and Petrobras andits partners will not vent it. Hence, we have a plan for greenseparation and reinjection of the gas in saline aquifers orfor enhanced oil recovery. The CO2 also presents a corro-sion challenge to equipment and tools, particularly thosethat will reside for long periods in the wells.

Because the Tupi cluster is about 300 km [186 mi] fromshore, the logistics for mobilization of personnel and equip-ment will require innovative planning that might includeoffshore bases for tasks such as maintenance and heli-copter fueling. Petrobras is also looking at nontraditionaluses of natural gas produced offshore. Feasibility of floatingliquefied-natural-gas facilities is under study, as is consid-eration of using the gas at an offshore hub to produce elec-trical power for a series of production platforms.

The outstanding experience acquired from Campos basinproduction development through the partnership betweenPetrobras and traditional service and equipment supplierswill again be crucial for successful development of the Santos basin presalt cluster—technical cooperation agree-ments are under discussion to accelerate the necessarytechnological achievements.

These challenges may appear to be daunting, but theTupi field pilot project predictions show a significant eco-nomic return for Petrobras and its partners, even whenbased on application of traditional technologies. However,Petrobras has always considered introduction of new tech-nology to be a key business driver. The company will con-tinue to develop and apply technologies, in cooperationwith research institutions, universities, service companiesand partners, to ensure that the presalt riches can beextracted safely and economically, even with fluctuatinghydrocarbon prices.

José FormigliE&P Pre-salt Executive ManagerPetrobras

José Formigli was recently appointed to a newly created Executive Managerpost in Petrobras domestic E&P, called E&P-PRESAL. This position is specifi-cally dedicated to evaluation and production development of presalt discover-ies, encompassing the cluster of recent strikes in Santos basin, offshore Brazil.Since joining Petrobras in 1983, he has worked in several activities related towell completion and subsea engineering, starting as an offshore company manand later managing those activities. José was production manager of Camposbasin, Marlim field asset manager, E&P services executive manager and E&Pproduction-engineering executive manager. He received degrees in civil andpetroleum engineering from the Instituto Militar de Engenharia and PetrobrasUniversity, respectively, and an MBA degree in advanced business manage-ment from the COPPEAD Graduate School of Business of the Universidade Federal do Rio de Janeiro.

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Schlumberger

Oilfield Review4 The Prize Beneath the Salt

The subsalt play in the northern Gulf of Mexico extends basin-ward across a wide expanse of the outer Continental Shelf andSlope of the western and central US Gulf Coast. E&P companiesare exploiting this play by drilling structures lying between saltmasses or beneath salt canopies. Originally targeting horizonsof Miocene through Pleistocene age, some operators are nowexploring deeper sands of the Lower Tertiary.

18 Shooting Seismic Surveys in Circles

Surveys that record data from raypaths in a wide range of directions deliver better illumination of the subsurface thanconventional marine 3D seismic surveys, which record data primarily from one direction. A new technique uses a vesselsailing in continuously linked circles to record these wide-ranging raypaths efficiently. This article reviews the new tech-nique and its considerable potential for addressing imagingchallenges in complex geological settings.

Executive EditorMark A. Andersen

Advisory EditorLisa Stewart

EditorsMatt VarhaugRick von FlaternVladislav GlyanchenkoTony SmithsonMichael James Moody

Contributing EditorsRana RottenbergGlenda de LunaJudy JonesErik NelsonJohn Kingston

Design/ProductionHerring DesignSteve Freeman

IllustrationTom McNeffMike MessingerGeorge Stewart

PrintingWetmore Printing CompanyCurtis Weeks

Address editorial correspondence to:Oilfield Review5599 San Felipe Houston, Texas 77056 USA(1) 713-513-1194Fax: (1) 713-513-2057E-mail: [email protected]

Address distribution inquiries to:Tony SmithsonOilfield Review12149 Lakeview Manor Dr.Northport, Alabama 35475 USA(1) 832-886-5217Fax: (1) 281-285-0065E-mail: [email protected]

Useful links:

Schlumbergerwww.slb.com

Oilfield Review Archivewww.slb.com/oilfieldreview

Oilfield Glossarywww.glossary.oilfield.slb.com

On the cover:

In the Gulf of Mexico, deepwater opera-tors are extending exploration campaignsseeking pay that extends beneath saltbodies. Here, a rotary steerable systemhas been oriented to drill out perpendicularto the bottom face of the salt body, whichis indicated by the purple portion of theseismic section.

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Salt

Base of salt

Inclusion

Autumn 2008Volume 20Number 3

61 Contributors

64 New Books and Coming in Oilfield Review

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32 Meeting the Subsalt Challenge

At one time, operators studiously avoided drilling through saltsections. Today, through innovation and experience, drillershave learned to routinely drill vertical and directional wellsthrough extremely thick salt sheets on their way to the hydrocarbon-rich reservoirs beneath them.

150°C

69 M

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241

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HPHT

Ultra-HPHT

HPHT-hc

205°C

260°C46 High-Pressure, High-Temperature Technologies

Scientists and engineers push the limits of chemistry and materials science to meet the challenges associated with high-pressure, high-temperature (HPHT) wells. This article surveystechnologies and materials developed for successful HPHTdrilling, formation evaluation, well construction, stimulation,production and surveillance. Case studies illustrate how engineers contend with these difficult conditions.

Abdulla I. Al-KubaisySaudi AramcoRas Tanura, Saudi Arabia

Dilip M. KaleONGC Energy CentreNew Delhi, India

Roland HampWoodside Energy, Ltd.Perth, Australia

George KingRimrock Energy LLCDenver, Colorado, USA

Eteng A. SalamPERTAMINAJakarta, Indonesia

Jacques Braile SaliésPetrobrasHouston, Texas, USA

Richard WoodhouseIndependent consultantSurrey, England

Advisory Panel

Oilfield Review subscriptions are available from:Oilfield Review ServicesBarbour Square, High StreetTattenhall, Chester CH3 9RF England(44) 1829-770569Fax: (44) 1829-771354E-mail: [email protected] subscriptions, including postage,are 200.00 US dollars, subject toexchange-rate fluctuations.

Oilfield Review is published quarterly bySchlumberger to communicate technicaladvances in finding and producing hydro-carbons to oilfield professionals. OilfieldReview is distributed by Schlumberger toits employees and clients. Oilfield Reviewis printed in the USA.

Contributors listed with only geographiclocation are employees of Schlumbergeror its affiliates.

© 2008 Schlumberger. All rights reserved.No part of this publication may be repro-duced, stored in a retrieval system ortransmitted in any form or by any means,electronic, mechanical, photocopying,recording or otherwise without the priorwritten permission of the publisher.


4 Oilfield Review

The Prize Beneath the Salt

John R. DribusNew Orleans, Louisiana, USA

Martin P.A. JacksonBureau of Economic GeologyThe University of Texas at AustinAustin, Texas, USA

Jerry KapoorMartiris F. SmithHouston, Texas

For help in preparation of this article, thanks to Joelle Fay and Mark Riding, Gatwick, England; and Chris Garcia, Mexico City, Mexico. Q-Marine is a mark of Schlumberger.

Exploration and production activities in the deep and ultradeep waters of the northern

Gulf of Mexico have led the way to the latest subsalt play. Lessons learned from this

play may, in turn, open the way for subsalt exploration in other basins around the world.

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Autumn 2008 5

highly competitive arena, where choice blocks ofoffshore real estate can lease for more thanUS $100 million for a 10-year lease. But secrecyand competition are not the only impediments toexploration in this area.

Perhaps the greatest challenge is posed bythick layers of salt in the subsurface. Severaldeepwater prospects lie beneath sheets of salt—some up to 20,000 ft [6,100 m] thick.1 Like anundulating and tattered canopy, coalesced saltsheets extend from the US Continental Shelf tothe deepwater Continental Slope off the coasts ofTexas and Louisiana. A similar subsalt provincelies well to the south, in less-explored waters offMexico’s Yucatan Peninsula.

In their pursuit of new exploration targets,many offshore operators have had to drillthrough hundreds or even thousands of feet ofsalt to discover pay sands. Their efforts have led

to notable subsalt discoveries on the Shelf, suchas Mahogany; or in deeper waters, such asGemini, Atlantis, Tahiti, Mad Dog and Pony; or in ultradeep waters, such as Thunder Horse, St. Malo, Jack and Kaskida.2

Salt is a particular challenge for drillers, whomust contend with high-pressure sediment

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Successes in deep- and ultradeepwater prospectsare spurring a resurgence in exploration in theGulf of Mexico. Announcements of significantdiscoveries or record-setting achievements havepiqued interest in the activities of deepwateroperators, as evidenced by bidding competitionat recent offshore lease sales. Exploratorydrilling has also confirmed the presence ofreservoir-quality sands that are much fartherfrom shore than expected. The discovery ofhydrocarbons in several of these sands is fuelingspeculation about the tantalizing potential thatmight lie beneath deep Gulf waters.

Speculation is in large supply. Offshoreoperators diligently safeguard their expensiveand hard-won secrets of the deep and releaseonly the data required by governmental mandate.Press releases are carefully constructed to avoidrevealing the full extent of discoveries in this

1. Close F, McCavitt RD and Smith B: “Deepwater Gulf ofMexico Development Challenges Overview,” paper SPE113011, presented at the SPE North Africa Technical Conference and Exhibition, Marrakech, Morocco, March 12–14, 2008.

2. The concept of deep water has evolved considerablythroughout the years. The US Department of Interior Minerals Management Service (MMS) originally defineddeep water as 200 m [656 ft]. This mark was later eclipsedby industry drilling trends, and now the deepwater stan-dard is set at 1,000 ft [305 m]. The MMS has designateddepths greater than 5,000 ft [1,524 m] as ultradeep water.In the Gulf of Mexico, the deepest waters are found in the Sigsbee Deep, whose estimated depths range from12,303 ft [3,750 m] to 14,383 ft [4,384 m].


inclusions or rubble zones as they drill throughsalt bodies (see “Meeting the Subsalt Challenge,”page 32). It also poses substantial difficulties forgeophysicists as they attempt to image deepstructures beneath irregularly shaped saltbodies. In salt, seismic waves can reachvelocities of 14,500 to 15,100 ft/s [4,400 to 4,600m/s]—in some cases roughly twice the velocitythey would travel in surrounding sediments. Thisvelocity contrast causes geophysical imagingproblems that can mask underlying structuresand prevent geoscientists from determining thelocation or extent of potential reservoirs.3

However, advances in seismic acquisition andprocessing techniques are helping geophysicistsresolve problems that previously preventedimaging beneath the salt (see “Shooting SeismicSurveys in Circles,” page 18).

The process of drilling and producing asubsalt well requires significant planning,operational skill and investment. Given thedifficulties associated with drilling in deepwaters, the decision to take on the additionalchallenge of drilling through salt must bejustified by potential for payouts and returnsworthy of the additional expense and riskinvolved. One frequently cited article, written in1997, noted that potential subsalt reserves from25 or more significant fields located primarily on

the Continental Shelf of the northern Gulf hadbeen estimated at 1.2 billion bbl [190 million m3]of oil and 15 Tcf [435 billion m3] of gas.4 Theseestimates do not include additional reserves thathave since been discovered in the deepwaterMiocene play—including Mad Dog, Pony, Tahitiand others—nor do they include ultradeepwatersubsalt discoveries such as Jack, Kaskida,St. Malo and Thunder Horse.

This article describes the evolving subsaltplay in the northern Gulf of Mexico. We brieflyreview the geologic processes that led todeposition of the Louann Salt and the transportof reservoir-quality sands into deeper reaches ofthe basin. We examine the role of saltmobilization and its effect on overlying sedimentin the formation of traps and migration pathwaysnecessary to complete an effective petroleum

system in the Gulf of Mexico. We also discuss howsands that were originally deposited on top ofsalt have come to lie beneath it. Although thisarticle focuses primarily on the intensivelyexplored US waters of the northern Gulf ofMexico, some of the principles described are alsorelevant to other basins around the world.

Evolution of the Gulf of Mexico BasinDiscoveries in the Gulf of Mexico havechallenged previous thinking regarding theoccurrence of hydrocarbon-bearing sands that liebeneath great thicknesses of salt. This salt isactually older than the sands that lie beneath it.However, the salt has moved and in some casescreated seals capable of trapping oil and gas.Understanding the geological complexities ofthese discoveries requires a step back in time.

The evolving subsalt play in the Gulf of Mexicois inextricably tied to the geologic history of theGulf itself. This history goes back eons, before theGulf of Mexico existed, to a time after most of theworld’s continental plates had converged into asupercontinent known as Pangea (left). Thetectonic activity that followed would mold theGulf basin and influence the distribution ofsediments that subsequently filled it.

In addition to unremittingly gradual tectonicand depositional processes in this basin, otherforces were at work. The early history of the Gulfof Mexico was at times abruptly punctuated bycatastrophic events that not only influenced theformation of the Gulf, but also changed the world.These events were remarkable in their scale, butwere certainly not unique; one such cataclysmoccurred just before the Gulf began to open.

Approximately 250 million years ago, much oflife on Earth was extinguished. On land, insectbiodiversity plummeted, while plant and animallosses were even more severe, as 70% of landspecies vanished. In the seas, trilobites, tabulateand rugose corals, and nearly all crinoids becameextinct, along with roughly 90% of all marinespecies. Atmospheric oxygen levels dropped from30% to less than 15%.

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> Earth during the Triassic period. The eventual breakup of the Pangeansupercontinent was manifested in part by rifting between the continentalplates of Africa and the Americas, which eventually led to the formation ofthe Gulf of Mexico.

3. Farmer P, Miller D, Pieprzak A, Rutledge J and Woods R:“Exploring the Subsalt,” Oilfield Review 8, no. 1 (Spring 1996): 50–64.

4. Montgomery SL and Moore DC: “Subsalt Play, Gulf of Mexico: A Review,” AAPG Bulletin 81, no. 6 (June 1997): 871–896.

5. Salvador A: “Late Triassic-Jurassic Paleogeography andOrigin of Gulf of Mexico Basin,” AAPG Bulletin 71, no. 4(April 1987): 419–451.

6. A graben is a downthrown fault block that is bounded oneither side by opposing upthrown normal fault blocks.Grabens occur in areas of rifting or extension, where theEarth’s crust is being pulled apart.Red beds are reddish sedimentary strata, such as sand-stone, siltstone or shale, which have accumulated under

oxidizing conditions. The red color results from specks ofiron oxide minerals in the sediments. Oxidizing conditionsare common in hot, arid environments and thereforeimply that the sediments have been exposed to theseconditions through surface weathering as a result ofuplift or erosion of overlying sediment. Red beds arecommonly associated with rocks of the Permian and Triassic periods.

7. Salvador, reference 5.8. Pindell J and Kennan L: “Kinematic Evolution of the

Gulf of Mexico and Caribbean,” in Fillon RH, Rosen NC,Weimer P, Lowrie A, Pettinghill H, Phair RL, Roberts HHand van Hoorn B (eds): Proceedings, 21st Annual GulfCoast Section SEPM Foundation Bob F. Perkins ResearchConference (2001): 193–220.


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This was the great Permian-Triassic extinc -tion event (above). The cause of this massextinction is subject to debate. While recentdiscoveries point to an asteroid impact, otherevidence supports a variety of theories includingmassive volcanic activity, falling sea levelsbrought on by the formation of continental icesheets, anoxia caused by sluggish oceancirculation, a massive release of methane fromseafloor hydrates, or some combination of theseevents. Regardless of the cause, this extinctionestablished a prominent geological benchmarkin outcrops around the world, providing a gaugeby which to establish the timing of subsequentprocesses that led to the formation of featuressuch as the Gulf of Mexico.

After this extinction, Pangea began to driftapart as a precursor to the development of theGulf of Mexico basin. In the Late Triassic, as theNorth American plate pulled away from the SouthAmerican and African plates, deep rifts began toform. These rifts were associated with stretchingof the continental crust.5 Still part of the NorthAmerican plate, the area that would eventually

become the Gulf of Mexico was cut by grabens,which gradually subsided as they filled withvolcanic deposits and nonmarine red bedsderived from sediments eroded from adjacentelevated areas.6 These red beds, which providesome of the earliest records of Gulf of Mexicorifting, make up part of the Eagle Mills formation.

Subduction-related tectonism along thewestern margin of the North American platepermitted sporadic encroachment of the PacificOcean. During the Middle Jurassic, Pacific stormsurges reached eastward across Mexico to fillshallow depressions in the proto-Gulf—thesurface expressions of continually subsidinggrabens activated during the Late Triassic.Between surges, the connection with the PacificOcean would close, leaving behind isolatedbodies of salt water.

Throughout countless cycles of replenish -ment and evaporation, salinity in these bodies ofwater steadily increased. This resulted in haliteprecipitation in the center of the hypersalinebasins and anhydrite precipitation along parts ofthe periphery. Local subsidence accom modatedthe pace of halite precipitation, as evidenced byevaporite deposits that are thousands of feetthick. In the northern Gulf of Mexico basin, theseextensive salt deposits came to be called theLouann Salt, of late Middle Jurassic age.

In the Late Jurassic, during what is inferredto be the final stages of rifting, continuedstretching of the continental crust caused theYucatan platform to separate from the NorthAmerican plate, taking a portion of the salt bodyalong with it. A connection between the earlyGulf of Mexico and the Atlantic Ocean probablyopened late in the Jurassic, when a passagewaybetween the Florida and Yucatan platforms wasestablished, and the connection to the PacificOcean became restricted.7 The Yucatan rotatedcounterclockwise as it continued to driftsouthward.8 It finally came to rest on the northernedge of the South American plate during theEarly Cretaceous (below).

Tectonics beyond the basin greatly influencedthe sequence and areal extent of sedimentarydeposits that began filling the Gulf and buryingthe thick layers of Louann Salt. Some of thesesediments would later become hydrocarbonsources, while others would become possiblehydrocarbon reservoirs that today are beingtargeted for exploration.

Jurassic uplift of the Appalachian Mountainswas accompanied by erosion of graniticmountain materials. As they weathered, thefeldspar and mica minerals within these granitesbroke down to produce clastic deposits rich in

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> Yucatan microplate movement. The Louann Salt basin split apart as the Yucatan microplate (dashedyellow line) rotated and drifted southward (white arrow). (Adapted from Pindell and Kennan, reference 8.)


clay, known as feldspathic sandstone. Locally,arid winds transported some of the clasticsediments, winnowing the clays away from thequartzose fraction, resulting in eolian depositsof the Upper Jurassic Norphlet sandstone.9

Meanwhile, the Florida Shelf and Yucatan Shelfbecame starved of clastic sediments and weredominated by the deposition of massive layers ofche mical carbonates.

Following Norphlet deposition, a rise in sealevel produced a transgressive period duringwhich localized deposition of evaporites, shallowmarine clastics and organic-rich carbonatesoccurred. The organic matter, derived fromalgae, plankton and other materials in themarine environment, was mixed and buriedwithin layers of carbonates and shales. As thesediments were buried deeper over time, heatand pressure resulting from the accumulatingoverburden transformed the organic matter intoType I and Type II kerogens, essential precursorsto the generation of hydrocarbons.10

During the Cretaceous, thick deposits ofinterbedded carbonates, marls and organic-richmarine shales were laid down during anotherseries of marine transgressions. Like theirdeeper Jurassic equivalents, these organic-richdeposits would become important source rockswhen buried deep enough to generate hydro -carbons. The end of the Cretaceous—about65 million years ago—was marked by the arrivalof a large asteroid, which heralded a new era inthe geologic history of the Earth.

This asteroid, 5 to 6 mi [8 to 10 km] indiameter, impacted near the present-day town ofChicxulub Puerto, on Mexico’s YucatanPeninsula (above). Upon impact, the asteroidexcavated a crater in the Yucatan carbonateShelf that spans more than 112 mi [180 km] indiameter and melted the Earth’s crust to a depthof about 18 mi [29 km].11 The energy released onimpact exceeded that released from 100 millionmegatons of TNT.12 In the Gulf basin, massive

earthquakes induced slump ing of coastalsediments, while 330-ft [100-m] tsunamisradiated across the Gulf of Mexico and the proto-Caribbean and Atlantic basins.13

Attesting to the physical effect of the impactis a layer of melt spherules found across Haiti, aswell as in the United States, Canada, Spain andNew Zealand. These spherules were produced astons of molten ejecta blasted out of the crater,forming a red-hot plume that circled the globeand rained molten glass for days, sparking firesacross parts of North and South America, centralAfrica, India and Southeast Asia. As a conse -quence, a deposit of ash and soot is preserved inthe sediments of Europe and the western USA.During this time, greenhouse gases increasedmore than a hundredfold, atmospheric sulfurcontent increased by a factor of a thousand, andchlorine gas destroyed the ozone, creating anenvironment that ended the age of the dinosaursand extinguished 75% of the Earth’s species.14

Following the Cretaceous-Tertiary cataclysm,sediments shed from mountain-building eventson the western margin of the Gulf began to fillthe subsiding basin. At the beginning of thePaleocene, clastic detritus from the westresulted in a Lower Wilcox basin-floor fancomprising poorly sorted, gravity-driven arkosicsandstone and siltstones with abundant clays.These arkosic turbidite sandstones are reportedto have permeabilities from 1 to 10 mD andporosities between 14% and 18%.15

As basin fill continued during the EarlyEocene, amalgamated deepwater channel-leveesequences buried the basin-floor fan complex.These Upper Wilcox sediments were depositedunder higher energy conditions than those of theLower Wilcox and are better sorted than theirbasin-floor counterparts. Consequently, theseamalgamated sequences have fewer rock frag -ments, less clay and better reservoir properties,as evidenced by reported values of 50- to 200-mDpermeability and 20% to 28% porosity.

8 Oilfield Review

9. Mink RM, Bearden BL and Mancini EA: “Regional Geologic Framework of the Norphlet Formation of theOnshore and Offshore Mississippi, Alabama and Florida Area,” Proceedings, Oceans ’88 MTS-OES-IEEEConference and Exposition (1988): 762–767.

10. Following burial to depths of 0.6 to 1.2 mi [1 to 2 km] andheating to temperatures of 140°F [60°C], the kerogensserve as primary feedstock for the generation of hydrocarbons.

11. Kring DA: “Composition of Earth’s Continental Crust asInferred from the Compositions of Impact Melt Sheets,”presented at the 28th Lunar and Planetary Science Conference, Houston, March 17–21, 1997, http://www.lpi.usra.edu/meetings/lpsc97/pdf/1084.PDF (accessedAugust 21, 2008).

12. NASA/University of Arizona Space Imagery Center’sImpact Cratering Series, http://www.lpl.arizona.edu/SIC/impact_cratering/Chicxulub/Discovering_crater.html(accessed August 11, 2008).

13. Kring DA: “The Chicxulub Impact Event and Its Environmental Consequences at the Cretaceous-TertiaryBoundary,” Palaeogeography, Palaeoclimatology,Palaeoecology 255 (November 2007): 4–21.

14. For more on the Chicxulub impact and its relationship tothe Cretaceous-Tertiary boundary: Pati JK andReimold WU: “Impact Cratering—Fundamental Processin Geoscience and Planetary Science,” Journal of EarthSystem Science 116, no. 2 (April 2007): 81–98.Simonson BM and Glass BP: “Spherule Layers—Records of Ancient Impacts,” Annual Review of Earthand Planetary Science 32 (May 2004): 329–361.Smit J: “The Global Stratigraphy of the Cretaceous-Tertiary Boundary Impact Ejecta,” Annual Review ofEarth and Planetary Science 27 (March 1999): 75–113.Olsson RK, Miller KG, Browning JV, Habib D and Sugarman PJ: “Ejecta Layer at the Cretaceous-Tertiary Boundary, Bass River, New Jersey (OceanDrilling Program Leg 174AX),” Geology 25, no. 8 (August 1997): 759–762.

15. Meyer D, Zarra L and Yun J: “From BAHA to Jack, Evolution of the Lower Tertiary Wilcox Trend in the Deepwater Gulf of Mexico,” The Sedimentary Record 5,no. 3 (September 2007): 4–9.

16. Some authors have proposed that a collision of theCuban Arc against the Yucatan and Florida blocks duringthe Paleocene and Eocene may have isolated the Gulf ofMexico, prompting a dramatic short-term regressive lowering of sea level through evaporation. This wouldhave allowed reworking of previously deposited Wilcoxsands. As the sea level dropped, these sands would havebeen redeposited onto the deep basin floor in a series ofproximal basin-floor fans. For more on this scenario:Rosenfeld JH and Blickwede JF: “Extreme EvaporativeDrawdown of the Gulf of Mexico at the Paleocene-Eocene Boundary,” presented at the AAPG AnnualConvention, Houston (April 9–12, 2006), http://www.searchanddiscovery.com/documents/2006/06065rosenfeld/index.htm (accessed September 30, 2008).

HAITI

USA

MEXICO

Chicxulubcrater rim

> Chicxulub impact map. Spherules from the impact havebeen found at sites (green circles) along the gulf coast andnortheast coast of the USA, in boreholes drilled off the easternUS coast and in outcrops in Mexico and Haiti. During theimpact, which marked the Cretaceous-Tertiary boundary, Haitiwas located about 435 mi [700 km] south of Chicxulub. (Adaptedfrom Olsson et al, reference 14.)


Autumn 2008 9

Major canyon systems cut through CenozoicShelf margins and channeled the Wilcox clasticsfar from shore.16 These clastics were carried outto the deepwater basin floor (above). Theresulting thick deposits of clastic reservoir rock

are now being targeted for exploration, andoffshore operators have announced discoveriescontaining signifi cant oil accumulations in areasof the Perdido and Mississippi Canyon fold belts,as well as beneath the salt canopy at the Jack,Kaskida and St. Malo prospects.

The Upper Wilcox deposits were buriedbeneath thick layers of deepwater marine shaleduring the Late Eocene. During the Oligocene,another influx of clastic sediment was deliveredby a series of deltas sourced from uplift of the

Second delta

Sand

Fluvial/marineinterface

Not to scale Not to scale

Not to scale Not to scale

Clasticzone

Grain size decreases with energy decrease

Silt Clay HighstandSea level

A’A

Abyssal plain

SlopeShelf

Lowstand fluvial/marineinterface

Slope becomesover-steepenedand unstable

Lowstand

A’A

Former lowstand

New fluvial/marineinterface

New delta forms on shelf

Turbidite gravity processesdeposit fan on basin floor

New highstand

A’A

A’

New delta

Abyssal plain

A

A’

Shelf

Slope

Abyssal plain

Basin-floor fan

River delivers sediments onto the shelf

Slope delta over-steepens with continued deposition Slope delta sediments deposited as basin-floor fan

River

ARiver

DeltaSand

Silt

Shelf

Slope

Shifting fluvial/marineinterface

Former highstand

Falling sea level

A’A

A’

Shelf

ARiver

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Former shorelineShoreline

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Sediment carried to the slope as sea level falls

Perched deltaforms on slope

Shelf deltasubject toerosion

A’

Abyssal plain

ARiver

Eroded delta

Failed delta

Former shoreline

Former highstand

Clay

Abyssal plain

Slope

Perched delta

Slope Lowstand shoreline

Feeder channel

New shoreline

> Moving sands to deeper waters. When a river meets the ocean, watervelocity dictates where it will deposit the sediments it carries in suspension.Heavier materials—typically coarse- to medium-grained sands—drop outfirst. Then, as velocity decreases with distance from shore, finer sands andsilts are deposited, followed by very fine particles that make up clays. Such adepositional progression is seen in the formation of river deltas on thecontinental shelf (map view and cross section, top left ). However, waterlevels rise and fall—the result of glacial activity and cycles of tectonic platedispersion or collision—and this variance has an impact on sedimentaryprocesses. Thus, during periods of glaciation, water becomes locked up incontinental ice sheets, which can dramatically lower sea levels. The ensuingregression draws water away from existing coastlines and deltas until itreaches a maximum fall of sea level, or lowstand. As they become exposedto weather, these coastlines and deltas erode and successively reveal

deposits of sand, silt and clay when the sea recedes. As they are eroded,these sediments are redeposited downbasin—farther from their originalsource—and some rest temporarily on the steeper continental slope, awayfrom the gentler dipping shelf that they were originally deposited on (topright ). As deposition on the slope continues, these water-laden, shelf-edgedeposits become steeper and more unstable (bottom left ). An earthquake,loop current or major hurricane may eventually trigger the release of thesesediments. When they give way, turbidity currents carry the sedimentstoward the abyssal plain, to be deposited in basin-floor fans (bottom right). Inother cases, entire fault blocks can also be transported downdip intact orwith varying degrees of mass translation. With changing glacial or tectonicconditions, sea level will eventually encroach upon the land in what istermed as a transgression. During this highstand, a new delta may formwhere the river meets the sea. (Used with permission of John R. Dribus.)


Sierra Madre range, to the west. Ensuingerosional processes led to sequences of inter -bedded deltaic arkosic clastic sediments, marineshales and volcaniclastics.

By the Early to Middle Miocene, deepwaterclastics entering the Gulf of Mexico basin wereincreasingly sourced from the northernMississippi River system as uplift and erosion ofthe Rocky Mountains continued, and sedimentinput from the Sierra Madres in the west beganto decline. As these western-sourced systemsdiminished, clastic deposits in the Gulf becamemore quartzose and less arkosic, therebycreating reservoir rock with less clay and betterreservoir potential. In the Middle Miocene, sand-rich turbidites, fed almost entirely from theMississippi River system, formed sheet depositsacross the Gulf basin floor, and by Late Miocene,contributions from western river systems becamenegligible (above).

Throughout transgressive and regressivedepositional cycles spanning the Jurassic andMiocene, the Louann Salt has been responding tobasin tectonics, as well as to clastic loadingprocesses from deltas and turbidite fans thatcontinue to this day. Depositional loading hashad profound effects on the salt and thepotential for viable prospects throughout muchof the Gulf of Mexico.

Salt TectonicsA basic knowledge of salt tectonics is helpful inunderstanding how hydrocarbon traps formedabove deposits of salt, and how these same trapslater became covered by thick layers oftectonically emplaced salt. Thick layers of salt,when buried and deformed, result in continentalmargin stratigraphy and structures that areutterly different from those in margins lackingsalt. These tectonic effects are a product of thedistinctive properties of salt.

Pure rock salt is composed of sodium andchloride, forming a mineral known as halite.Other minerals formed by evaporating seawater,such as gypsum and anhydrite, are commonlyinterlayered with halite, and the entire accumu -lation of evaporite minerals is referred to simplyas “salt.” As these minerals precipitate frombrine, they form a crystalline rock.

One of the more important properties of rocksalt is that it is much weaker than surroundingsedimentary rocks, such as sandstone or shale.Its strength diminishes with decreasing crystal -line grain size and increasing tempera ture, orwhen thin films of original seawater remainbetween salt grains.17 Failure in salt often leadsto ductile flow. Even at ambient temperaturesand pressures, salt can flow at a rate of metersper year, as has been measured in the saltglaciers of Iran (next page, top).

Salt is also distinctive for its low density.Freshly deposited mud and sand are less densethan salt. However, these sediments expel theirinterstitial fluids and compact during burial,eventually becoming denser than salt. The saltconsequently becomes more buoyant by compari -son. In the Gulf of Mexico, the average density ofa sedimentary column does not usually exceedthat of salt until the overburden thicknessreaches 1 to 2 mi [2 to 3 km].18 Another impor tantproperty of salt is its permeability. It is so low thatsalt acts as a seal to liquids and gases, and thuscan stop fluid migration and trap hydrocarbons.

Salt is mechanically stable if compressedequally from all sides during burial. However,salt’s low viscosity allows it to flow underunbalanced forces or loads, which occur innature primarily under two conditions.Gravitational loading results when overlying

10 Oilfield Review

Pleistocene

Pliocene

Miocene

Oligocene

Eocene

0.01

1.8

5.3

23.8

33.7

54.8

Age

in m

illio

ns o

f yea

rs b

efor

e pr

esen

t

Epoch

TexasLouisiana

MississippiAlabama

Pleistocene

Pliocene

Miocene

Oligocene

Alaminos Canyon Keathley Canyon Walker Ridge Lund

Atwater Valley

MississippiCanyon

Green CanyonGarden BanksEast Breaks

Eocene

17. Grain size is a function of the sedimentary chemical environment, but it can be altered through deformation.

18. Hudec MR, Jackson MPA and Schultz-Ela DD: “The Paradox of Minibasin Subsidence into Salt: Clues to theEvolution of Crustal Basins,” Geological Society of Amer-ica Bulletin (in press).

19. In the US waters of the northern Gulf of Mexico, all theseforces are imposed by gravity. In the southern Gulf, bothgravitational and plate-tectonic forces are at play.

20. Much of the greatest mountain on Earth actually liesbeneath the Pacific Ocean. Mauna Kea, one of five volcanic masses that form the island of Hawaii, USA,rises from the depths of the Pacific Ocean to a height of 33,476 ft [10,203 m]. Because only about 13,796 ft[4,205 m] is above sea level, it is commonly outranked by Mt. Everest, which is 29,028 ft [8,848 m] high.

> Shifting depocenters. Major depositional centers of the northern Gulf of Mexico basin exhibitsignificant shifts over time, gradually moving west to east and extending basinward from north tosouth. [Modified from Seni SJ, Hentz TF, Kaiser WR and Wermund EG, Jr (eds): Atlas of Northern Gulfof Mexico Gas and Oil Reservoirs, vol 1: Miocene and Older Reservoirs. Austin: Bureau of EconomicGeology, The University of Texas at Austin, 1997.]


Autumn 2008 11

sediments vary laterally in thickness or density,causing the underlying salt to flow laterallytoward thinner or less-dense overburden.Displacement loading is the second form ofinstability. It is driven by tectonic forces andtypically acts horizontally.19 If the sedimentsflanking a salt body pull away laterally, the saltcan stretch and sag into the resulting gap.Conversely, if the flanking sediments presstogether, any intervening salt body will be

squeezed, tending to rise like toothpasteextruded from a tube.

However, even if unbalanced forces areimposed on weak salt, it may not deform. Twoimportant forces resist salt flow. First is thestrength of overlying sediment layers. For salt torise, it must penetrate or lift the sediments aboveit. If the overlying sediments are thick enough,they will be too heavy to be lifted and too strongto be pierced by the salt, despite its buoyancy.

Second is boundary drag, caused by frictionagainst the top and bottom of the salt layer.Where a salt layer feeds a growing salt structurenearby, it becomes exponentially more difficultfor this feeder layer to flow laterally as the saltsource depletes and the layer grows thinner.

Salt is originally deposited in flat layers. Theforces described above transform these layersinto underground mountain ranges of salt—some hundreds of miles long—that can growtaller than the greatest mountains on Earth.20

Because it was originally thought that such saltmasses push through overlying sediments, theyare called diapirs, from the Greek worddiapeirein, to pierce.

Diapirs are unquestionably the tallest andmost spectacular of the various salt bodies (left).Horizontal salt layers may transform intosubsurface mountainous diapirs in three ways.First, where a sedimentary basin is stretched,reactive diapirs can rise to create sharp-crestedridges below strata that are thinned by exten -sional faulting. Second, active diapirs can breakthrough arch-like folds whose crests have beenthinned by erosion, especially in areas wheretectonic squeezing has pressurized the salt.Third, passive diapirs can grow like “islands” ofsalt, exposed on the Earth’s land surface orseafloor, while the base of the diapir andsurrounding sediments sink as the sedimentarybasin fills.

> Allochthonous salt spreading subaerially. Kuh-e-Namak (Mountain of Salt in the Farsi language) is the most famous salt diapir in Iran. This salt glacier(light gray) emerges from an anticline, its summit towering 1,400 m [4,593 ft] above the surrounding plain. Note the vehicle (circled) in the foreground forscale. Here, the Infra-Cambrian Hormuz salt spreads over much younger Jurassic-Cretaceous strata (tan), which form the anticline. The main body of thissalt glacier advances at an average rate of about a meter a year. A collision between the Arabian and Iranian microplates created the Zagros Mountainsand enhanced the rise and extrusion of the salt. (Photograph courtesy of Martin Jackson.)

West

Dept

h, ft

0

5,000

10,000

15,000

20,000

25,000

30,000

East

2 mi

3.2 km

> Rising from the depths. This seismic display shows two salt diapirs beneath the Continental Shelf,offshore Louisiana. The diapir at left, which extends to within about 1,200 ft [366 m] of the seafloor,exhibits a vertical relief in excess of 18,000 ft [5,486 m]. Thinning and upturning of sediments againstthe salt flanks indicate different phases of salt piercement history.


Where the original source layer of salt is thickenough, the crests of the largest diapirs canbegin to spread laterally at or below the seafloor,forming a shallow sheet of salt. The source layerof salt is said to be autochthonous, or formed inplace (above). Autochthonous salt overlies olderrocks and is, in turn, overlain by younger strata.By contrast, the shallower sheets of salt thatspread out from the diapir are said to beallochthonous, or formed out of place and awayfrom their original source. Allochthonous saltsheets overlie younger strata. Thus, while theautochthonous Louann Salt dates back about160 million years to the Jurassic period, theshallow sheets of allochthonous salt derived fromthe Louann Salt may overlie strata as young as1 million years of age.

These fundamental processes of salt tec -tonics combine to create continental margins ofgreat complexity, and no divergent margin ismore complex than the Gulf of Mexico. One wayto better understand this margin is to divide theregion into provinces, each of which has adominant structure or distinctive geologichistory. This approach has become more refinedwith improvements in seismic acquisition and

processing that allow better visualization of thegeometries of the deep salt.

Geoscientists initially investigated this regionusing well data linked by a grid of 2D seismicsurveys. However, the subsalt regions tended tobe poorly imaged, so the structural provinceswere based mostly on mapping of shallow saltstructures.21 The advent of widespread 3Dseismic coverage during the 1990s enabledgeoscientists to start defining structuralprovinces on the basis of deep autochthonoussalt and related structures.22 These refinementshelped shape the following summary of keyprocesses and events, roughly in chronologicalorder, which shows how salt tectonics influencedbasin evolution of the Gulf.

Seismic data reveal that the Louann Saltvaried in thickness from almost zero to perhapsas much as 2.5 mi [4 km] as it accumulated on asurface made uneven by faulting, erosion orvolcanism. Countless cycles of seawater influxand evaporation resulted in this massivethickness of salt. Many of the crustal structurescontrolling original salt thickness are orientedalong a northwest-southeast trend. Verticallyconnected by salt, these deep structures appear

to have influenced much shallower structures,causing them to trend along a similar direction.

Crustal stretching and basin-center riftingsevered the Louann Salt basin into northern(USA) and southern (Mexico) parts. This wasfollowed by cooling of newly formed oceaniccrust and exhumed upper mantle in the center ofthe opening Gulf, which created a densityincrease that caused the basin floor to sink. Theresulting basinward tilt sent the severed saltflowing toward the center of the Gulf. At thesame time, sediments began to pile up on thenew oceanic crust, ahead of the spreading salt.This sedimentation caused the base of thespreading salt to climb over the accumulatingstrata, building a seaward-climbing wedge ofallochthonous salt during the Jurassic and EarlyCretaceous.23 The wedge formed a fringe of salt atleast 19 to 25 mi [30 to 40 km] wide beneath theSigsbee Escarpment between the MississippiCanyon and Keathley Canyon areas, marking thefirst of several salt-sheet emplacements in theGulf of Mexico.

During the Late Jurassic to Miocene periods,folding of strata above the salt began in theWalker Ridge area, along the eastern edge of theSigsbee Escarpment. This folding was partly aresult of loading caused by uneven clasticsedimentation from deltaic systems, whichforced the salt to flow away from thickdepocenters and into areas below thinner layersof sediment. In addition, lateral compressioninduced by tilted strata caused the saltoverburden to buckle.

Some areas, such as the eastern MississippiCanyon, originally contained thin layers ofautochthonous salt and yielded only a fewscattered tall diapirs. However, in other places,such as the Green Canyon and Atwater Valleyareas, thin deposits of salt were subsequentlythickened by salt inflation, beginning in the LateJurassic. Inflation occurred as sediments shedoff the North American continent were depositedinto the thick salt basin and displaced underlyingautochthonous salt ahead of the advancingsedimentary load. The displaced salt flowedhorizontally into peripheral regions, wherethinner layers of salt had been deposited. Asdisplaced salt built up these deposits on theperiphery, salt inflation enabled growth of muchlarger diapirs and folds than would otherwisehave been possible.

During the Cenozoic, folding and thrustingbegan in earnest on the lower Continental Slope.This folding was driven by gravitationallyinduced compression caused by the basinwardslope of the seafloor. The Perdido fold belt, in theAlaminos Canyon area, formed on a thick cushion

12 Oilfield Review

North South

5,000 ft

Allochthonous salt canopy

Stock

Autochthonous salt layer

40,000 ft

45,000 ft

13,715 m

> Evolving salt structures. A thick allochthonous salt canopy spreads laterally beneath theContinental Slope off Louisiana. This layer has been fed by two stocks rising from an underlying layer ofautochtho nous salt, which, in turn, has been nearly depleted as a result of salt withdrawal. The base ofone stock is clearly imaged in the center of the autochthonous layer. To the right of this structure, thesecond stock is largely pinched off.


Autumn 2008 13

of autochthonous salt in the Late Oligocene andEarly Miocene. To the east, the Mississippi Fanfold belt formed on the deep wedge ofallochthonous salt in the Atwater Valley areaduring the Late Miocene. Across a broad areabetween these fold belts extending fromKeathley Canyon to west Walker Ridge, deep foldbelts have not been recognized because they arebelow the deepest part of the basin, which hasbeen poorly imaged by seismic surveys.

Concurrent with this folding was the mostremarkable process of all. From the Miocene tothe present, vast salt sheets spread laterally likepancake batter wherever salt supplies fromdepth were sufficient to feed their expansion.These sheets then coalesced to form shallow saltcanopies. Some shallow salt sheets were fed bymassive salt diapirs sourced from the deepautochthonous layer below. Other sheets werefed by overlying, yet deeply emplacedallochthonous canopies.

This massive spreading of salt was highlyvariable. In the eastern Mississippi Canyon area,where autochthonous salt was thin, onlyscattered, small salt sheets formed. To the west,in the Green Canyon area, where deep salt wasthicker, most diapirs merged into canopies. Evenfarther west, from the Walker Ridge to AlaminosCanyon areas, where autochthonous salt wasthickest, massive diapiric walls of salt fed asingle giant canopy that spread southward formany tens of kilometers.24

Allochthonous salt spread throughout theCenozoic, and its lateral extent increased overtime. The main driver for the Neogene spreadingof canopies was a mid-Miocene switch incontinental sediment sources, which moved fromthe west and northwest to the northern rim ofthe Gulf.25 This switch increased the sedimentaryload in areas where autochthonous salt was stillthick. As the shallow salt sheets surgedsouthward, they either pushed and smearedsmaller salt sheets ahead of them or overrodesmall diapirs that were locally sourced from thin,autochthonous salt.

Clues to how the salt canopies spread arefound along the Sigsbee Escarpment, where aveneer of Pleistocene sediment covers theleading edge of the shallow spreading salt(above). The Sigsbee Escarpment is the largestdeformation structure affecting the seafloor inthe Gulf of Mexico and is the largest exposed saltstructure in the world. The escarpment reaches aheight of approximately 4,100 ft [1,250 m]. It hasa great-circle length of about 350 mi [560 km]and a sinuous and buried length of more than620 mi [1,000 km]. The salt canopies continue to

advance today over about 60% of the escarpment,gradually obscuring much of the subsalt geology.

Initially, salt sheets extrude across theseafloor as salt glaciers, and much of the solublesalt dissolves into the seawater. However, thespreading salt is partly protected by deep-marineclay that has settled as a muddy veneer.Moreover, as the most-soluble salt mineralsdissolve, a mushy layer of less-soluble mineralsremains as a thickening protective blanket.Today, sediments bury almost all of the SigsbeeEscarpment, hindering salt extrusion. Thus, saltand its roof must advance together over the

abyssal plain, causing thrusting along the base ofthe escarpment. Either the compressed sedi -ments ahead of the advancing salt break cleanlyas a single thrust fault, or they are bulldozed intoa tapering prism of thrust slices.

The youngest salt sheets are now found inpristine form along the Sigsbee Escarpment, atthe foot of the Continental Slope. Progressinglandward up the Slope, the covering sedimentsthicken. This increasing sedimentary load on thesheets causes the salt within them to be expelledinexorably seaward.

Sedimentation is highly irregular andtypically creates minibasins in the top of thesalt’s surface. Some minibasins begin as meredimples in the top of the salt sheets, then deepeninto sediment-filled dishes 6 to 25 mi [10 to40 km] wide. Once the minibasins becomegreater than 1 or 2 mi thick, their compacteddensity is enough to make them sink, causingdiapiric salt to well up around them. Otherminibasins form in a different manner entirely.

On the lower Slope, gravitationally inducedcompression wrinkles the sedimentary veneerand initiates minibasins. On the middle Slope,several other mechanisms have been proposed.26

The pattern of sedimentation controls wheresubsidence is greatest and thus molds the top ofthe salt canopies. This structural relief, in turn,creates the local bathymetry, which is the maininfluence on where sediment moves and where itamasses. Here, cause and effect blur because salttectonics and sedimentation affect each other.

Sediment works its way down the ContinentalSlope, following a sinuous path created by partlymerged minibasins, while avoiding bulges on topof salt structures. Some pathways end intemporary or permanent cul-de-sacs, wheresediment is trapped in minibasins. The mini -basins continue to subside until all underlyingsalt is expelled laterally. At this point, a salt weldis formed as sediments that were formerly aboveand below the salt are brought together duringits expulsion. Like a boat grounding at low tide, aminibasin comes to rest on unyielding sedimentinstead of on displaced mobile salt.

21. Diegel FA, Karlo JF, Schuster DC, Shoup RC andTauvers PR: “Cenozoic Structural Evolution and Tectono-Stratigraphic Framework of the Northern Gulf Coast Continental Margin,” in Jackson MPA, Roberts DG andSnelson S (eds): Salt Tectonics: A Global Perspective:AAPG Memoir 65. Tulsa: AAPG (1995): 109–151.Peel FJ, Travis CJ and Hossack JR: “Genetic StructuralProvinces and Salt Tectonics of the Cenozoic OffshoreU.S. Gulf of Mexico: A Preliminary Analysis,” in JacksonMPA, Roberts DG and Snelson S (eds): Salt Tectonics: A Global Perspective: AAPG Memoir 65. Tulsa: AAPG(1995): 153–175.

22. Hall SH: “The Role of Autochthonous Salt Inflation andDeflation in the Northern Gulf of Mexico,” Marine andPetroleum Geology 19, no. 6 (June 2002): 649–682.

23. Peel F: “Emplacement, Inflation, and Folding of an Extensive Allochthonous Salt Sheet in the Late Mesozoic(Ultra-Deepwater Gulf of Mexico),” presented at theAAPG Annual Convention, Denver, June 3–6, 2001.

24. Peel FJ: “The Geometry and Emplacement History of theMajor Allochthonous Salt Sheets in the Central US Gulfof Mexico Slope: A Regional Review,” presented at theGulf Coast Association of Geological Societies Meeting,Austin, October 30–November 1, 2002.

25. Galloway WE, Ganey-Curry PE, Li X and Buffler RT:“Cenozoic Depositional History of the Gulf of Mexico Basin,” AAPG Bulletin 84, no. 11 (November 2000): 1743–1774.

26. Hudec et al, reference 18.

Shallow

Deep

Bath

ymet

ry

> Sigsbee salt. This bathymetric image of theSigsbee salt canopy, offshore Brownsville,Texas, is projected looking east toward NewOrleans. The downslope limit of this salt canopyis known as the Sigsbee Escarpment. Thisallochthonous salt and its thin sedimentary roofare advancing southward by means of thrustfaults at the base of the escarpment. The uppersurface of the canopy is pock-marked byminibasins sinking into salt. [Courtesy of Dr.Lincoln Pratson, Duke University, from Pratson LF and Haxby WF: “What Is the Slope ofthe U.S. Continental Slope?” Geology 24, no.1(January 1996): 3–6.]


14 Oilfield Review

Source rock

Reservoir rock

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ay

Petroleum System Elements

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Seal

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Timing

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Incr

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ng te

mpe

ratu

re a

nd p

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Basement

The patterns of minibasin subsidence, saltthinning and welding are complex but aregenerally viewed as combinations of three endmembers: salt-stock canopy systems, rohosystems and stepped counter-regional systems. • Salt-stock canopy systems are characterized

by evacuated clusters of funnel-shaped saltdiapirs that have coalesced.

• Roho systems are characterized by stretchedsediments that are spread on long smears ofwelded allochthonous salt. A roho system con-sists of a group of listric basinward-dippinggrowth faults that sole, or bottom out, onto anallochthonous salt sheet or weld. (Listricfaults are curved, normal faults that exhibitdecreasing dip with depth.) Sediment wedgesin the fault blocks dip and thicken landward,but become younger seaward.

• Stepped counter-regional systems are distin-guished by sagging sediments on short weldedallochthonous salt sheets. A stepped counter-regional system consists of a major listriclandward-dipping growth “fault” or leaningsalt diapir. This fault is actually a landward-dipping salt weld that passes downward into aflat salt weld and, even more deeply, intoanother landward-dipping salt weld that rootsinto the flat source layer. Sediment wedges dipand thicken seaward.

In these varied ways, thick salt sheets can betransformed into a three-dimensional network ofirregular salt bodies partly connected by thinsmears of salt and arrays of faults.

The Petroleum SystemThe earlier discussions on tectonics anddeposition touched upon key elements requiredfor creation and accumulation of hydrocarbons.These elements, long recognized by the oil and gasindustry, have been codified into a single conceptknown as the petroleum system (above). Aneffective petroleum system comprises thefollowing elements: • source rock containing organic material of suf-

ficient quality and quantity for the generationof hydrocarbons

• temperature and pressure envelope (achievedthrough burial) suitable for converting organicmaterial into hydrocarbons

• hydrocarbon migration process and pathway• reservoir rock with enough porosity to

accumulate and store hydrocarbons and suf-ficient permeability to eventually producethe hydrocarbons

• trap and seal to stop the migration processand provide containment within the reservoir

• timing that ensures hydrocarbon creation andmigration occurred while the trap and sealwere present to retain the hydrocarbons asthey migrated through the system

• preservation to preclude destruction througherosion, tectonics or temperature.

The absence of any one of these elements willcondemn the viability of a prospect. Until the mid1980s, the search for reservoir, trap and seal inthe Gulf of Mexico basin was focused on stratalying above the salt canopy. Although an effective

petroleum system had been confirmed with eachdiscovery made above the salt, there was noevidence that requisite conditions existedbeneath it.

This mindset was challenged in 1983, whenPlacid Oil Company drilled a well through twothin salt sheets before being forced to plug andabandon it in the third salt body it encountered.27

Although the borehole penetrated only 295 ft [90 m] of subsalt sediment, with no indication ofpay, this well drilled completely through twosheets—rather than diapirs. This spurredinterest from other operators that helped set thestage for further subsalt drilling. Then, in 1986,Diamond Shamrock penetrated 990 ft [302 m] ofsalt before drilling out into a 1,000-ft [305-m]reservoir-quality sand section. No hydrocarbonswere encountered in this South Marsh IslandBlock 200 well, but drilling results confirmedthat sandstone of sufficient porosity andpermeability could be found beneath salt. Fouryears later, Exxon drilled a commercial discoveryin 4,350 ft [1,326 m] of water at its Micaprospect, in Mississippi Canyon Block 211. Exxondrilled this deepwater well through 3,300 ft[1,021 m] of salt before discovering a reservoirestimated to contain 100 to 200 million bbl [15.9to 31.8 million m3] of oil equivalent—provingthat an effective petroleum system could indeedexist beneath the salt.28

Today, E&P companies have a much betterunderstanding of the subsalt region, thankslargely to data and experience gained throughdeepwater and subsalt drilling, along withimproved seismic acquisition, processing andimaging techniques.29 There is no longer anydoubt that all elements of the petroleum systemcan be found above and below the salt. Byexploring the subsalt region, E&P companies arelearning how salt affects structure and deposi -tion and how interactions between salt andoverburden influenced the development ofpetroleum systems in the Gulf of Mexico basin.

Geoscientists have come to understand that,as the basin evolved and continued to subside,burial and subsequent heating of organic-richsource rocks of Jurassic—and perhapsCretaceous—age created an excellent system forgenerating hydrocarbons. The deformation of theautochthonous Louann Salt on the floor of thebasin below the source rocks, and subsequentdeformation of the salt into pillows, diapirs andallochthonous salt bodies, resulted in numerousstructural traps. Faults created during extensionof the salt and overlying sediments would, inmany cases, provide conduits for hydrocarbonmigration to potential reservoir rocks above. Insome cases, faulting juxtaposed permeable sands

> Petroleum system. To evaluate the viability of a petroleum system, geoscientists must determinewhether all critical elements exist, such as source rock, migration route, reservoir rock, trap and seal.These elements must be weighed against the timing of key processes including generation ofhydrocarbons and their expulsion, migration, accumulation and preservation.


Autumn 2008 15

against impermeable shales to create traps andseals. Thick deltaic and turbidite clasticsediments created potential reservoir rocks ofvarying quality throughout the Tertiary, fromhigh-permeability and high-porosity quartzosesandstones in younger rocks to less-permeablearkosic sandstones in older rocks. Studies ofbasin history have also indicated favorabletiming of fluid expulsion and hydrocarbonmigration. Thus the northern Gulf’s subsalt playappears to have all the elements necessary for aneffective petroleum system.

Revolution in the Gulf For the first 40 years of drilling in the Gulf ofMexico, it was not unusual for drillers to stopshort of targeted depth once they encounteredsalt. These encounters were not predictable—seismic coverage was often sparse, and it was notuncommon for wildcats to be drilled solely on thebasis of a few lines of 2D seismic data. Moreover,sparse coverage and early processing techniques

sometimes led operators to target poorly resolvedseismic structures or seismic bright-spot anom -alies known as direct hydrocarbon indicators(DHIs). However, these seismic targets some -times turned out to be the top of salt. Havingdrilled to targeted depth without striking pay, butrather finding their bit in salt, most operatorswere reluctant to drill ahead.

One supposed DHI target helped to launchthe subsalt trend in the northern Gulf of Mexico.The Placid Oil Company No. 2 well at Ship ShoalBlock 366, mentioned previously, was drilled to aDHI target that instead encountered three saltbodies before being plugged and abandoned.30

Several other subsalt wells drilled in the 1980sand 1990s also found salt while aiming for DHIs.

In the 20 years following the dry hole at Ship Shoal, more than 140 subsalt wells have beendrilled in the Gulf of Mexico.31 Although somewere not commercial, several of these wells werenotable for extending the trend or setting recordsin their day (above).

Of these wells, only 50 were drilled inrelatively shallow waters of the Outer ContinentalShelf; their water depths ranged from 93 to 560 ft[28 to 171 m]. The rest were drilled on theContinental Slope, in water depths ranging from630 to 7,416 ft [192 to 2,260 m]. There was nogradual and deliberate move from shallow todeeper waters; in the year following its Ship ShoalBlock 366 dry hole, Placid drilled another subsaltwell in 2,004 ft [610 m] of water.32

27. Moore DC and Brooks RO: “The Evolving Exploration of the Subsalt Play in the Offshore Gulf of Mexico,”Transactions, Gulf Coast Association of Geological Societies 45 (1995): 7–12.

28. DeLuca M: “Forty-Six Wells Designated Subsalt in the Gulf of Mexico,” Offshore Magazine 59, no. 1 (January 1999): 50, 52, 145.

29. Camara Alfaro J, Corcoran C, Davies K, Gonzalez Pineda F,Hampson G, Hill D, Howard M, Kapoor J, Moldoveanu Nand Kragh E: “Reducing Exploration Risk,” OilfieldReview 19, no. 1 (Spring 2007): 26–43.

30. Moore and Brooks, reference 27.31. US Department of Interior Minerals Management Service

(MMS), Table of Subsalt Wells, http://www.gomr.mms.gov/homepg/offshore/gulfocs/subsalt/data/Subsalt_Wells.xls(accessed August 11, 2008).

32. MMS, reference 31.

211

349

128

127

292

699

116

346

778

783

12,763

16,563

18,454

14,730

17,976

19,525

21,600

11,833

23,531

16,867

1,328

113

215

192

1,038

1,869

98

96

1,844

1,423

1990

1993

1994

1995

1995

1998

1998

1998

1999

1999

Mica

Mahogany

Enchilada

Chimichanga

Gemini

Atlantis

Hickory

Tanzanite

Thunder Horse

Magnolia

—

—

Dry hole. Targeted a direct hydrocarbon indicator (DHI); drilled through salt.

Dry hole. DHI target proved to be salt; however, 1,000 ft [305 m] of wet,

reservoir-quality sand lay beneath it.

Ship Shoal

South Marsh Island

366

200

ProtractionArea Remarks

BlockNumber feet

YearDrilled

FieldName

Notable Wells of the Subsalt Play

8,203

13,500

138

145

4,356

372

705

630

3,405

6,133

323

314

6,050

4,668

Water Depth

453

475

3,890

5,048

5,625

4,490

5,479

5,951

6,584

3,607

7,172

5,141

meters feet meters

2,500

4,115

1983

1986

Total Depth

562

782

877

640

678

759

292

726

25,624

22,826

23,500

26,804

29,066

28,175

32,500

25,680

1,213

1,347

1,615

1,224

2,145

2,088

1,786

1,433

1999

2001

2001

2002

2003

2004

2006

2007

K2

Mad Dog

Redhawk

Tahiti

St. Malo

Jack

Kaskida

West Tonga

3,979

4,420

5,300

4,017

7,036

6,850

5,860

4,700

7,810

6,957

7,163

8,170

8,859

8,588

9,906

7,827

First significant occurrence of hydrocarbons in five thin pay zones beneath salt.

Put on line before Mica. Became the first commercial development in

the Gulf of Mexico subsalt play.

Salt weld discovery.

Second commercial subsalt discovery; drilled 1,300 ft [396 m] of salt, tested at

2,100 bbl/d [334 m3/d] of oil and 20 MMcf/d [566,337 m3/d] of gas.

Third commercial discovery of the play, in Pliocene-Miocene sands.

Deepest moored floating oil and gas production facility in the world

and also one of the largest.

Penetrated 8,000 ft [ 2,438 m] of salt.

First well tested 1,917 bbl/d [305 m3/d] of oil and 29.7 MMcf/d [841,100 m3/d]

of gas, one of the highest rates in the shallow-water Gulf of Mexico.

Largest field in the Gulf of Mexico.

Tension leg platform (TLP) installed in record water depth for TLPs.

Drilled through 10,000-ft [3,048-m] salt canopy of the Miocene fold trend.

300 ft [91 m] of net pay discovered in Mississippi Fan fold belt.

Produced from the world's first truss spar facility.

Middle Miocene trap beneath 11,000-ft [3,353-m] salt canopy.

First subsalt well of the Wilcox trend, drilled through 10,000 ft [3,048 m] of

Sigsbee salt canopy, with 450 ft [137 m] of net pay.

Wilcox test: deepest extended drillstem test in deepwater

Gulf of Mexico history.

First Wilcox subsalt wildcat located significantly inboard of the Sigsbee

Escarpment, northern frontier of Wilcox prospects. Found 800 ft [244 m] of net pay.

Discovered 350 ft [107 m] of net oil in three Miocene sands.

Mississippi Canyon

Ship Shoal

Garden Banks

Garden Banks

Mississippi Canyon

Green Canyon

Grand Isle

Eugene Island

Mississippi Canyon

Garden Banks

Green Canyon

Green Canyon

Garden Banks

Green Canyon

Walker Ridge

Walker Ridge

Keathley Canyon

Green Canyon

> Subsalt wells. Noteworthy wells that were drilled beneath the allochthonous salt show a range of water depths and targets. (Compiled from pressreleases and US Department of Interior Minerals Management Service, reference 31.)


The subsalt drilling campaigns of the 1980sand 1990s primarily targeted turbidite depositsof Pliocene age, with some Pleistocene andMiocene sands.33 Today, however, in a basinwhere 99% of proven oil reserves are producedfrom formations of Miocene age or younger, theGulf of Mexico subsalt trend is being rejuvenatedfrom deepwater and ultradeepwater discoveriesin much older Eocene and Paleocene sands(above). Discoveries in turbidite channel and fansystems, the deep-basin equivalent of onshoredeposits of the Wilcox formation in Texas andLouisiana, are helping to extend the subsalt play.These turbidite reservoirs have been discoveredmore than 250 mi [400 km] downdip from Wilcoxdelta systems.34

This deepwater Wilcox trend lies in 4,000 to10,000 ft [1,200 to 3,050 m] of water and isthought to cover some 30,000 mi2 [77,670 km2].Some prospects lie beneath salt canopies thatare 7,000 to 20,000 ft [2,130 to 6,100 m] thick.Interestingly, however, the early discoveries inthis trend never penetrated salt. At first,operators tried to avoid the salt by moving todeeper waters to drill outboard of the salt. There,seismic imaging was not distorted by salt, anddrillers had to contend only with familiarchallenges associated with drilling in deepwaters. However, once they established theviability of this deepwater Wilcox trend,exploration teams began chasing their prospectsupdip, beneath the salt, resulting in discoveriessuch as St. Malo and Jack.

The Lower Tertiary Wilcox play was initiatedby the second Baha well drilled at AlaminosCanyon Block 557, a prospect that originallytargeted fractured carbonates of Mesozoic age.In 1996, drilling problems forced the No. 1 well tobe abandoned before reaching total depth, but itdid encounter 15 ft [4.6 m] of pay in an UpperEocene sand, thereby suggesting that a viablepetro leum system and perhaps a commercialdiscovery might exist deeper within the structure.In 2001, the Baha No. 2 well was successfullydrilled to 19,164 ft [5,841 m] and showed theoriginal Mesozoic carbonates to be nonporous.Though this dry hole found only 12 ft [3.7 m] of oilin an Eocene sand, it also identified possiblereservoir-quality sands contained in more than4,000 ft [1,219 m] of a Wilcox turbidite section.35

Shortly thereafter, wells located south ofBaha, such as the Trident prospect (AlaminosCanyon Block 903), and Great White prospect(Alaminos Canyon Block 857), discovered Wilcoxpay sands in the Perdido fold belt of the westernGulf of Mexico. Subsequent drilling ventures tothe east resulted in Wilcox discoveries at theCascade, Chinook, St. Malo and Jack prospectslocated in the Walker Ridge area. The Kaskidadiscovery and the noncommercial Sardinia andHadrian wells in Keathley Canyon helped bridgethe gap between west and east. Data from thesewells allowed geologists to infer that Wilcoxsands extend more than 300 mi [480 km] across

the Gulf of Mexico basin. By 2007, at least 20wildcat wells had been drilled in this trend,resulting in 12 discoveries. Estimated recover -able reserves for each discovery ranged from 40to 500 million bbl [6.4 to 79.5 million m3] of oil.36

The St. Malo discovery at Walker RidgeBlock 678 is distinguished as the first well toreach Wilcox sands beneath allochthonous salt.Another subsalt Wilcox well was drilled at WalkerRidge Block 759—the much-heralded Jackdiscovery.37 A second well was drilled to appraisethe structure. This well—the only well in thesubsalt Wilcox to be tested—produced encour -aging results: it was announced that the Jackwell flowed for 23 days, sustaining a rate of6,000 bbl/d [953 m3/d] of oil, while testing 40% ofthe total net pay interval (next page). To thenorthwest, the Kaskida well marks thenorthernmost frontier for Wilcox subsaltdiscoveries to date and lies farther from the edge of the Sigsbee Escarpment than others ofthis trend.

How many more trends and fields willeventually be discovered beneath the expanse ofthe Sigsbee salt canopy? Once hampered by poorimaging, subsalt exploration has benefitted fromrevolutionary approaches to measuring proper -ties of deep formations. New seismic acquisitiontechniques, together with more accurate velocitymodels and migration algori thms, are helping tomeet the challenge of imaging beneath salt. Inparticular, wide-azimuth and rich-azimuthseismic survey techniques obtain improvedsignal-to-noise ratios in complex subsalt geologyand provide natural attenuation of certain typesof signals that cause multiple reflections.38 TheQ-Marine system capitalizes on less-attenuatedlow frequencies to better image the subsurface.It also provides large, steerable, calibratedsource arrays for better subsalt energy, single-sensor recording to improve noise sampling andattenuation, and the capability to record whilethe vessel turns to a different heading.

With the aid of complementary nonseismictechnologies that measure different properties ofthe subsurface terrain, geoscientists andengineers are building more comprehensivemodels to help E&P companies better determinethe viability of a prospect and identify drillingrisks before moving a rig onto location. Inaddition to seismic data, geoscientists areturning to marine magnetotelluric, gravimetricand electromagnetic surveys. These surveys haveadvanced well beyond first or second generation,and all are acquired by marine survey vessels.

Complementary technologies have been usedto improve delineation of prospects located above

16 Oilfield Review

Keathley Canyon

Green CanyonGarden BanksEast Breaks

Texas Louisiana

Lund

Atwater Valley

Mississippi Canyon

Keathley Canyon

Kaskida

JackChinook

Lower Tertiary TrendLower Tertiary Trend

CascadeSt. Malo

Trident

BahaGreat White

Walker RidgeAlaminos Canyon

> The Lower Tertiary trend. In pursuit of Lower Tertiary targets, operators have moved farther off theShelf into substantially deeper waters. (Modified from Richardson GE, Nixon LD, Bohannon CM,Kazanis EG, Montgomery TM and Gravois MP: “Deepwater Gulf of Mexico 2008: America’s OffshoreEnergy Future, OCS Report MMS 2008-013.” New Orleans: US Department of Interior MineralsManagement Service Gulf of Mexico OCS Region, 2008.)


Autumn 2008 17

salt, where data from marine magneto telluricsurveys help to fine-tune seismic processing byidentifying and measuring the depth andthickness of resistive strata, and by predictingreservoir fluid properties. Subsurface structurescan also be identified by combining gravitysurveys, ocean-bottom profiling surveys and 3Dseismic data to highlight salt domes anddepositional features such as buried sand-richchannels. Controlled-source electromagnetic(CSEM) surveys identify subsurface resistors andcan be integrated with seismic surveys for a morecomplete picture of hydrocarbon traps. Afterdrilling, time-lapse seismic surveys can be run totrack production and evaluate reservoir sweepefficiency. Recognizing the value of suchcomplementary technologies in suprasalt applica -tions, geoscientists are now trying to adapt themto the subsalt regime.

These advances will help geoscientists imagenew prospects and, in turn, spur newdevelopments in drilling, logging and productiontechnologies. The Lower Tertiary trend, a newfacet of the subsalt play, is just the latest wave ofrejuvenation to sweep the Gulf. Thus, explorationcontinues to evolve as advances in technologyreveal new targets and open more frontiers in asupposedly mature drilling province.

Driven by SaltTechnologies developed for exploring the subsaltprovince of the deepwater Gulf, along with theexperience gained in the process, will provehelpful in developing future subsalt plays. TheGulf of Mexico is, after all, just one of 35 basinsaround the world that contain allochthonous saltbodies.39 These salt bodies can be found offshoreAngola, Brazil, Canada, Madagascar, Mexico,Morocco and Yemen. Some basins share remark -able similarities with others around the world.

For instance, a close analog of the SigsbeeEscarpment is seen in the ultradeepwaterKwanza basin off the coast of Angola. The AngolaEscarpment is roughly 685 mi [1,100 km] longand marks the seaward limit of an allochthonoussalt fringe, although the fringe is typically less

than 12 mi [20 km] wide.40 The Scotian basin off the coast of Nova Scotia, Canada, also hassimilarities such as Cretaceous and Tertiaryturbidite deposition, along with traps controlledby lateral and vertical motion of Triassic-Jurassic salt.41

Not all salt bodies are found in offshorewaters; some are in orogenic belts that markepisodes of mountain-building, or are otherwiselandlocked. These salt bodies can be found inAlgeria, Canada, Colombia, Germany, Iran,Kazakhstan, Peru, Spain and Ukraine. Soalthough salt in the Gulf of Mexico basin hasbeen explored by drill bit and seismic boat, saltin mountain ranges has been studied extensivelyin outcrop and explored hands-on. Geoscientistsare recognizing similarities in each, and studiesof salt structures in the field yield insights intothose found beneath the sea.

Comparisons have been made between theGulf of Mexico basin and the Precaspian basin ofKazakhstan and Russia.42 The Precaspian basinwas formed in Permian times as a result of theUralian orogeny. Beyond age differences, both

basins experienced rapid salt deposition andwere dominated by a major source of sedimen -tation (the Mississippi and Volga rivers). Bothalso display salt overhangs that spread intoallochthonous salt sheets. Recognizing differ -ences between basins is also helpful, as in thepresalt play of Brazil. In the Santos basin,different processes are at work. There, largediscoveries within carbonate reservoirs arelocated beneath autochthonous salt and arestructurally and stratigraphically unaffected bysalt tectonics.

Identifying such similarities or differenceshelps E&P companies recognize the presence ofcharacteristics in one basin that may point tocorresponding, yet previously undiscoveredfeatures in analogous basins. Thus, intenselyexplored outcrops—such as the salt glaciers ofIran—or extensively explored basins—such asthose of the Gulf of Mexico, the Precaspian orWest Africa—complement each other in helpingto unlock hydrocarbon potential in other basinsaround the world. —MV

33. Moore and Brooks, reference 27.34. Lewis J, Clinch S, Meyer D, Richards M, Skirius C,

Stokes R and Zarra L: “Exploration and Appraisal Chal-lenges in the Gulf of Mexico Deep-Water Wilcox: Part1—Exploration Overview, Reservoir Quality, and SeismicImaging,” in Kennan L, Pindell J and Rosen NC (eds):Proceedings, 27th Annual Gulf Coast Section SEPMFoundation Bob F. Perkins Research Conference (2007):398–414.

35. Lewis et al, reference 34. 36. Lewis et al, reference 34.37. For more on the testing program for the Jack discovery:

Aghar H, Carie M, Elshahawi H, Gomez JR, Saeedi J,Young C, Pinguet B, Swainson K, Takla E and Theuveny B:

“The Expanding Scope of Well Testing,” Oilfield Review 19, no. 1 (Spring 2007): 44–59.

38. Camara Alfaro et al, reference 29.Multiple reflections, commonly known as multiples, are caused by seismic energy that repeats itself as it isreflected more than once from a boundary. Multiplesoften complicate attempts to discern the image of thesubsurface, and a great deal of effort in seismic dataprocessing is spent attempting to distinguish betweenprimary and multiple energy and then to remove the multiple reflections.

39. Hudec MR and Jackson MPA: “Advance of AllochthonousSalt Sheets in Passive Margins and Orogens,” AAPG Bulletin 90, no. 10 (October 2006): 1535–1564.

40. Hudec and Jackson, reference 39.41. Mukhopadhyay PK, Harvey PJ and Kendell K: “Genetic

Relationship Between Salt Mobilization and PetroleumSystem Parameters: Possible Solution of Finding Commercial Oil and Gas Within Offshore Nova Scotia,Canada During the Next Phase of Deep-Water Exploration,” Transactions, Gulf Coast Association of Geological Societies 56 (2006): 627–638.

42. Lowrie A and Kozlov E: “Similarities and Differences in Salt Tectonics Between the Precaspian Basin, Russia, and the Northern Gulf of Mexico, USA,” Transactions, Gulf Coast Association of Geological Societies 54 (2004): 393–407.

Texas Louisiana

Jack

Mississippi

> Preparing to test. The Jack 2 well, drilled by the Discoverer Deep Seas drillship, was cased andsuspended before the Cajun Express semisubmersible rig moved in for an extended well test. Bargeswere also brought in to collect fluids produced by the test.


18 Oilfield Review

1. Camara Alfaro J, Corcoran C, Davies K, Gonzalez Pineda F,Hill D, Hampson G, Howard M, Kapoor J, Moldoveanu Nand Kragh E: “Reducing Exploration Risk,” Oilfield Review 19, no. 1 (Spring 2007): 26–43.

2. Production in the seismic sense means production ofseismic data. Therefore, productivity is the amount oftime a seismic vessel spends recording useful data relative to the total time the vessel is in the survey area,usually expressed as a percentage.

For help in preparation of this article, thanks to Tim Buntingand Mikael Garden, Kuala Lumpur; Iain Bush, Edward Hager,Hasbi Lubis, Gary Poole, Bruce Webb and Phil Williams,London; William Dragoset, Houston; and Jens Olav Paulsen,Oslo, Norway.Coil Shooting, Monowing, Q-Fin and Q-Marine are marks ofSchlumberger.

Shooting Seismic Surveys in Circles

Michele BuiaPablo E. Flores Eni E&PMilan, Italy

David Hill Ed PalmerRob RossRobin WalkerGatwick, England

Marianne HoubiersMark ThompsonStatoilHydroTrondheim, Norway

Sergio LauraEni IndonesiaJakarta, Indonesia

Cem MenlikliTürkiye Petrolleri Anonim Ortaklıgı (TPAO)Ankara, Turkey

Nick MoldoveanuHouston, Texas, USA

Earl SnyderJakarta, Indonesia

Traditionally, marine seismic data are acquired by a seismic vessel sailing in a straight

line over a target, then turning back to shoot another line parallel to the first. A new

technique acquires seismic data in continuously linked circles with little or no

nonproductive time. The results are high-quality data containing reflection information

from all azimuths. Test results indicate that the technique will be useful for improving

seismic imaging in several complex geological environments. The first full survey

using the technique was acquired for Eni in 2008 on the Tulip project in the Bukat

production-sharing contract block, offshore Indonesia.

Many of the world’s most significant technicaldevelopments were envisioned long before theybecame commercial. For example, Leonardo daVinci’s 15th century designs probably played apart in the development of the helicopter andscrew propeller. Within the E&P industry, recentdevelopments by WesternGeco in 3D seismicimaging systems apply fundamental principlesdefined decades ago that had to await advancesin technology to realize their potential. Thesedevelopments have now enabled circularshooting—another idea from the past—tobecome a reality.

The seismic industry performed early trials ofcircular acquisition geometries in the 1980s.However, it was not until 2006 that WesternGecorealized that it could make a circular acquisitiontechnique a practical option for 3D surveys.

Three-dimensional seismic surveys haveprobably done more than any other moderntechnology to increase the likelihood of explora -tion drilling success.1 Subsurface imaging using3D surveys has proved particularly succes sful forimaging clastic sediments; however, accurateimaging of sediments beneath hard sea floors,salt, basalt and carbonate layers remains achallenge, particularly in deep water.

In deep water, towed-streamer geometries arecurrently the only economically viable solutionsfor acquisition of large 3D seismic datasets.

Conventional marine 3D surveys, acquired as a setof adjacent parallel straight lines, have provedtheir value as exploration tools in a wide variety ofgeological settings. These surveys image thesubsurface with seismic raypaths that are alignedpredominantly in one direction. Complex geologyand highly refractive layers cause ray bending thatcan leave portions of the subsurface untouchedwhen recording seismic waves traveling in just onedirection. In such circumstances, conventional 3Ddata may provide ambiguous or misleadingimages, reducing confidence in explorationdecisions and potentially introducing uncer -tainties and inaccuracies in models used forreservoir development.

Wide-azimuth (WAZ) seismic surveys providedata from raypaths traveling in a wide range ofdirections. The method has been shown to deliverbetter illumination of the subsurface, highersignal-to-noise ratio and improved seismic resolu -tion in several complex geological environ ments,such as beneath large salt bodies with complexshapes. Until recently, in deep water, thisimproved method of imaging has required severalseismic vessels working together.

This article reviews developments in towed-streamer WAZ acquisition and introduces CoilShooting acquisition: a new technique that goesbeyond WAZ to acquire a full range of azimuths


Autumn 2008 19

When the vessel gets back to the other edgeof the survey area, it turns to follow anotherracetrack-like course displaced laterally from thefirst. This continues until coverage of that part ofthe survey area is completed.

Usually, no data are recorded while the vesselis turning because, in conventional acquisitionsystems, streamers do not maintain their lateralseparation during turns, and the positions ofreceivers within the streamers cannot beaccurately calculated. Additionally, turning mayinduce increased lateral drag on the streamersas they move through the water, resulting inincreased levels of noise. Depending on surveydimensions, vessels can spend up to 50% of thetime available for production on line changes, soline changes represent a significant period ofnonproductive time (NPT).2 This limitation cancompromise data quality: to minimize NPT, andhence costs, some surveys are shot in the optimaldirection for efficiency but not the best directionto achieve geophysical objectives.

In conventional surveys, the direction, orazimuth, of a seismic ray traveling down from thesource into the subsurface then up to a receiver

using a single vessel shooting continuously with acircular or curved path. We describe modelingand feasibility tests, which indicate that thetechnique has considerable potential forefficiently addressing imaging challenges incomplex geological settings. Also presented aresome details of the world’s first full Coil Shooting project.

Wide-Azimuth Towed-Streamer AcquisitionConventional marine 3D surveys acquire datafrom a vessel sailing in a series of adjacentparallel straight lines. The vessel is typicallyequipped with one or two airgun source arraysand 8 to 10 streamers. When the vessel reachesthe edge of the defined survey area, it continuesin a straight line for one-half the length of astreamer, then turns around in a wide arc toposition itself for another straight line in theopposite direction, as if following the course of asimple racetrack (right).

> Typical conventional deepwater 3D acquisitionconfiguration. The acquisition path follows astraight line (blue arrow) then turns 180° toacquire data in the opposite direction (orangearrow). No data are normally recorded duringline turns (black).


20 Oilfield Review

> Conventional single-vessel streamerconfiguration. A vessel tows an airgun sourcearray and 10 streamers, each containing about2,000 receivers. Streamers are typically 6 to 8 km[4 to 5 mi] long and 100 m [328 ft] apart.Downgoing seismic rays (green) emanate fromthe source. They reflect at the seabed and atsubsurface interfaces then travel upward (red)to the receivers where they are recorded. Theillustration shows only raypaths to the first andlast receivers in each streamer. The direction, or azimuth, between the seismic source andreceivers is close to the direction of the vesseltrack, particularly for far offsets—the datarecorded by receivers farthest from the source.

> A four-vessel wide-azimuth acquisition configuration. Two recordingvessels (left and right ), both equipped with an airgun source array and 10 streamers, are joined by two source vessels (center). The source on the left-hand vessel is fired, and data are recorded by streamers on bothrecording vessels, providing two areas of subsurface coverage (dark tan).

Sources are then fired in sequence by the other vessels, providing a widerarea of subsurface coverage (light tan) and a broader range of source-receiver azimuths than can be achieved by a single vessel. Sail lines maybe repeated with source vessels in different positions, providing differentranges of azimuths.


Autumn 2008 21

will be close to the direction of the vessel track(previous page, top). Azimuths for far offsets willtypically be within ±10° of the vessel track. Nearoffsets will have a higher range of azimuthsbecause of the lateral displacement between thesource and the front of the streamers.

Complex geology and highly refractive layersbend seismic rays so that portions of thesubsurface may remain untouched by seismicwaves, particularly when source-receiver geome -tries provide only a narrow range of azimuths. Ananalogy to this phenomenon, whereby the azimuthof observation impacts the results of imagingthrough media with complex geometries, can bemade by viewing an object through textured glass(above). Viewing the glass from several differentdirections will enable the viewer to determine itscontents more accurately. Similarly, acquiringseismic data with a broad range of azimuths hasbeen shown to deliver more-accurate images ofthe subsurface in complex geologicalenvironments, such as those associated with saltbodies, by essentially “shining a light” on theformations from many directions.

Various towed-streamer acquisition geome triesthat increase the range of source-receiver azimuthshave been tested in several locations, including theNile Delta, the North Sea and, most prominently,the Gulf of Mexico. These surveys typically usethree or four seismic vessels, each shooting instraight parallel lines (previous page, bottom).

Since 2001, the WAZ technique has been usedin several surveys in which one or more recordingvessels, following essentially the same racetrack-like course as for a conventional 3D survey, arejoined by source vessels positioned in front ofand/or behind the streamer spread, and offsetlaterally at various distances on each side of the

spread. The technique typically provides analmost full range of azimuths at near offsets butonly ±30° for far offsets.

In 2006, WesternGeco acquired a survey inwhich a WAZ geometry was deployed in twoopposite sailing directions for each of threedifferent orientations—effectively covering thesubsurface six times. When combined, theresulting 3D dataset contained contributionsfrom a complete range of azimuths for mostoffsets. This survey, acquired over the Shenzifield in the Gulf of Mexico, was the world’s firstrich-azimuth (RAZ) seismic survey.3

A 2007 study concluded that these types ofsurveys, combined with accurate velocity modelsand high-fidelity migration algorithms, couldprovide a step-change improvement in subsaltillumination, signal-to-noise ratio and attenua -tion of multiples, compared with conventionalnarrow-azimuth (NAZ) surveys.4 The study foundthat wider crossline offsets led to better results,and that the best results were from data acquiredover a complete 360° range of azimuths, asdelivered by RAZ geometries.

The RAZ and WAZ towed-streamer geometriesdescribed above were all acquired as a series ofadjacent straight lines. As with a conventional3D survey, the time taken to turn the recordingvessel between lines is usually nonproductivetime. For multivessel operations and widestreamer spreads, this turning time is typicallymore than three hours per sail line, adding up toseveral weeks for a large survey. Anotherpotential problem with parallel geometries isthat they can leave undesirable acquisitionartifacts in the data, such as stripes in thedirection of sail lines that can be seen in theprocessed dataset.

3. Howard M, Harding C and Stoughton D: “Rich AzimuthMarine Seismic, A Cost Effective Approach to BetterSubsalt Images,” First Break 25, no. 3 (March 2007): 63–68.

4. Kapoor S, Moldoveanu N, Egan M, O'Briain M, Desta D,Atakishiyev I, Tomida M and Stewart L: “Subsalt Imaging:The RAZ–WAZ Experience,” The Leading Edge 26, no. 11(November 2007): 1414–1422.Multiples are seismic energy that has bounced betweenmore than one reflecting surface. A form of noise thatcan interfere with or obscure primary reflection events,multiples are suppressed by algorithms applied during processing.

> Image distortion. Refraction of light through the irregular surface of a glass causes parts of the spoon to be invisible or distorted. The image changes dependingon the direction of view. Similarly, the azimuth of observation impacts the results of seismic imaging through geologic media with complex geometries.

Circular AcquisitionWhile acquiring the Shenzi seismic survey,WesternGeco and the operator—BHP Billiton—agreed that it might be worthwhile to continuefiring sources and collecting data during line turns.The results of this experiment were extremelyencouraging. The first stage of processing for thesedata, acquired using Q-Marine single-sensortechnology, included an advanced noise-attenuation algorithm, which effectively addressedany increase in the levels of ambient noise toprovide useful data at the edge of the survey area.In addition, acquisition productivity was increasedthrough elimination of nonproductive time duringline changes.

Because sail lines acquired during linechanges approximate arcs of circles, they can beconsidered as a partial implementation ofcircular acquisition geometry. The success ofcontinuous acquisition during the Shenzi RAZsurvey convinced WesternGeco to investigate thepossibility of employing circular geometry forwide-azimuth towed-streamer acquisition.

Like many fundamental seismic acquisitiontechniques, some potential benefits of circulargeometry for marine acquisition have beenknown for many years. In the 1980s, it wasproposed that sailing in concentric circlesaround salt domes would improve structural


22 Oilfield Review

5. French WS: “Circular Seismic Acquisition System,” US Patent No. 4,486,863 (December 4, 1984).

6. Durrani JA, French WS and Comeaux LB: “NewDirections for Marine 3-D Surveys,” ExpandedAbstracts, 57th Annual International SEG Meeting, NewOrleans (October 11–13, 1987): 177–181.

7. Ongkiehong L and Huizer W: “Dynamic Range of the Seismic System,” First Break 5, no. 12 (December 1987): 435–439.

8. Christie P, Nichols D, Özbek A, Curtis T, Larsen L,Strudley A, Davis R and Svendsen M: “Raising theStandards of Seismic Data Quality,” Oilfield Review 13,no. 2 (Summer 2001): 16–31.

9. Woodward M, Nichols D, Zdraveva O, Whitfield P andJohns T: “A Decade of Tomography,” Geophysics 73, no. 5 (September–October 2008): VE5–VE11.

10. Fold of coverage is the number of seismic traces thatmap to a defined area, typically 25 m by 25 m [82 ft by 82 ft].

11. Moldoveanu N: "Circular Geometry for Wide-AzimuthTowed-Streamer Acquisition," presented at the 70thEAGE Conference and Exhibition, Rome, June 9–12, 2008,paper G011.

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acquires short-offset data, something not possiblewith multivessel WAZ geometries. The methodalso delivers data sufficiently sampled in azimuththat the dataset can be split into differentazimuth ranges for building anisotropic velocitymodels and analyzing fractures (above).9

The Coil Shooting technique involves a singlevessel equipped with multiple streamers and aseismic source. The vessel sails along a pattern ofoverlapping circular or curved sail paths thatcover the survey area, shooting and recordingdata continuously. This continuous mode ofacquisition virtually eliminates NPT, so it is

imaging of the flanks of the domes and associ -ated faulting.5 Test surveys were acquired in theGulf of Mexico and in the North Sea usingconcentric circle acquisition.6 However, becausethe marine acquisition technology at that timedid not allow proper implementation of themethod, it was abandoned.

The Q-Marine system, introduced in 2000,has overcome many of the challenges inherentin circular acquisition geometries, enabling itsuse for several new applications. Q-Fin steeringdevices precisely control the depth and lateralposition of the streamers, making it possible tomaintain constant streamer separation.Monowing multistreamer towing technology ishighly effective at maintaining lateral streamerdisplacement while turning. Shaped like anaircraft wing, Monowing deflectors provide forceperpendicular to the sailing direction to keepthe wide streamer spread in position. Monowingdeflectors are mounted close to the edge of theouter streamer. By contrast, conventionaldeflection devices are mounted outside thestreamer spread, resulting in a much larger totalequipment spread that necessitates a largerturn radius.

An acoustic network provides accuratepositioning of the in-sea equipment. Large cali -brated source arrays deliver deep-pene trating

energy, and an advanced digital source controllerprovides a fully calibrated airgun sourcesignature for every shot.

In the presence of strong cross-currents,towing streamers in a curve can increase noiselevels in the raw field data. Q-Marine technologyleverages advances in electronics and fiber-opticnetworks to provide high channel-countrecording systems, enabling finely sampledsingle-sensor recording of both signal and noisein the seismic wavefield. Shell geophysicistsdocumented the potential of the single-sensormethod in the late 1980s, but limitations inhardware and processing capabilities at the timeprevented full realization of its benefits.7

Adequately sampling streamer noise allowstargeted signal-processing techniques to sup -press it while preserving the integrity of theseismic signal. Part of the digital group forming(DGF) process, this effective noise removalallows acquisition of high-quality seismic dataeven in poor weather or when towing streamersthrough strong currents.8

Using circular geometry for towed-streameracquisition offers benefits for both geophysicalanalysis and operational efficiency. The CoilShooting technique acquires well-sampled, full-azimuth (FAZ) data, providing more completeillumination of the subsurface and benefitingnoise reduction and multiple attenuation. It

> Comparison of acquisition geometries (bottom) and azimuth-offsetdistribution plots in rose diagrams (top). The number of traces recorded foreach offset-azimuth combination is color-coded in the rose diagrams.Offset corresponds to distance from the center of each circle. Azimuthcorresponds to the angle within each circle. Colors range in order frompurple and blue for a low number of traces, to green, yellow and red for ahigh number of traces. From left to right: Traditional marine surveys areacquired by one vessel in one azimuth and produce data with a narrowazimuth-offset distribution. Multiazimuth surveys are acquired by one

vessel sailing in multiple directions and have azimuth-offset distributionsclustered around the direction of the sail lines. Wide-azimuth surveys areacquired by several vessels, increasing the azimuth range for many offsets.Rich-azimuth surveys use several vessels shooting in several directions,combining the concepts of multiazimuth and wide-azimuth surveys todeliver contributions for most azimuth-offset combinations. The CoilShooting single-vessel technique delivers a high number of contributionsfor a complete range of azimuths for all offsets.


Autumn 2008 23

highly cost-effective for acquiring data withenhanced azimuthal contributions, particularlyfor appraisal and development projects, and forparts of the world where it is impractical tomobilize several vessels. For parallel geometries,vessels are typically productive about 45% of thetime they are in a survey area. With circulargeometry, this can double to 90% of availableacquisition time. For parallel geometries, thelast half-streamer length of each straight lineacquires low fold of coverage in a “taper-off”mode.10 This typically means that 3 km to 5 km[1.9 mi to 3.1 mi] of each straight line are ofdegraded quality. By contrast, the Coil Shootingmethod provides well-sampled data close to theedge of the whole survey area. Continuous lineacquisition is also highly efficient for conven -tional 3D projects, in which shooting whileturning provides valuable additional data for arelatively small additional effort.

Gulf of Mexico Feasibility TestBased on the successful acquisition of dataduring line turns for the 2006 Shenzi survey, aCoil Shooting feasibility test was performedduring 2007 in an area of the Gulf of Mexicopreviously covered by a parallel WAZ survey.11 Aprimary objective of this first test was todetermine whether it is feasible to sail using acircular geometry while maintaining constantstreamer separation and accurately measuringreceiver positions. Another objective was toprovide an indication of any relationshipbetween the curvature of streamers while towedin a circular trajectory and the levels of noiseintroduced. The test would also determine if CoilShooting data could be processed and imaged,and give an early indication of the effectivenessof the method for delivering high-quality, full-azimuth data.

Prior to acquiring the test data, WesternGecomodeled the coverage, offset and azimuthdistribution for circular geometry assuming asurvey area of 42 km x 42 km [26 mi x 26 mi] anda vessel equipped with a single source and 10streamers, each 7 km [4.4 mi] long separated by120 m [394 ft]. This streamer configuration istypical of a WAZ acquisition geometry. The modelassumed that data would be acquired by a vesselfollowing a set of circles, separated from eachother by a fixed distance in both x and ydirections (right).

Fold of coverage is highest over the targetarea in the middle of the survey and decreasestowards the fringes. Azimuth-offset distributionacross the modeled circular geometry survey was

analyzed for three different areas, presented as“rose diagrams.” This analysis shows that thecircular geometry provides full-azimuth

distribution over the target area and a reducingrange of azimuthal contributions in a fringearound the edges of the survey area.

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> Azimuth and offset distribution for a Coil Shooting 3D survey. Data are acquired by a vessel sailingin a circular path (top right ). When transit of one circle is complete, the vessel moves to a secondcircle separated by a fixed distance from the first, and this is repeated until the survey area is covered.The figure on the top left shows a grid of circles covering a survey area. The second diagram on theleft is a coverage plot, displaying the trace density across the modeled survey area. This shows a highnumber of traces in the middle of the survey area (color-coded red), reducing to fewer traces at theedge of the area (green, blue and purple). On the right are rose diagrams indicating average azimuth-offset distribution for three parts of the survey area. Red indicates a high number, decreasing throughyellow, green and purple. The area at the center of the survey has a complete range of azimuths andoffsets. The area at the edge of the survey receives no azimuths between 90° and 270°. The region inthe corner of the survey receives azimuths mostly from 0° to 90°. The bottom-left diagram is a “spider”plot illustrating the offset and azimuth of all traces within one typical 25-m x 25-m bin at the center ofthe survey area. Distance from the center of the circle corresponds to offset, and angle within thecircle corresponds to azimuth.


For the purpose of comparison, analysis ofthe azimuth-offset distribution was also per -formed for a parallel WAZ geometry surveyacquired with a four-vessel configuration. Nearoffsets are better recorded with circular geome -try than with the parallel WAZ geometry becauseof the high lateral displacement between sourceand recording vessels in parallel geometries.Near offsets are needed to image shallow over -burden, and fully sampled data, both in azimuthand offset domains, enable more effectiveapplication of processing algorithms that removenoise and improve resolution.

The high density of shot locations achievedthrough continuous acquisition results in highertotal fold of coverage than could typically beachieved within the same number of days using aparallel WAZ geometry survey acquired with twosource vessels and two recording vessels with thesame streamer configuration. Well-sampled datawith higher fold result in higher signal-to-noiseratio in the processed dataset.

Following the modeling exercise, a field testwas performed to investigate the practicalities ofacquiring data using the modeled circulargeometry. Four overlapping circles with different

24 Oilfield Review

12. Palmer E, Bacon J, Toygar AR, Uygun S and Menlikli C:“A Complex, Deepwater Seismic Survey Produces HighQuality Results,” World Oil 229, no. 7 (July 2008): 89–93.

Wide-Azimuth Data Circular-Geometry Data

> Comparison between E-Octopus 3D prestack depth migration of full-aperture, full-fold WAZ data(left ) and circular-geometry test data (right ). The Coil Shooting data exhibit some indications ofimproved imaging, such as the higher amplitude and better continuity of the salt overhang in the top-left area of the section.

Gulf of Mexico Coil Shooting Test

> Acquisition geometry for the Gulf of Mexico Coil Shooting test. The plotshows areas containing traces from each of four circles acquired withdifferent radii, colored orange, yellow, green and blue.

radii were acquired in April 2007 by the seismicvessel Western Regent over an area covered bythe E-Octopus project (left). E-Octopus is aWesternGeco multiclient program coveringseveral hundred blocks in the Green Canyon andadjacent areas of the Gulf of Mexico. The projectis designed to deliver more-precise base andedge of salt definition through the integration ofmagnetotelluric, gravity and Q-Marine WAZseismic data.

The Coil Shooting acquisition test resultsproved that, using Q-Marine technology, it isfeasible to sail along circles while maintainingconstant streamer separation and achievinghighly accurate receiver positioning. After theDGF process, ambient noise levels wereacceptable for all the test data and comparableto those encountered in straight-line parts of the test.

The Coil Shooting test data were processedusing the same sequence as applied to theparallel WAZ data, including single-sensorcoherent noise attenuation, DGF at a 12.5-m [41-ft] group interval, shot-by-shot bubbleremoval and anomalous noise attenuation.Three-dimensional prestack depth migration wasperformed with the same velocity model used forparallel WAZ data. Despite low fold and limitedmigration aperture, the four-circle test datacompare favorably with the full-aperture, full-fold parallel WAZ data (left).

Black Sea TestThe second field test of the Coil Shootingtechnique was in an area of the Black Sea knownto have strong sea currents and subsurfaceimaging challenges related to complex geology.This test built on the success of the Gulf ofMexico test, which had already confirmed thefeasibility of acquiring and processing seismicdata with a circular geometry. The objective ofthe Black Sea test was to build experience andidentify technological developments and proce -dures required to better support the method,particularly in terms of survey design, acquisitionoperations, quality control and data processing.

WesternGeco acquired a conventional NAZ3D survey between September 2006 and January2007 for Türkiye Petrolleri Anonim Ortaklıgı(TPAO) in the Kozlu area of the Black Sea (nextpage, top).12 The NAZ survey was acquired by theseismic vessel Western Pride, using Q-Marinetechnology. Water depth in the area ranges from


Autumn 2008 25

1,100 to 2,200 m [3,600 to 7,200 ft]. The target forthis exploration seismic survey included poten -tial reservoirs related to a complex sequence oflimestone reefs and shales at depths of 3,500 to4,000 m [11,500 to 13,100 ft], overlying volcanicstructures. Parts of the target strata have lowacoustic impedance contrast with rocks aboveand below, so create only weak reflections. Theoverburden includes layers of gas hydrates,which can inhibit transmission of seismic energy.The seabed is rugose, and complex near-seabedgeology results in strong diffractions. In someareas, the target is masked by strong water-bottom multiple energy, including multiples ofthe diffractions generated near the seabed.

The Q-Marine data, combined with anadvanced processing sequence to address thestrong multiples and other noise, delivered ahigh-quality seismic image. Experience gained inacquiring and processing this dataset suggestedthat the geological and geophysical challenges ofthe area would benefit from an enhanced-azimuth seismic imaging approach such as theCoil Shooting technique.

During acquisition of the NAZ survey, stronglocalized currents were encountered; these werethought to be related to the undulating seabed.These currents tested the Q-Marine streamer-steering system and also provided anotherlearning opportunity for the subsequent CoilShooting test. The currents were strong enoughto cause the spread of eight streamers, each 6 kmlong, to bend and deflect, sometimes increasingfeather angle by more than 15° within the spaceof 6 km (right). Despite these strong currents, thestreamer array remained parallel and under goodcontrol throughout the survey.

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. The effects of strong currents in the Kozluarea. The illustration at top left shows the shapeof the eight streamers for one example locationof the 2006/2007 Kozlu NAZ 3D survey. Acrossline offset of zero represents the directionof sailing. Localized currents caused significantbending and deflection, or feathering, of thestreamer spread from the direction of sailing.The same currents were observed during the2007 Coil Shooting test. The middle figuresdisplay streamer positions in three parts of oneacquired circle. Current direction is shown bythe red arrows. When shooting perpendicular tothe current direction (left and right ), streamersare deflected. When shooting parallel to thecurrent direction (center), streamers follow thecourse of the vessel around the circle. Thegraph (bottom) plots noise in the field dataagainst the azimuth of the vessel. Noise ismeasured as the root-mean-square (RMS)amplitude of data between 0.5 and 2 s two-waytime, which is earlier than the first reflections.The graph indicates that the direction of towingclearly impacts noise levels in the streamers.


TPAO agreed to have WesternGeco perform aCoil Shooting test survey over its acreage. Vesselcommitments meant that only a four-day timeslot was available for acquisition of the test datavolume. A suitable survey design had to bederived that would allow efficient acquisition of afit-for-purpose dataset in this short time frame.To meet the objectives of the test, the datasetwas required to have full-azimuth and close tofull-fold coverage over a geographical areasufficiently large to enable generation of a 3D-migrated image suitable for analysis andcomparison with data from the NAZ survey.

The geometry modeled for the previous Gulf ofMexico test involved a series of circles thattranslated laterally by a fixed distance. Thisdesign is not efficient for a small test area. Aninnovative solution was required to quickly

achieve coverage of a small, full-azimuth, high-foldarea. One proposal was for the vessel to follow thepattern of the edges of the petals of a flower suchas a dahlia. The design ultimately selected for theBlack Sea test was a “half-dahlia,” comprisingnine circular coils rotated about a fixed point. Thiswas expected to deliver a 2-km x 5-km [1.3-mi x3.1-mi] area of adequate coverage within theallocated time frame.

The Kozlu Coil Shooting test data wereacquired within three days during December 2007by the seismic vessel Western Monarch. As withdata from the Gulf of Mexico test and later CoilShooting projects, levels of noise in the field datawere observed to fluctuate considerably withineach of the nine circles acquired (above).Experience to date indicates that tow ing a

streamer in a curved trajectory will increaseaverage noise levels relative to shooting in astraight line. A lesson learned from the Kozlu test,and supported by other Coil Shooting projects, isthat current direction has a signifi cant impact onhow and when noise levels increase.

During acquisition of the Kozlu test dataset,the dominant current was flowing in anapproximately northeasterly direction. Whentowed along part of a circle perpendicular to thiscurrent, streamers were observed to feather tothe northeast. When towed with or against thecurrent, streamers remained close to the track ofthe vessel. Plotting average noise levels in all theacquired test data against source-receiverazimuth—approximately the towing direction—shows clearly that noise levels are highest whentowing perpendicular to the current.

Q-Marine field data are recorded with singlesensors at 3.125-m [10.25-ft] intervals along eachstreamer. This spacing is sufficiently small tosample most noise, enabling it to be recognizedand removed by data-adaptive algorithms applied within the DGF process. Shots with lowlevels of ambient noise are free of noise after theDGF process. For shots with higher levels ofambient noise, some residual noise may remainafter DGF, but this is attenuated duringsubsequent processing.

The Coil Shooting test data were processedusing a sequence comparable to that applied tothe previously acquired NAZ data, includingprestack time migration. A new technology, 3Dgeneral surface multiple prediction (3D GSMP),was applied to the test data volume.13 Thismethod is effective for attenuating multiples,while preserving the integrity of primary energy.The technique is useful in areas of complexgeology, such as rugose surfaces and crosslinedip, where the geophysical assumptions of manyother demultiple techniques break down. Unlikemany other algorithms, 3D GSMP can be appliedto multiazimuthal data, as generated by CoilShooting acquisition.

The Kozlu Coil Shooting test achieved itsobjectives. The innovative survey design enableda fit-for-purpose dataset to be acquired withinthe allotted time. It also provided valuableknowledge about the effects of ocean currents onnoise levels. The test dataset was small and maynot include sufficient migration aperture toaccurately image all reflection events. Neverthe -less, the processed results compare favorablywith the previous NAZ survey (next page, top).The Coil Shooting data show more continuity atthe top and bottom of the carbonate reef targetand improved fault resolution in several parts of

26 Oilfield Review

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the section. The results indicate that full-azimuth acquisition will improve the quality andreliability of seismic imaging in the area.

Full Deployment in IndonesiaIn October 2007, WesternGeco presented the CoilShooting technique at the Milan headquarters ofthe E&P division of Eni, a company with experi -ence in several projects involving wide- andmultiazimuth imaging and with a history ofdesigning and applying innovative marineacquisition techniques. The Eni E&P geophysicalteam immediately recognized the benefits of thetechnology and worked to identify a suitablelocation where the technique could be expectedto resolve imaging challenges better than othertechniques. Eventually the company chose theTulip structure in its Bukat production-sharingcontract block, offshore Indonesia.

The Tulip field has complex geology, and thetarget has low P-wave impedance, so only weakseismic reflectivity. By contrast, the waterbottom is strongly reflective, and there is abottom-simulating reflector (BSR) across thewhole survey area.14 Parts of the existing 2Dseismic data exhibit up to six reverberations ofwater-bottom and BSR-related multiples, whichcontaminate the weak primary reflections. Theseafloor topography is highly undulating, withridges and canyons. Anomalies close to theseabed create diffractions that propagatethrough the section. In addition, a gas hydrateBSR in the overburden attenuates P-wave energy,obscuring the geology below.

A team of Eni and WesternGeco geophysicistsevaluated possible towed-streamer acquisitionconfigurations using a structural model of theTulip field based on existing information,including bathymetry, 2D seismic data and a 3Dvelocity-depth model. The team compared thesubsurface illumination, in terms of incidenceangles and azimuth, that would result from a CoilShooting geometry; conventional NAZ surveys,considering four different shooting directions;and multiazimuth (MAZ) acquisition, which isthe combination of several NAZ surveys shot indifferent directions (right). Multivessel WAZ andRAZ options were not considered because it wasimportant to record near offsets to image theundulating seabed.

13. Moore I and Dragoset B: “General Surface MultiplePrediction: A Flexible 3D SRME Algorithm,” First Break 26(September 2008): 89–100.

14. A bottom-simulating reflector (BSR) is a seismicreflection often seen in seismic sections from deepwaterareas. Studies indicate that it is primarily due to theacoustic impedance contrast in areas where free gas istrapped at the base of a gas hydrate stability zone.

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> Presurvey illumination tests for the Tulip project. NORSAR-3D software was used to predict theillumination of a subsurface target. The colors represent the number of traces mapping to each partof the target horizon, ranging from blue (low) to red (high). Areas of the target are poorly illuminatedwith conventional narrow-azimuth acquisition (left ). Multiazimuth acquisition in four directions(middle) provides much better illumination but requires four times the acquisition effort of theconven tional geometry. Coil Shooting acquisition (right ) illuminates the target effectively and is moreefficient to acquire.


The study concluded that a Coil Shootingsurvey would provide the best illumination of thetargets. As a result, Eni Indonesia, on behalf ofthe Bukat Joint Venture, awarded WesternGecothe world’s first commercial full-azimuth towed-streamer survey using the technique. The seismicvessel Geco Topaz acquired the 563-km2

[220-mi2] survey during August and September2008, equipped with eight streamers, each 6 kmlong, separated by 100 m (above).

Because of ocean currents and other factors,acquisition cannot exactly match planned sourceand receiver positions, so the actual subsurfacecoverage was monitored as the surveyprogressed. The presurvey evaluation used thecommercial NORSAR-3D modeling package toevaluate illumination of the subsurface targetfrom planned acquisition geometries.15 The samepackage was used onboard Geco Topaz duringacquisition to model the illumination based onactual source and receiver positions (aboveright). Comparison of the predicted illuminationfrom planned versus actual positions highlightedgaps in coverage requiring additional data,known as “infill lines,” to be acquired.

The field data exhibit low levels of noise,building confidence that acquiring data whiletowing streamers in a circular trajectory does notcompromise data quality (right). The Tulip fieldCoil Shooting survey was completed in 49 days.By comparison, a three-azimuth MAZ survey waspredicted to require 60 days, and a four-azimuthsurvey 75 days (next page, top).

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15. NORSAR-3D is a product of NORSAR.16. Houbiers M, Arntsen B, Thompson M, Hager E, Brown G

and Hill D: “Full Azimuth Seismic Modelling at Heidrun,”presented at the PETEX conference, London, November 25–27, 2008.

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> Onboard quality control of illumination. As data were acquired over the Tulip field, actual sourceand receiver positions were used to model illumination of the subsurface target horizon usingNORSAR-3D software. The left plot shows the number of traces mapping to the horizon at each partof the survey area, ranging from blue (low) to red (high). The plot on the right displays the ratio ofactual to planned coverage. A value of 1 (green) means that coverage matches the survey plan. Redindicates higher coverage than planned. Areas in dark blue signify lower coverage than planned.Based on this, some additional “infill” data were acquired over areas of low coverage within the mainsurvey area and away from the edge, where variable fold is to be expected.

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Norway Survey Design Study and TestStatoilHydro included the Coil Shooting option ina simulation study performed during 2008 thatinvestigated whether a full- or wide-azimuth

acquisition geometry could resolve seismicimaging challenges at its Heidrun field, locatedin 350-m [1,150-ft] water depth in the NorwegianSea, 100 km [62 mi] from the coast of Norway.16

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> Heidrun modeling results. The depth-velocity model (top) displays thefaulted reservoir, coal markers and a small salt body. In the lower panels,the synthetic seismogram (far left ) shows the 1D zero-offset reflectivityconvolved with the wavelet for the middle part of the model. It representsthe simplest seismic response. Note the pull-up of events below the saltbody, caused by the high P-wave velocity in the salt. This pull-up

disappears when the section is converted to depth. The red arrows markthe horizon used for the amplitude analysis shown in the figure on the nextpage. The simulated NAZ data (middle left ) exhibit distortion in reservoirreflections under the salt body. The WAZ (middle right) and Coil Shootingdata (right ) have better continuity and better imaging of steeply dippingevents. Sea-surface multiples are included in all three simulations.

Heidrun came on stream in 1995, and productionin 2006 was estimated at 3 million m3 [106 MMcf]of gas and 22,260 m3 [140,000 bbl] of oil per day.

The reservoir consists of sandstones of Early and Middle Jurassic age at about 2,300-m[7,500-ft] depth below the Base CretaceousUnconformity (BCU). The reservoir is heavilyfaulted, and parts of the field are not fullyunderstood because of imaging problems. Inparticular, a dome-shaped feature in one areacauses a highly disturbed image. One explana tionfor this dome is that it is formed by a salt diapirsourced by Triassic salt. Another imaging problemis that, in some areas of the field, faults and dipdirections below the BCU are unclear andconflicting. Despite several vintages of seismicdata, it has not been possible to obtain a clearseismic image of these complex areas. An ocean-bottom seismometer (OBS) survey pro videdbetter attenuation of multiples caused by strongimpedance variations around the dome than wasachieved by conventional towed-streamer surveys.The geometry of an OBS survey provides data froma full range of azimuths but at a significantlyhigher cost than a towed-streamer survey.

Geoscientists generated a 3D geologic model,covering a rectangular area of about 200 km2

[78 mi2] to a depth of 3,800 m [12,500 ft], torepresent the field (left and below). It includedan overburden with weak lateral velocityvariation, a faulted reservoir section and asection below the reservoir. The faults includedin the reservoir section represent the two mainfault systems in the field, crossing each other at

Coal markers

FaultsSalt body

Faults

Model

1,500 2,000 2,500 3,000 3,500 4,000

Velocity, m/s

Dep

th, m

0

1,000

Distance, m

0 2,000


an angle of about 45°. Apart from two faults withlower average dip, all faults had an average dipbetween 40° and 60°. Below the reservoir, twothin coal markers were included, one of which isthe base of the reservoir. A small salt body wasincluded at the location of the dome. Each layerand faulted subdivision of the structural modelwere allocated densities and P-wave velocitiesbased on a depth-migration model from 3Dseismic data and well data.

Three types of acquisition geometries weresimulated: conventional NAZ; a WAZ four-vesselconfiguration; and a Coil Shooting survey, usingabout 170 coils to provide a full 360° range ofazimuths over the modeled area. Modeling was

performed using a one-way wave-equationmigration approach that included simulation ofseabed multiples. Geoscientists evaluated simu -lated results for each of the acquisitiongeometries, comparing modeled vertical sectionsand also maps of peak amplitude extracted fromone of the horizons in the overburden (above).

Compared with the WAZ and Coil Shootingresults, the NAZ design exhibited more noise,especially around steep faults and in areas wherethe seabed has small bumps. The NAZ resultsalso have artifacts below the salt that were moreanomalous. The NAZ configuration showedconflicting dips resulting from contamination by

energy from multiples. The seabed multiple andmultiples of the coal markers were betterattenuated in the WAZ and Coil Shooting designsthan in the NAZ design. A steep flank of thestructure, visible in the WAZ and Coil Shootingdesigns, was invisible in the NAZ geometry. Thisflank was also invisible when modeling wasperformed without multiples. Artifacts related tothe acquisition footprint can be seen in theshallow part of the WAZ data, and to a lesserextent in the NAZ design. The Coil Shootingresults exhibit less acquisition footprint.

The Coil Shooting geometry showed moreconsistent amplitudes along the analyzed horizonthan the NAZ or WAZ designs, and these

30 Oilfield Review

NAZ Simulation

WAZ Simulation Coil Shooting Simulation

Synthetic Seismogram

> Heidrun modeled horizon amplitudes. Amplitudes were extracted by autotracking theamplitude peak on the horizon marked by the red arrows on the previous figure.Amplitudes in the simulated Coil Shooting data (bottom right ) match amplitudes of thesynthetic seismic section (top left ) better than do the NAZ (top right ) and WAZ (bottomleft ) geometries.


Autumn 2008 31

amplitudes were comparable to the expectedvalues of the reflection coefficient at that horizon.The study concluded that a survey design with anincreased range of azimuths and a higher fold ofcoverage would enable imaging of steeplydipping flanks that are invisible in a NAZ design.Such a survey would also deliver fewer artifacts,better noise suppression and better multipleattenuation. The study indicated that a CoilShooting design would also provide moreconsistent and accurate amplitudes.

To validate the conclusions of the modelingexercise, StatoilHydro acquired a Coil Shootingtest dataset over the field. The seismic vesselWestern Monarch acquired the data during afour-day period in September 2008. Survey designapproximated the dahlia pattern, with 18 coilsintersecting over the target area (right). Thecoils are slightly irregular in order to avoidsurface obstructions in the area, including atension leg platform and two loading buoys. Onestraight line was also acquired to provide someazimuths that were missing because of theobstructions. The test survey geometry wasdesigned to provide approximately 3 km x 3 km offull-azimuth, high-fold data, plus sufficientsurrounding aperture to provide 3D migratedimages that could be compared with previousseismic surveys and the modeling results. At thetime of writing, the data were being processed inpreparation for this analysis.

Worldwide PotentialWide- and rich-azimuth seismic techniques havebeen proven to deliver superior subsurfaceimages and better attenuation of coherent noiseand multiples relative to conventional narrow-azimuth acquisition. Experience gained sincetrials starting in 2006, including the firstcommercial deployment in 2008, indicates thatthe Coil Shooting technique is a highly efficientand effective method of acquiring data with a360° range of azimuths across the full offset-range over a survey area. A key benefit of thetechnique is that it requires only one vessel,negating the need for deployment of additionalsource and streamer vessels. This is particularlyattractive for acquiring small to medium-sized3D datasets, or for projects in remote areas,where it may not be practical to mobilize severalseismic vessels at the same time.

For very large surveys, deploying multiplevessels may be a more effective option, becauseevery shot is recorded by a large number ofstreamers (bottom right). WesternGeco multivesselsurveys in the Gulf of Mexico typically deploy a

total of 20 streamers, compared with 10streamers expected for typical Coil Shootingprojects. In practice, few surveys are likely to belarge enough to warrant deploying severalvessels, and these will normally be practical onlyin highly active areas such as the Gulf of Mexico.

Compared with a single-vessel three-azimuthMAZ survey, for the same sailing distance, CoilShooting technology delivers more shots, a largerimaged area and better sampling of offset andazimuth. The Coil Shooting technique provides acost-effective solution for better illumination andimproved seismic imaging in complex geologicalenvironments around the world. —JK

1,000

1

500 Fold

> Heidrun acquisition geometry. The test data were acquired as 18 intersectingcoils plus one straight line oriented at a heading of approximately 60°. Thenumber of traces (fold) mapping within 25- x 25-m bins is color-coded. Foldrises where circles intersect and is highest in the center of the survey.

Tim

e, d

ays

0

100

150

200

250

300

350

400

450

50

WAZ acquisition survey days

WAZ acquisition vessel days

MAZ acquisition survey days

Coil Shooting acquisition survey days

500-km2

development survey1,500-km2

appraisal survey5,000-km2

exploration survey10,000-km2

regional survey

> Estimate of acquisition duration for surveys of various sizes. This chartcompares the predicted time required to acquire different sizes of surveyusing three techniques: the Coil Shooting method, a three-azimuth single-vessel MAZ geometry and a multivessel parallel WAZ geometry. Estimates forthe WAZ geometry assume two recording vessels and two source vessels.The predicted time to complete the survey is shown for all three geometries.For the WAZ survey, the chart also shows “vessel days,” in which the time isincreased by a factor of three—a rough indicator of the increased costincurred though deploying multiple vessels.


32 Oilfield Review

Meeting the Subsalt Challenge

Marco Aburto PerezRobert ClydePiero D’AmbrosioRiaz IsraelTony LeavittLes NuttHouston, Texas, USA

Carl Johnson Aberdeen, Scotland

Don WilliamsonSugar Land, Texas

For help in preparation of this article, thanks to John Dribus,New Orleans; Jerry Kapoor, Houston; Lisa Stewart,Cambridge, Massachusetts, USA; Toby Pierce and AndrewWilde, M-I SWACO, Houston; and Mike Truitt, SterlingDrilling, Houston.Bit On Seismic, PowerDrive, PowerPulse, Q-Marine,seismicVISION and TerraTek are marks of Schlumberger.Fann is a mark of Fann Instrument Company.RHELIANT is a mark of M-I SWACO.

Drillers today are confident about their ability to reach reserves buried beneath

thousands of feet of salt and water. Now their attention has turned to doing so

economically, not through new technology, but by putting to best use what is

already at hand.

1. For more on the challenges of deepwater production:Amin A, Riding M, Shepler R, Smedstad E andRatulowski J: “Subsea Development from Pore toProcess,” Oilfield Review 17, no. 1 (Spring 2005): 4–17.


Autumn 2008 33

In the 1990s, the oil industry discovered thatimmense hydrocarbon reserves lay beyondcontin ental shelves beneath thousands of feet ofwater. In pursuit of that prize, drilling contractorsand engineers confronted techno logical hurdlesunlike any previously experienced, as they tookon an operating environment nearly as foreign tothem as deep space had been to aeronauticalengineers in the 1950s. In time, the effort becameeven more daunting with the discovery that thesepay zones were covered by vast, thick sheets ofsalt that would challenge commonly accepteddrilling and completion practices.

For example, in water depths beyond about7,500 ft [2,286 m], the replacement by water ofthousands of feet of overburden results invanishingly small margins between the fracture-and pore-pressure gradients that manifest earlyin the drilling process. Reaching target depthunder such conditions, with the technologyavailable in the early days of ultradeepwaterdrilling, required setting multiple, increasinglysmaller casing strings to control pore pressurewhile simultaneously keeping the hydrostaticpressure of the mud below that of the formationfracture gradient. The resulting well configura -tion often included a production string that wastoo narrow to accommodate desired production

volumes. In other words, the industry could drillinto these reserves but could not produce them atrates sufficient to justify the capital expended onthe effort.

Rigs capable of handling enough pipe, riser,drilling fluids and cement to drill and completewells in such water depths were rare. Oil industrychemistry was pushed to its limits by arequirement for drilling and completion fluidsthat could negotiate a thermal roller coaster asthey were pumped from surface temperatures tonear-freezing conditions at the seabed and thento reservoir temperatures at depth. Similarly,produced fluids had to flow from a subsurfacereservoir to a wellhead bathed in the frigidwaters of the seafloor and through miles ofocean-bottom flowline to production facilitiesthat were sometimes miles away, creatingunprecedented flow-assurance problems.1

Variable deck weight, supply chain logisticsand myriad other standard offshore operatingprocesses were all significantly altered bydistance from shore and extreme water depthonce operations moved beyond the world’scontinental shelves. In time, most of these issueswere addressed through such innovations as solidexpandable casing, heated flowlines, advancedchemistry and the construction of super sizeddrilling vessels. But for drilling engineers, one of

the most daunting new facts of deepwater life wasthe realization that much of the prize lay beneathmassive salt canopies (above).

Before the intensified interest in subsaltdrilling, accepted wisdom among drillingengineers held that the best way to deal with saltintervals was to avoid them. Drilling in theseformations was considered to be so fraught withrisk that standard turnkey contracts—those bywhich contractors are paid a lump sum for drillingto an agreed depth—routinely contained a clausethat converted such agreements to a standard day-rate contract if salt was encountered. Under mostagreements, time calculations—used for penaltyor bonus payments—were also suspended fromthe moment of entry into the salt until the bitexited its base and casing had been set across the formation.

The difficulties encountered while drillingthese sections are a function of salt’s uniquecharacteristics. Salt sheets retain a relatively lowdensity even after burial. Since other formationsat the same depth and deeper increase in densityover time as overburden is added, salt sheetstend to be less dense than the formations nearand beneath them. If the overlying sedimentsoffer little resistance to salt migration, as is oftenthe case in the Gulf of Mexico, the salt rises. Thismovement generates a difficult-to-model rubble

> Salt formations in deep water. This map shows areas with known potential subsalt exploration targets (white). The initial growth of activity in deep waterhas been in the so-called golden triangle of the Gulf of Mexico, Brazil and, more recently, West Africa. These established areas will continue to see themajority of deepwater capital investment, some 85% of activity over the next 5 to 10 years. However, frontier and emerging areas—most of which are atleast partially subsalt—have made deepwater exploration a global phenomenon.


zone at the salt’s base and sides (above).Because pore pressures, fracture gradients andthe existence and extent of natural fractures aredifficult to predict, well control is highlyproblematic when exiting the base of the salt(see “The Prize Beneath the Salt,” page 4).

Penetrating salt with a wellbore also presentsa unique challenge. Under sustained constantstress, salt deforms significantly as a function oftime, loading conditions and its physicalproperties.2 This phenomenon, known as creep,allows the salt to flow into the wellbore to replacethe volume removed by the drill bit. Especially atelevated temperatures, this invasion may occurquickly enough to cause the drillpipe to stick andmay eventually force the operator to abandon thewell or sidetrack around it.

Another consideration for engineers is thatshock and vibration levels inherent in thedownhole drilling environment can becomeacute when drilling through salt sections. Thismay be attributable to poor tool selection andBHA design, inappropriate drilling-fluid design,ratty or laminated salt intervals, creeping salts,and less-than-optimal input drilling parameterssuch as weight on bit (WOB) or rotary speed.3

On the other hand, though salt is harder thanmost formations and therefore more difficult todrill, its unique rock characteristics also offerdrillers certain advantages. For example, saltscommonly have a high fracture gradient thatallows longer borehole sections to be drilledbetween casing points. Its low permeability, inaddition to providing a reliable hydrocarbon-trapping mechanism, virtually eliminates theusual well-control problems encountered whendrilling more-permeable formations.4

To make the most of these advantages whileminimizing salt’s inherent drawbacks, drillingengineers have turned to a combination ofexisting tools. Polycrystalline diamond compact(PDC) bits, concentric under-reamers and rotarysteerable systems (RSSs), originally broughttogether for use in extended-reach wells, havebeen adapted to meet the specific needs of drillingand steering through massive salt structures.

In this article, we discuss how engineers haveleveraged these and other tools, seismic proces s -ing and drilling-fluid management to turnmassive salt sections in deepwater plays fromtraditional foe to friend. We also look at how thiswas done while simultaneously meeting the

special economic and technical demands ofdeep water development. Though deepwatersubsalt formations are being explored off thecoasts of eastern Canada, Brazil, West Africa andelsewhere, this article primarily focuses on theGulf of Mexico where the effort is most matureand the subsalt play has gone beyond explorationto production.

A Better Look Among the most critical concerns when drillinginto reservoirs that lie beneath salt are thelocation and angle of the wellbore exit. In the Gulfof Mexico, drilling engineers prefer to exit saltwhere the contact between the base of salt andunderlying sediments has a low dip angle becausethe rubble zone tends to be more stable therethan at steeply dipping flanks. When that is notpossible, they strive to keep the wellbore within30° of perpendicular to the base of salt.

Attaining these drilling targets, however, isoften problematic because the base of salt can bedifficult to model. Since salt may be structurallycomplex and seismic waves travel through it athigher velocities than in surrounding layers,surface seismic surveys have historically providedonly poor images below or near it. This leavesconsiderable margin for error in estimating porepressure and other properties of the subsaltformation, with potentially catastrophic results,including loss of the wellbore.

In the 1990s, 3D seismic acquisition andprocessing greatly improved the success rate forexploratory wells on land and in shallow watersoffshore but, because of complex geology, hadlittle impact on discovery rates in deeper water.Deepwater subsalt prospects proved particularlydifficult to image using data from early 3Dsurveys. Furthermore, even when seismic dataprocessing provided sufficient data for successfulexploratory drilling through these formations, itoften could not provide data of sufficient qualityfor efficient development.

In response to these and other limitations of traditional seismic survey methods,Schlumberger introduced the Q-Marine single-sensor acquisition system, which increasesseismic image resolution by providing 40% greaterbandwidth. Other changes to seismic surveymethods aimed at increasing azimuthal coveragehave also added to the industry’s ability to

34 Oilfield Review

2. Poiate E, Costa AM and Falcao JL: “Well Design forDrilling Through Thick Evaporite Layers in Santos Basin—Brazil,” paper IADC/SPE 99161, presented at theIADC/SPE Drilling Conference, Miami, Florida, USA,February 21–23, 2006.

3. Israel RR, D’Ambrosio P, Leavitt AD, Shaughnessey JMand Sanclemente J: “Challenges of Directional DrillingThrough Salt in Deepwater Gulf of Mexico,” paperIADC/SPE 112669, presented at the IADC/SPE Drilling

Conference and Exhibition, Orlando, Florida, March 4–6, 2008.

4. Leavitt T: “BHA Design for Drilling Directional Holes inSalt in Deepwater Gulf of Mexico,” presented at the 19thDeep Offshore Technology International Conference andExhibition, Stavanger, October 10–12, 2007.

5. For more on Q-Marine, wide-azimuth and rich-azimuthsurveys: Camara Alfaro J, Corcoran C, Davies K,Gonzalez Pineda F, Hampson G, Hill D, Howard M,

Kapoor J, Moldoveanu N and Kragh E: “ReducingExploration Risk,” Oilfield Review 19, no. 1 (Spring 2007): 26–43.

6. For more on borehole seismic surveys: Blackburn J,Daniels J, Dingwall S, Hampden-Smith G, Leaney S, Le Calvez J, Nutt L, Menkiti H, Sanchez A and Schinelli M:“Borehole Seismic Surveys: Beyond the Vertical Profile,”Oilfield Review 19, no. 3 (Autumn 2007): 20–35.

> Potential drilling hazards in and around salt. The opportunities for problems drilling to, through andout of salt canopies are many and derive essentially from salt’s tendency to move. The industry’slimited ability to image salt may lead to mistaken base-of-salt depth calculations and unexpectedencounters with elevated or reduced pressure zones in and beneath the salt.

Salt gouge zone ateffective stress

High pressureassociatedwith seamsand inclusions

Base-salt deptherror (velocityuncertainty)

Recumbent oroverturned beds Major subsalt

pressure regression

Possible casingloading due to high-temperature salt

Dirty salt: potentialtight-hole conditionsdue to sylvite, polyhaliteor carnalite bands

Tar bands

Mud loss inhighly fracturedcarapace facies

Overpressured sediment incarapace and rafted facies

Trapped sedimenton salt seams

Area of tectonicinstability

Rubble zone fromrestricted dewateringpathway or tectonicstresses

Invisible salt wingwith trapped pressure


Autumn 2008 35

visualize subsalt formations (above).5 In addition,a new seismic acquisition method, shooting incircles, has been effective at imaging below saltand other reflective layers and requires fewervessels than wide-azimuth or rich-azimuthtechniques (see “Shooting Seismic Surveys inCircles,” page 18).

Drillers are also able to more confidently exitthe salt by looking ahead of the bit. To do this theyuse borehole seismic procedures called walk awayvertical seismic profiles (VSPs) and seismic-while-drilling (SWD) techniques. Walkaway VSPsare conducted by moving the seismic sourceprogressively farther from the wellhead at thesurface. Receivers are clamped inside thewellbore just above the zone to be imaged—inthis case near the base of salt—to provide SWDdata that are used to look ahead of the bit and sobetter image the base of salt and its underlyingformation. Amplitude variation with angle (AVA)inversion of the walkaway VSP is used to predictcompressional (P-) and shear (S-) wave velocityratios (vp /vs) just below the salt/formationinterface. These velocities are used to predictpore pressure ahead of the bit.6

The walkaway VSP is then rapidly processedto provide a high-resolution image of the base ofsalt; it can also give details on possible sutures orinclusions in the salt. Finally, the VSP is pro -cessed to present a high-resolution image of thesubsalt sediments. When the VSP is combined

with surface seismic data, it is possible to attainmore-comprehensive imaging of the structuraland stratigraphic details in key development areasthat can then be used to design well trajectories.

Familiar wireline logging technology hasbeen adapted to LWD tools to deliver real-timetime-depth and velocity information during thedrilling process (below). This SWD system

> Enhanced views beneath the salt. The narrow-azimuth image (left ) shows some indications of dipping layers beneath the salt, but the rich-azimuthimage (right) illuminates subsalt layers clearly. The survey configurations for each survey are adjacent to the seismic images.

Narrow-Azimuth Image, Full Processing Rich-Azimuth Image, Basic Processing

Bottom of salt Bottom of salt

> Looking ahead of the bit. The seismicVISION sensor located in the LWD tool of the BHA (right ) hasbeen adapted from the wireline tool (left ). The sensor contains a processor and memory and receivesseismic energy from a conventional airgun array located either on the rig or on a source vessel. Afteracquisition, the seismic signals are stored and processed, and checkshot data and quality indicatorsare transmitted uphole in real time through a connection with a PowerPulse MWD telemetry system.

seismicVISION Survey

Source

Seafloor

Seismic reflector

seismicVISIONtool

MW

D t

elem

etry

Wireline Borehole Seismic Survey

Source

Seafloor

Wireline tool

Seismic reflector

Salt Salt


comprises an LWD tool with seismic sensorspositioned near the drill bit, a seismic source atthe surface and an MWD system for real-timetelemetry.7 The time-depth data are used toposition the well on the seismic map, which can be viewed at the wellsite or remotely. Real-time waveforms allow immedi ate processing ofthe VSP, enabling a true look-ahead-while-drilling capability.

Full waveforms are recorded in the toolmemory for VSP processing after a bit trip.Source activation and data acquisition areconducted during drilling pauses when thedownhole environment is quiet. Suitable times toacquire data are during pipe connections whiledrilling and tripping.

Real-time checkshot (time-depth) data areused to place the bit on the surface seismic data using a software-generated map to aidnaviga tion, select casing points and prepare forfaults, pore-pressure changes or formationvariations (left).8

Just-in-Time Data Despite these refinements to subsalt imaging,the science is still imperfect, and a level of risk continues to exist while drilling through and exiting the salt. As a hedge against drilling surprises or making poorly informeddecisions, operators rely on data delivered in realtime from the BHA to help them monitor criticaldrilling parameters.

MWD sensors are used to continuously updatevibration, stick/slip and WOB measure ments.Equivalent circulating density (ECD) measure -ments—critical to keeping the dynamichydrostatic pressure of the drilling fluid fromexceeding the well fracture gradient—arerecorded using an annular pressure while-drilling instrument.

Although few petrophysical measurementsare required while drilling salt sections, LWDdata can be used to maximize drilling perfor -mance. For example, gamma ray measurementsnear the bit can be used to correlate changes indrilling parameters to changes in lithologyassociated with entering or exiting the salt ordrilling through an inclusion.

Sonic compressional data can be used toimprove the model by adding pore pressuremeasured while drilling through inclusions andin the interval below the salt, where resistivitymeasurements are still influenced by the salt andso may be inaccurate. Sonic shear-wave data arealso important for geomechanical modeling ofthe salt. These models can determine the stressregimes in the salt and predict whether they varywith depth. This information is then fed backinto the well-construction process for use on thenext well.9

The most potent resource for dealing withdrilling problems in salt continues to be exper -tise supported by quick decision making basedon reliable, timely information. To that end,operators are relying on real-time drillingmonitoring and on drilling support centers thatuse high-speed connectivity to bring togetherdata and experts for rapid resolution of possibledrilling hazards. This is partly a response to theshortage of expert personnel and the costs of thesoftware and other tools necessary to compe -tently drill in complex, often remote deepwaterand subsalt environments.

36 Oilfield Review

> Refined depth prediction. Bit On Seismic software enhances visualization, communication andcooperation, updating the seismic map in real time. The map allows complex information to bepresented as a wellbore placement path. Real-time seismic velocities are used to update pore-pressure predictions and predict drilling hazards. Uncertainty as to the BHA location in reference toseismic markers, represented here in blue, decreases as the well progresses toward the target.


Autumn 2008 37

The Toolbox While collaboration among experts using real-time data is a powerful tool, the real measure ofa project’s success is in the level of its return oninvestment. And because the biggest subsaltprize is in ultradeep water, holding down the costof development—often a matter of time savings—is as essential to reaching that economic goal asis use of the right technology to reaching atechnical one.

A key strategy for minimizing overall fielddevelopment costs is to save drilling days andcapital by limiting, to the extent possible, thenumber of drill centers per field. To do so, it maybe necessary to drill extended-reach develop mentwells. To avoid high angles and doglegs that cancause significant problems and delays duringcasing and completion operations, a shallowkickoff point—that point at which the well beginsto deviate from the vertical—is often necessary.

Shallow kickoffs, however, require directionaldrilling in the relatively large-diameter uppersections of the wellbore. This has typically beendone using mud motors. But in these uppersections, mud motors tend to deliver poor rates ofpenetration (ROP) and highly tortuous well bores.In response to the dilemma, drilling engineershave used a shallow kickoff with a 26-in. RSS andfound that the system reduced drilling time by63% compared with mud motors used in the samesections of nearby wells.

This success came on the heels of numerousrefinements in RSS tools that are at the heart ofthe industry’s increased success in drilling saltsections. That is because when drilling throughsalt, changes in well-path direction may beneeded to avoid hazards indicated by real-timedata. The accuracy and real-time steeringcapabilities of RSS tools permit drillers to steeraround problems such as inclusions or tardeposits without sacrificing borehole quality.

RSS tools also are preferred to steerablemotors while drilling through salt because theyrotate 100% of the time while steering, whichtranslates into improved ROP.10 The most recentversions of RSS tools have been shown to delivera wellbore that is rounder, more stable and lesssubject to creep than is possible using a drillingmotor (above right).

There are two types of RSS tools: push-the-bit and point-the-bit. The former pushes mud-actuated pads against the borehole wall. Thisforces the BHA and the well trajectory to move inthe opposite direction. A point-the-bit systemchanges bit toolface angle and thus welldirection by bending a flexible shaft attached tothe bit.

RSS tools change direction while drilling inan almost instantaneous response to commandsfrom the surface. Drillers also use this controlcapability to combat a natural build-walktendency—a phenomenon in which the wellboreinclination increases (builds) or changes direc -tion (walks) as the bit responds to forcesimposed on it by the formation being drilled. Insalt sections, build and walk directions havebeen known to change even within the sameformation. For this reason, RSS tools are alsooften called upon to counter build-walk tenden -cies while drilling vertical sections. And, becauseRSS tools are always rotating, they are able todeliver better overall penetration rates than mudmotors, which must change to the less efficientnonrotating sliding mode to counter salt’s build-walk tendency.11

In some instances, high-torque, low-speedmotors are recommended for use in conjunctionwith RSS tools. The addition of a motor createswhat is referred to as a powered RSS. This systemis capable of delivering increases in drillingefficiency because it allows the driller to reducedrillstring rotational speed while the motordelivers torque directly at the bit.

One recent operation in the deepwaterWalker Ridge block of the Gulf of Mexico affordedSchlumberger drilling engineers an opportunityto compare the performances of two BHAs used

to drill sidetrack wells below the salt formation:The No. 2 sidetrack was equipped with a push-the-bit RSS assembly and the No. 3 side trackwith a mud motor and bicenter bit.

7. Underhill W, Esmersoy C, Hawthorn A, Hashem M,Hendrickson J and Scheibel J: “Demonstrations of Real-Time Borehole Seismic from an LWD Tool,” paper SPE71365, presented at the SPE Annual TechnicalConference and Exhibition, New Orleans, September30–October 3, 2001.

8. A checkshot measures the seismic traveltime from thesurface to a known depth in the wellbore. P-wavevelocity can be measured directly by lowering ageophone to each formation of interest, sending out asource of energy from the surface and recording theresultant signal. The data can then be correlated tosurface seismic data by correcting the sonic log andgenerating a synthetic seismogram to confirm or modifyseismic interpretations. A checkshot differs from a VSPin the number and density of receiver depths recorded;geophone positions may be widely and irregularlylocated in the wellbore. By contrast, a VSP usually hasnumerous geophones positioned at closely and regularlyspaced intervals.For more on Bit On Seismic software: Breton P, Crepin S,Perrin J-C, Esmersoy C, Hawthorn A, Meehan R,Underhill W, Frignet B, Haldorsen J, Harrold T andRaikes S: “Well-Positioned Seismic Measurements,”Oilfield Review 14, no. 1 (Spring 2002): 32–45.

9. Israel et al, reference 3.10. By rotating 100% of the time, RSS tools better deliver

WOB, which more efficiently transfers the weight of thedrillstring and BHA to the bit. Other systems, such asmud motors, put much of the drillstring in tension, thusreducing downward force available.

11. For more on RSS: Copercini P, Soliman F, El Gamal M,Longstreet W, Rodd J, Sarssam M, McCourt I, Persad Band Williams M: “Powering Up to Drill Down,” OilfieldReview 16, no. 4 (Winter 2004/2005): 4–9.

> RSS advantages. The engineering advantages of RSS tools quickly lead to economic ones. Thesebenefits are magnified when applied to high-cost, high-risk deep- and ultradeepwater environments.

Powered Rotary Steerable System

Improved directional control

Improved steering to reducewellbore tortuosity

Less drag to improve controlof weight on bit

Longer extended reach withoutexcessive drag

Continuous pipe rotationfor cleaner hole

Less risk of stuck pipe

Time saved by drilling fasterwhile steering and by

fewer wiper trips

Lower cost per foot

Lower cost per barrel

Longerhorizontalrange with

good steering

Reducedcompletion

costs and easierworkovers

Fewer wells and platforms needed to develop a field


The mud motor and bicenter bit option waschosen because an RSS-reamer combinationcould not be rotated across the existingwhipstock face. This choice eliminated a separatetrip to pick up another BHA once the driller hadexited the whipstock but still allowed anextension of the wellbore and drilling of thesection in a single run.

While it took just 74 hours to drill 4,687 ft[1,429 m] of the No. 2 sidetrack, it took 77 hoursto drill 1,590 ft [485 m] of the No. 3 sidetrack,translating to ROPs of 63 and 20 ft/h [19 and6 m/h], respectively. The standard RSS was alsoable to achieve higher doglegs and so take the side -track away from the main wellbore faster (above).

At the Cutting EdgePDC bits are more suitable for drilling in the saltthan milled-tooth bits. The shearing action ofPDC bits makes them more efficient in cuttingthrough salt, and they require less WOB. They arehighly durable—a quality that takes advantageof the homogeneous nature of the salt so thatlong salt sections can be drilled in a single runbefore setting casing. Also, PDC bits can bedesigned with different degrees of aggressive -ness (below left).

Proper PDC bit selection is critical. Bit typeand corresponding drilling parameters are oftenprimary sources of downhole shock, vibrationand stick/slip and strongly influence a BHA’sdirectional tendency while maximizing ROP.12 Abit that is poorly suited to the job is likely to wearprematurely, produce poor-quality boreholes,cause tool failures and reduce ROP.

Despite extensive documentation of world -wide bit records and the proliferation of softwareprograms and improved PDC inserts and bitdesigns, bit selection is usually based on localfield knowledge. To address this potential short -coming, Schlumberger and Chevron engineersassembled a bit-tracking system for the US GulfCoast region by compiling information fromdrilling runs that used push-the-bit RSS tools. Bitperformance metrics were based on generalstability—recorded downhole shock, vibrationand stick/slip—directional steering ability andthe expected overall penetration rate.

Each entry was characterized by the numberof blades, bit size, cutter size, specialized bitfeatures, well profile and reamer being used.Other data included WOB and rotation rateapplied to the BHA, measured depth (MD) of thebit run, formation drilled, wellbore trajectoryand ROP as related to depositional environment.Each of these parameters was analyzed forsignifi cant effects on performance with regard todownhole shock and vibration and to directionalsteer ability, which is defined as either aninability to steer the well in the desired directionor ROP problems.13

Among the key findings of the study were the following:• Salt and sandstone formations had the most inci-

dences of shock and vibration, and sandstonelithologies yielded the most steering problems.

• Vertical wells had the highest incidence of shockand vibration events.

• Significant steering problems seemed unrelatedto the type of lithology drilled.

• The highest ROPs in competent formations werein wells that did not have shock and vibra tionand steerability problems.

38 Oilfield Review

> Performance comparison. The differences in ROP and average doglegseverity (DLS) highlight the RSS advantages over a mud motor using abicenter bit. Part of the improved time performance is a consequence ofthe fact that, unlike mud motors that use bent housings to build angle, it isunnecessary to pick RSS tools off bottom to directionally orient them. Also,RSS-equipped BHAs do not require bicenter bits to ensure that theborehole has sufficient casing-running clearance, which means lessenergy is required to drill the same section.

Run Statistics PowerDrive Run Bicenter Run

Well

Rig

Hole size

Bit

Date in

Date out

Total time BRT

Depth in

Depth out

Footage

Drill hours

ROP

Inclination in

Inclination out

Average DLS

Maximum DLS

Big Foot No. 2 ST01BP00

Cajun Express

121/4 in.

RSX 130 (RHC)

January 4, 2006

January 12, 2006

8 days

17,510 ft

22,197 ft

4,687 ft

74

63 ft/h

0.1°

31°

2°/100 ft

3.9°/100 ft

Big Foot No. 3 ST01BP00

ENSCO 7500

121/4 in. x 131/2 in.

QDS 42 (Smith)October 24, 2007

November 2, 2007 9 days

19,125 ft

20,715 ft

1,590 ft

77

20 ft/h

1.65°

6.3°

0.29°/100 ft

0.57°/100 ft

± ±

> Cutting action. PDC bits drill hard, essentially homogeneous salt sections efficiently using ashearing, lathe-like cutting action (left ). The back-rake angle and cutter exposure (top right) and side-rake angle (bottom right ) define how aggressively PDC bits contact the formation.

Side-rakeangle

Back-rakeangle

PDC bit—shearing

Exposure


Autumn 2008 39

• Rotary steerable systems helped reduce mostproblems associated with directional control.

• The appropriate choice of PDC bit characteris-tics and features, along with correct applica tionof operating parameters, reduced the problemsassociated with shock and vibration and, inturn, delivered a higher ROP regardless of geo-graphical area, depth and trajectory.

• The operator had to experiment to find thebest combination of bit design and BHA com-ponents to reduce shock and vibration and toenable the BHA to steer the well in thedesired direction.

Bigger and Better HolesThe ultimate goals of every drilling program are ahigh-quality gauge borehole, accurate formationevaluation and rapid, uncomplicated drilling. Insalt formations, added to other characteristicsthat define quality boreholes is a reduction inload points on the completion that wouldotherwise result from the salt’s nonuniformtransverse-loading characteristics. To achievethis in a cost-effective manner, operators useconcurrent drilling and reaming techniques toenlarge the borehole as it is drilled, rather thanmaking a separate trip for each. The mostcommon tools for this technique—known asenlarging while drilling (EWD)—are concentricreamers, bicentered bits and eccentric reamers.

Increasing borehole size beyond the diameterof the bit delivers many advantages, includingthe ability to use a casing string with an outsidediameter close to that of the previous string’sinside diameter. While this scenario naturallycreates a tight tolerance between the two casingstrings, enlarging while drilling leaves a largerannulus between the casing and borehole wall.The extra space reduces surge and swab effectsand cementing problems that may occur whenthere is too little open area between the casingbeing set and the wall of the openhole section.

One operator in the deepwater Gulf of Mexicoplanned to use the EWD technique to drill out ofa 16-in. casing shoe and continue drilling verti -cally to the kickoff point where the well wouldbuild inclination at a rate of 1.5°/100 ft [1.5°/30 m]until the well angle reached 30°. The plan was tocontinue the section through the salt base to the135⁄8-in. casing point at 21,911 ft [6,678 m] MD.

Despite encountering severe shocks andvibrations while drilling the same salt section inoffset wells with a powered RSS, engineers hopedto drill the section in one run. Again they used aPowerDrive RSS and a 16-in. under-reamer located90 ft [27 m] behind a nine-bladed 143⁄4-in. PDC bit.As a consequence, engineers were able to finish

the section in a single run and to drill it morequickly and with lower levels of shock andvibration than were experienced in the offsetwells (above).

At the start of the run, the RSS was program -med to drill vertically and, in fact, held maximumangle to just 0.10° until the kickoff point wasreached. Angle was then built to 30° using

downlinked commands to steer the RSS tool, andthat inclination was held until the wellboreexited the base of the salt. A flow check was then

12. Moore E, Guerrero C and Akinniranye G: “Analysis ofPDC Bit Selection with Rotary Steerable Assemblies inthe Gulf of Mexico,” paper AADE-07-NTCE-08, presentedat the 2007 AADE National Technical Conference andExhibition, Houston, April 10–12, 2007.

13. Moore et al, reference 12.

> Purpose-built BHA. The PowerDrive RSS drilled the 143⁄4-in. by 16-in. salt interval (blue line) asplanned in a single run (red line right). The BHA for this interval (left ) was designed to avoid thesevere shocks encountered in offset wells.

65⁄8-in. drillpipe to surface

65⁄8-in. heavyweightdrillpipe (11 joints)

Jar

65⁄8-in. heavyweightdrillpipe (8 joints)

Crossover

8-in. drill collars (4)

Crossover

91⁄2-in. drill collars (2)

145⁄8-in. bicenter stabilizer

91⁄2-in. nonmagnetic drill collar

145⁄8-in. stabilizer

91⁄2-in. nonmagnetic drill collar

143⁄4-in. by 16-in. under-reamer


Downhole filter

MWD tool


LWD tool

Downhole filter


PowerDrive RSS

143⁄4-in. PDC bit

16-in. casing point

Kickoff point, 0° inclination

15,521 MD, 15,520 ft TVD

Base of salt

4,000

20,000

18,000

16,000

14,000

12,000

2,000

Vertical section, ft

TVD

, ft

0

135⁄8-in. casing point, 30.43° inclination

21,911 MD, 21,215 ft TVD


performed, and drilling proceeded until the baseof salt was confirmed on the log at 21,119 ft[6,437 m]. The well was circulated bottoms up

and successfully drilled through the rubble zone.The section was then drilled to total depth (TD)follow ing the planned trajectory.

Engineers drilling deepwater wells in the BC-400 field offshore Brazil recently quantifiedthe impact of BHA and geosteering systemchoices on enlarging-while-drilling methods. TheBHAs included LWD tools and wireline calipersto measure results and to provide a directcomparison of borehole quality attained witheach system. Salt formations were drilled toensure that each system was compared within acommon drilling environment without variationsattributable to formation types.14

The test well, in 1,745 m [5,725 ft] of water,used intermediate casing strings to isolate saltformations. After the intermediate string was setat 3,793 m [12,444 ft], three EWD combinationswere used to open the 121⁄4-in. hole section to143⁄4 in. Then, a 103⁄4-in. secondary intermediatecasing string was set across the salt. The testcomprised five drilling runs—including two with no enlarging-while-drilling assembly—thatcompared the following equipment types:• conventional mud motor with a 1.15° bent

housing and a PDC bit and no enlargement• conventional BHA with a fixed-blade reamer• conventional BHA with bicenter bit• mud motor with 121⁄4-in. tricone bit, a 1° bent

housing and no enlargement• 121⁄4-in. x 143⁄4-in. concentric reamer and RSS.15

MWD tools recorded downhole vibrationscaused by lateral shocks and stick/slip. The RSSpro duced a hole that was virtually free of rugosityand wellbore threading—grooves on the well -bore wall similar to those that would be left by

screw threads. This BHA configuration alsoproduced the longest run for the section with arun length of 254 m [833 ft] with an average ROPof 10 m/h [33 ft/h]. Measurements indicated low levels of stick/slip, vibrations and shocks.Additionally, hole inclination was reduced from 2 to 0.4° for the entire run.16

The Fluids Just as drilling in salt requires specific BHAs,entering, drilling through and exiting the saltalso place special demands on fluids selection.Because of salt washout or leaching, creep,sutures and other inclusions within the salt, andthe unknowns associated with the rubble zone,drilling fluids must be designed to balance thesometimes competing interests of ROP, holequality, wellbore stability and affordability (left).

For instance, ROP increases significantlywhen salt formations are drilled using under -saturated brines or seawater. But their use canalso lead to significant hole enlargement throughsalt leaching. On the other hand, using seawateroffers significant cost savings while also elimi -nating the need for precious rig space to storeweighted brines when drilling riserless into thetop of the salt.

Scientists at the Schlumberger TerraTekGeomechanics Laboratory Center of Excellencein Salt Lake City, Utah, USA, investigated thepotential advantages and feasibility of usingseawater to enter the top of salt. To do so, theyused physical laboratory modeling of saltleaching under conditions of forced convection.17

The laboratory test used a Reynolds numbercalculation to determine the dissolution charac -teristics of salt while flowing seawater andheavier brines at simulated field conditions.18

Flow rates were scaled to match the Reynoldsnumbers associated with field flow conditions fora 24-in. borehole with a 51⁄2-in. drillpipe, and1,000- and 750-galUS/min [227- and 170-m3/h]flow rates.

The analytical model was based on diffusionprinciples and fluid mechanics. Model inputsincluded initial hole diameter, drillstringdiameter, BHA diameter and length, along withdrilling ROP, flow rate and salt thickness. Otherinputs were the temperature and initial salinityof drilling fluid, and diffusivity and salt density.With a few exceptions for specific conditions,modeled results typically matched laboratoryresults, usually within 10% of average diameter.

The model was applied to a well in the Gulf ofMexico where current practice is to drill a 24-in.hole riserless into the first 500 ft [152 m] of saltusing seawater and gel sweeps. The final 200 ft

40 Oilfield Review

> Washouts. Problems associated with poordrilling-fluid selection include sections ofborehole enlargement and weakened boreholewalls as a result of leaching. Low mud weightmay allow creep to impinge on the drillstring,while drilling fluid with unfavorable rheologicalproperties may be unable to carry cuttings to thesurface, causing the drillstring to becomepacked off above the bit.

Potential Problems

Salt

Radial-stress relaxation

Salt-creep ledgesimpinge on drillstring.

Borehole wall is weakenedby leaching water, gasand other mineralsout of salt.

Wellbore enlargementresults from saltdissolution.

Accumulated cuttingsjam drillstring.

> Flat rheology. Flat-rheology SOBMs, like the MI-SWACO RHELIANT system (right ), can maintainconstant gel and shear strength through a range of temperatures and pressures. This indicates thatthe fluid is retaining favorable drilling characteristics—including high ROP and low ECD—associatedwith synthetic oil-base fluids (left ) without sacrificing the viscosity necessary for efficient boreholecleaning. Typical reported fluid properties of yield point and 10-min gel are measured in lbm/100 ft2,and 6 rpm and 3 rpm are true centipoise viscosity (s–1) as seen on a Fann viscometer dial.

Gel

str

engt

h *

100,

lbm

/ft2

80

70

60

50

40

30

20

10

0

80

70

60

50

40

30

20

10

040 100 15040 100 150

Temperature, °F Temperature, °F

Yield point 6 rpm 10-min gel3 rpm

Conventional SOBM RHELIANT System

Vis

cosi

ty, s-1

Gel

str

engt

h *

100,

lbm

/ft2

Vis

cosi

ty, s-1


Power section

Multiplestabilization pointsto customizeBHA response

Control unit

Steering section

Bearings andtransmission

Integratedfilter assembly

Power section

Housing

Rotor

Stator

Autumn 2008 41

[61 m] is typically drilled with a salt-saturatedmud to ensure a good cement job.

However, modeling suggested there are bene -fits to drilling the last 200 ft using seawater.Proposed advantages include improved ROP of50 to 120 ft/h [15 to 37 m/h] compared to a salt-saturated mud and lower drilling-fluid costs.Predicted leaching resulted in a need to use 8%by volume more cement—the amount normallypumped to ensure cement returns to the seabed.The modelers, using 2004 rig rates, assumedsavings from improved ROP and reduced fluidcosts at about US $250,000 per well.19

Once past initial entry and during progres -sion through the salt itself, drilling hazards mayinclude sutures and inclusions of higher or lowerpore pressure than the surrounding salt, makingthose sections more prone to kicks or lostcirculation. Additionally, salt will creep into thewellbore if the mud’s hydrostatic pressure is lessthan the stress developed in the salt. Earlyoperator experiences in drilling these formationsusing conventional salt-saturated muds includedslow penetration rates, poor hole integrity, lostreturns, bit balling and packoff problems.

For relief from these difficulties, drillersturned to synthetic oil-base muds (SOBMs).Because they are more expensive than water-base fluids, operators have traditionally avoidedSOBMs for drilling in areas with lost circulationpotential. Additionally, although they have beenshown to deliver high drilling rates and goodwellbore stability, SOBMs exhibit elevatedviscosity as a function of increased temperatureand pressure. This may lead to higher equivalentcirculating densities that can result in lostcirculation. This is of particular concern in deepwater where pore-pressure/fracture-gradientmargins may be exceedingly narrow.

Still, the attraction of days saved in theultradeepwater arena—both as a function ofimproved ROP and as a consequence of holestability that can significantly reduce casing andcementing operations—has made SOBM thedrilling fluid of choice for many operators drillingin and below the salt. For example, in 2000, afterhaving drilled an 8,000-ft [2,438-m] salt sectionin its first well with a salt-saturated mud, oneGulf of Mexico operator switched to an SOBMsystem for the next well. The second well, which

penetrated the same zones, required 78 fewerdrilling days than the first well for a cost savingsof about US $12 million.20

SOBMs are gaining increased acceptancenow that manufacturers have developed flat-rheology SOBMs to overcome these fluids’tendency toward elevated viscosity at hightemperatures and pressures. The new systemsare designed to maintain constant rheologicalparameters as temperature and pressures vary(previous page, bottom). The flat rheology allowsfor a higher viscosity without raising ECD andmaintains cuttings-carrying capacity and barite-suspension properties.21

Salt-Entry TechnologiesThe ability of powered RSS tools to deliver torqueto the bit reduces the stick/slip potentialtraditionally associated with large PDC bits. Thisfeature makes the RSS option particularly well-

suited for operations in the riserless section ofthe hole in which operators jet-in the conductorpipe. Once the borehole reaches the conductorsetting point, the driller can unlatch the RSSfrom the casing and drill ahead while takingreturns to the seafloor.

The efficiency of this practice was recentlydemonstrated in one deepwater Gulf of Mexicowell after earlier attempts to drill the 26-in. saltsection had met with mixed results, and thecompany was anxious to improve ROP using apowered RSS with a PDC bit (above). Previous

14. Lenamond C and da Silva CA: “Fully-Rotating RotarySteerable and Concentric Reamers TechnologyCombination Eliminate Wellbore Threading in Deepwater,”paper SPE/IADC 91929, presented at the SPE/IADCDrilling Conference, Amsterdam, February 23–25, 2005.

15. Lenamond and da Silva, reference 14.16. Lenamond and da Silva, reference 14.17. Willson SM, Driscoll PM, Judzis A, Black AD, Martin JW,

Ehgartner BL and Hinkebein TE: “Drilling Salt Formations

19. Willson et al, reference 17. 20. Meize RA, Young M, Hudspeth DH and Chesebro SB:

“Record Performance Achieved on Gulf of MexicoSubsalt Well Drilled with Synthetic Fluid,” paperIADC/SPE 59184, presented at the IADC/SPE DrillingConference, New Orleans, February 23–25, 2000.

21. van Ort E, Lee J, Friedheim J and Toups B: “New Flat-Rheology Synthetic-Based Mud for Improved DeepwaterDrilling,” paper SPE 90987, presented at the SPE AnnualTechnical Conference and Exhibition, Houston,September 26–29, 2004.

Offshore with Seawater Can Significantly Reduce WellCosts,” paper IADC/SPE 87216, presented at theIADC/SPE Drilling Conference and Exhibition, Dallas,March 2–4, 2004.

18. Reynolds numbers (Re) may be expressed in oilfieldunits by Re = 379 x ρ x Q/µ x De, where ρ = fluid densityin lbm/gal, Q = flow rate in galUS/min, µ is fluid density incP, and De is effective diameter of the hole in inches.Therefore, as the effective diameter of the holeincreases as a consequence of leaching, the Reynoldsnumber decreases.

> Powered RSS. Components of a powered RSS(right) add a power section (above) to the basicRSS. As drilling mud passes between the rotorand stator of the power section, the rotorattached to the bit turns. This provides the RSSwith additional torque and rotational speed at thebit and so improves ROP.


attempts to drill this hole section using an insertbit had met with low ROP of 15 to 20 ft/h or hadbeen plagued by shocks and vibrations sufficientto halt drilling or cause BHA failure.

By contrast, the powered RSS delivered aconsistent rate of 35 to 40 ft/h [11 to 12 m/h] anda vertical hole with a 0.17° inclina tion at totaldepth. Judged against similar wells, this 48%overall ROP increase saved the operator anestimated US $1.25 million per well.

In many instances, the top of salt cannot bereached using riserless drilling methods becausesalt migration may have altered stresses in theinterval just above the salt, creating drillinghazards. Fractured or faulted formations areparticularly common when the salt top isrelatively deep. In these environments older,higher-pressured sediments have been pushedupward by the salt and subsequently fractured asthe pressure bled off, creating a potential lostcirculation zone. However, if the pressure is notrelieved, the opposite hazard may exist and theformation just atop the salt may be overpres -sured, creating a zone in which a kick is likely.

In either case, the driller must proceed withcaution. To gain time in which to interpret dataand react to risk as the bit approaches the salt,prudent drillers reduce WOB as they encounterthe first indications that they are nearing the top

of salt: an increase in torque and reduced pene -tration rates. A gamma ray logging tool placedwithin 10 ft [3 m] of the bit provides usefulconfir mation that these drilling parameterchanges correlate to the top of salt.22

With the top of salt thus confirmed, operatorscommonly maintain a cautious approach until theBHA is completely within the salt sheet—typicallyfor 100 to 150 ft [30 to 46 m]. At this point, theycan reasonably assume it is safe to drill a longsection of salt without significant problems.

Drilling Through the SaltIn the Gulf of Mexico, unlike other subsalt playsaround the world, drilling targets are notbeneath deep, depositional, autochthonous salt.Instead they are under salt diapirs, sheets andremnant welds—evacuated salt below mobile,allochthonous salt. These deepwater salt bodiesmay occur as multitiered sheets that areinterconnected by vertical and inclined saltfeeders. Although deepwater salt sheets are notentirely understood, experi ence has shown themto be complex systems with a wide range ofinternal variations. This may be particularly truefor suture zones—where the salt sheets havemerged—that contain pervasive inclusions ofsediments from the surrounding strata.23

As a consequence, within the salt, trappedpressures in rafts of fractured dolomite or inshale inclusions can cause fluid influx—a kick.Though the influx from these kicks may berelatively small, problems can arise if operatorsrespond with standard well-control measures inenvironments with narrow windows between thepore-pressure and fracture gradient.24 Raisingthe mud weight to kill the well, for example, canincrease hydrostatic pressure to a level greaterthan that of the fracture gradient.

Shock and vibration imposed on the BHA maybe the most difficult challenge while drillingthrough salt. Vibration can cause tool twist-off or failure, leading to costly fishing or otherremedial operations and added trips. Unstable oroverly aggressive bits, poorly matched bit-reamercombinations or ratty or creeping salts alsoinduce shock and vibration. Drilling throughheterogeneous formations may also introduceshock and vibration. When the reamer and bitare run simultaneously, often as much as 90 ftapart, it is possible that the bit will be drillingsalt while the reamer is simultaneously drillingan inclusion. This could result in one componentdrilling faster than the other, which could causepoor weight transfer that manifests in shock andvibration levels sufficient to damage the BHA.

The potential hazards associated with drill -ing within or near massive salt sections arelegion. But for many drilling and completionengineers, the most significant is the tendency ofsalt to creep when subjected to stress. Thischarac teristic—essentially pseudoplastic flowcaused by overburden pressures, augmented bysubsur face temperatures and low permeability—accounts for the presence of salt diapirs and cancause newly drilled wellbores to close.

Salt creep involves either two or three creep stages (above left). When the confiningpressures are less than 5 MPa [725 psi], strainbegins at a very high rate and then decreases toa constant rate during the first stage. The secondstage is marked by salt deforming at a constantrate, and in the third stage, the strain rateincreases until failure occurs. When theconfining pressure is more than 5 MPa, no thirdstage is evident.25

For salt formations, the in situ stress isassumed to be equal in all directions and equal tothe overburden weight. The rate at which thewellbore closes because of creep increases withtemperature and the differential pressurebetween the formation stress and the hydrostaticpressure of the mud weight. Also, calculationshave shown that the closure rate is directlyproportional to the wellbore radius.26

42 Oilfield Review

> Salt-creep levels. This plot illustrates the creep behavior of salt at three different levels ofconfining pressure (P). The strain-time curves for confining pressures higher than 5 MPa areidentical to the one conducted at 5 MPa. Therefore, creep results obtained under a confiningpressure of at least 5 MPa are expected to be appropriate for deepwater Gulf of Mexico conditionsfor which the mean stresses are extremely high. (Adapted from Fossum and Fredrich, reference 25.)

Axia

l stra

in

0.25

0.20

0.15

0.10

0.05

00 5 10 15 20

Time, days

P = 2 MPa [290 psi]

P = 5 MPa [725 psi]

P = 1 MPa [145 psi]

0.30


Autumn 2008 43

Other influences on creep behavior includesalt thickness, mineralogy, water content andimpurities. Chloride and sulfate salts containingwater are the most mobile, and halite is rela -tively slow moving. Anhydrite and the othercarbonate evaporates are essentially immobile.27

In the Gulf of Mexico, where the salt compositionis up to 96% halite, creep during the drillingprocess is a smaller problem than in other partsof the world and usually can be controlled withmud weight.

Still, salt creep has been responsible forcasing collapse in a number of Gulf of Mexicowells. In a Green Canyon discovery well, casingcollapsed as a result of catastrophic stresscaused by creep nearly three months after thecasing was set across a 15,000-ft [4,572-m] saltsection. Recommendations for combating thisproblem include under-reaming the slip zone,proper drilling-fluid composition and cementingpractices that improve stress distribution.28

Exiting the SaltDrilling out of the base of salt is fraught with thesame risks as entering it—and for the samereason: The expected stress regimes of thesurrounding formations are disrupted by themigration of the salt body. Immediately beneaththe salt may lie rubble zones that introduceuncertainty as to fracturing, pressure andoverturned beds.29

Most Gulf of Mexico deepwater operatorshave developed company-specific procedures forexiting the salt. In general, drilling engineersseek to exit the salt at a flat or minimally angledlocation at the base of salt or, if that option isimpractical, they attempt to keep the exit anglebetween the salt base and the wellbore close to90° (above right). Once the target exit point is located and the well path established, atabout 400 ft [122 m] above the expected base ofsalt, drillers reduce ROP to about 40 ft/h.Simultaneously, they will monitor and reach asteady state of drilling parameters of torque,WOB, bottomhole temperature, ECD, vibrationand near-bit gamma ray response.

At this point, drillers may increase mudweight and add lost circulation material (LCM)to the system. Prudent drillers also often preparean LCM pill for use in case the subsalt porepressure is lower than that of the salt.

Once changes to drilling parameters informthe operator that the salt base has beenbreached, the driller pulls the bit back up intothe salt and performs a flow check. Whilecirculating cuttings above the BHA, the driller

monitors pit volumes for gains or losses thatindicate kicks or fluid losses in the rubble zone.The next step is to space out the drillpipe—inserting nonstandard lengths of drillpipe intothe drillstring—to ensure drilling can continuebeneath the salt to a depth equal to the length ofa full stand of drillpipe before a connection hasto be made. Drilling is then resumed in 10- to 15-ft intervals with constant monitoring ofdrilling conditions, and the drillstring is repeat -edly pulled back into the salt to circulatecuttings above the BHA and to check pit volumes.

Once it is established that there are no high-pressure, lost circulation or hole-integrityproblems, controlled drilling increments areincreased to 15- to 30-ft [5- to 9-m] intervalsbetween hole checks. This is continued until twostands or up to 300 ft [91 m] below the salt havebeen drilled.30

A Special Exit ChallengeAmong the most vexing problems reported byoperators upon exiting salt in certain deepwaterareas of the Gulf of Mexico are pockets of mobiletar, or bitumen, that often occur below salt and

along faults or welds. This viscous material ismore than 85% asphaltene and has proved to bea significant challenge to drill through.

The problem of bitumen in deepwater subsaltdrilling was initially raised by operator BP whiledrilling its second appraisal well in the Mad Dogfield in Green Canyon Block 82. The operatorreported drilling into a highly viscous

22. Israel et al, reference 3.23. Willson SM and Fredrich JT: “Geomechanics

Considerations for Through- and Near-Salt Well Design,”paper SPE 95621, presented at the SPE Annual TechnicalConference and Exhibition, Dallas, October 9–12, 2005.

24. Willson and Fredrich, reference 23.25. Fossum AF and Fredrich JT: “Salt Mechanics Primer for

Near-Salt and Sub-Salt Deepwater Gulf of Mexico FieldDevelopments,” SAND2002–2063, DOE Contract No. DE-AC04-94AL85000, Sandia National Laboratories, July 2002.

26. Leavitt T: “Steering for Success Beneath the Salt,”Offshore 68 (January 1, 2008): 78–81.

27. Poiate et al, reference 2. 28. Zhang J, Standifird W and Lenamond C: “Casing

Ultradeep, Ultralong Salt Sections in Deep Water: ACase Study for Failure Diagnosis and Risk Mitigation inRecord-Depth Well,” paper SPE 114273, presented at theSPE Annual Technical Conference and Exhibition,Denver, September 21–24, 2008.

29. Israel et al, reference 3.30. Israel et al, reference 3.

> Exiting the salt. While drillers prefer as flat a section as possible to exitthe salt, that is not always an option. As demonstrated in this well plan, thealternative is to build angle within the salt itself so as to create as close to a90° angle as possible between the wellbore and the plane of the base of salt.

Salt

Base of salt

Inclusion


hydrocarbon accumulation, rich in asphaltenesthat were sufficiently mobile to flow into thewellbore (below).31 The active, or mobile,

bitumen occurred as discrete layers along asubsalt fault, ranging in thickness from 10 to100 ft [3 to 30 m]. These deposits of mobile tar,

found throughout the Pliocene and Miocenesections at the base of salt, have ranged frominactive to highly active.

Similarly, a layer of tar up to 100 ft thick wasreported below salt and in faults at the Hess Ponydiscovery in Green Canyon Block 468. Tar hasalso been found at Chevron’s Big Foot prospectand at ConocoPhillips’s Spa prospect, both ofwhich are in Walker Ridge.32

Such mobile tar deposits in deepwater wellsare commonplace, and some intervals have provedeasy to drill through. But in the Green Canyon andWalker Ridge areas and, to a lesser extent,Atwater Valley and Mississippi Canyon, largedeposits found below the base of salt have beendifficult to work through. The primary drillingproblem associated with bitumen is difficultykeeping the borehole open. Even when under-reamers are employed, the borehole is oftenplugged with tar when it is time to run casing.33

The tar zone encountered at the Big Footprospect, for example, effectively preventedChevron from reaching its target depth before itwas forced to release its contracted rig. Althoughnot all time lost was directly attributable to tar,its presence did prevent the original well fromreaching TD. In the end, the resulting rig-schedulechange caused by the delay cost an additional US $55.8 million and 127 unplanned days.34

Drilling problems related to tar depositsinclude the following:• packoffs behind the BHA, resulting in lost

circulation• swabbing of the borehole• shock- and vibration-induced BHA damage• coating of logging tools• stuck tools caused by bridging of the borehole• casing-running problems such as sticking casing

high or excessive time working casing throughtar zones to depth

• excessive trips to clean tar in casing and riser• surface handling problems.

Since tar does not appear on surface seismicdata, its presence is impossible to predict. Todate, the industry offers few options when it isencountered. Increased mud weight does not stopits flow into the wellbore, and though water-basedrilling mud may prevent its adherence to thedrillstring, it does not control it. Conventionalwisdom for dealing with tar remains what it oncewas for all of salt: Avoid it.

44 Oilfield Review

> Mobile tar deposits. This cross section shows the location of tar deposits in several wells of the BPMad Dog field. The mobile tar first became evident while BP was drilling its second appraisal well inthe central part of the field, where tar was observed in the Middle Miocene section from 19,720 to19,280 ft [6,010 to 5,877 m]. Here, tar from a thin permeable sand flowed into the wellbore. (Adaptedwith permission from Romo et al, reference 31.)

Tar Gas

Oil Water

Mad Dog 4 Mad Dog 2 Mad Dog 7 Mad Dog 3

M72

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Active tar Inactive tarVery active tar Very active tar

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3.3 km2 mi

31. Romo LA, Prewett H, Shaughnessy J, Lisle E, Banerjee Sand Willson S: “Challenges Associated with Subsalt Tarin the Mad Dog Field,” paper SPE 110493, presented atthe SPE Annual Technical Conference and Exhibition,Anaheim, California, USA, November 11–14, 2007.

32. Weatherl MH: “Encountering an Unexpected TarFormation in a Deepwater Gulf of Mexico ExplorationWell,” paper SPE/IADC 105619, presented at the SPE/IADCDrilling Conference, Amsterdam, February 20–22, 2007.Rohleder SA, Sanders WW, Williamson RN, Faul GL andDooley LB: “Challenges of Drilling an Ultra-Deep Well inDeepwater—Spa Prospect,” paper SPE/IADC 79810,presented at the SPE/IADC Drilling Conference,Amsterdam, February 19–21, 2003.

33. Willson and Fredrich, reference 23.34. Weatherl, reference 32.35. For more on cementing and zonal isolation: Bellabarba M,

Bulte-Loyer H, Froelich B, Le Roy-Delage S, van Kuijk R,Zeroug S, Guillot D, Moroni N, Pastor S and Zanchi A:“Ensuring Zonal Isolation Beyond the Life of the Well,”Oilfield Review 20, no. 1 (Spring 2008): 18–31.

Abbas R, Cunningham E, Munk T, Bjelland B, ChukwuekeV, Ferri A, Garrison G, Hollies D, Labat C and Moussa O:“Solutions for Long-Term Zonal Isolation,” OilfieldReview 14, no. 3 (Autumn 2002): 16–29.Farmer P, Miller D, Pieprzak A, Rutledge J and Woods R:“Exploring the Subsalt,” Oilfield Review 8, no. 1 (Spring 1996): 50–64.

36. Garzon R and Simmons B: “Deepwater Wells Drive Salt Cementing Advances,” E&P (May 2008): 99–101.

37. Achieving turbulent flow with most cement slurries is notpossible unless the slurry is very thin and the annulargap very small. Therefore, engineers often choose toplace cement using laminar flow at rates of less than8 bbl/min [1.3 m3/min].

38. Nelson EB, Bruno D and Michaux M: “Special Cement Systems,” in Nelson EB and Guillot D (eds): Well Cementing, 2nd ed. Sugar Land, Texas:Schlumberger (2006): 241–242.

39. Close F, McCavitt B and Smith B: “Deepwater Gulf ofMexico Development Challenges Overview,” paperSPE 113011, presented at the SPE North Africa TechnicalConference and Exhibition, Marrakech, Morocco, March 12–14, 2008.


Autumn 2008 45

Tying It DownOnce a salt formation has been drilled, casingmust be run and cemented in place. As withdrilling, salt creep is a significant considerationin cementing operations because it createsnonuniform loading on the casing that canultimately lead to collapse (right). Therefore,besides providing zonal isolation and basicstructural support required of any cement sheath,a cement properly designed for placement acrossa salt zone must also ensure that the loading thatis an inevitable consequence of creep is uniform.To do so, cement must possess sufficient flexuraland tensile strength to withstand the casingpressures and loadings expected over the life ofthe well.35

Cementing experts have traditionally usedsalt-saturated slurries in long salt sections,assuming they would bond better with theformation, resist chemical attack, reduce thetendency of gas migration during setting and beless likely to dissolve salt formations. However, atconcentrations above about 18% by weight ofwater, salt retards thickening time, reducescompressive strength and promotes fluid lossand free-water development.36

As a consequence, the experts have turned tocement whose salt content is based on the saltformation at hand. In a salt-creep environment, ithas been found that low-salinity slurries—10% orless sodium chloride [NaCl] by weight of water—develop early strength and favorable rheologies.

During operations in this environ ment,cement returns should be pumped—ideally inturbulent flow—to above the salt duringdisplacement.37 Cement bond logs should be runwith the casing pressured to help identify anyunusual bonding caused by creep.

Temperature is also a key factor whendesigning slurries for use in salt formations. Hightemperatures increase the dissolution rate of saltsignificantly and mitigate much of the delayedcompressive-strength development associatedwith salt-rich slurries. At tempera tures belowabout 200°F [93°C], experts recom mend 10 to18% NaCl content; at temperatures greater than200°F, an 18 to 36% NaCl content is preferred.

Still, cement slurry design is only one factor inthe success or failure of cement sheaths placedacross salt formations; drilling, casing design andmud removal may have equal or greater influenceon the job’s final outcome. The salt itself isanother variable that can substan tially alterslurry properties. For example, experiments haveshown that 10% contamination of a freshwater

cement system can alter thickening time by 30%,increase slurry viscosity by 100% and increasefluid-loss rates by nearly 500%.38

Potential to Match the ChallengeBy the year 2015, deepwater developments areexpected to account for 25% of worldwideoffshore oil production, compared with about 9% in early 2008. In the Gulf or Mexico, most ofthese areas are in 4,000- to 10,000-ft [1,219- to3,048-m] water depths and are covered by saltcanopies ranging from 7,000 to 20,000 ft [2,100to 6,100 m] in thickness. Overall total depths arefrom 25,000 to 35,000 ft [7,600 to 10,700 m].39

The formations beneath these massive saltshold promise of vast volumes of oil and gasproduction. The volumes for Tupi field in Braziland the implications for the Lower Tertiary trendin the Gulf of Mexico, represented by success atJack field and elsewhere, are already part of oilindustry legend.

Though these and other targets have promptedconsiderable innovation and the industry hasaccomplished much to reach them, producingthem efficiently in terms of recovery rates andeconomics remains a formidable task. Theprimary barrier to exploitation of the subsalt is theindustry’s limited ability to image the base of saltand the formations beneath it accurately. But asthe demand to do so has increased, the seismicindustry has responded with innovative tools andinterpretive processes. It seems only a matter oftime before drillers are equipped to drill throughsalt into the formations below with no moreforeboding than they now experience passingthrough any other mapped transition zone.—RvF

> Cementing across mobile salt. Combating the effects of nonuniform loading caused by salt creeprequires that cement be returned to the top of the salt. In this case (left ), a liner has been set inside acemented casing in an effort to reduce radial pipe deformation. Salt movement (right ) will continue toload the casing and may cause the tubulars to fail over time—an eventuality that can be delayedthrough proper cement placement practices and the use of oversized, high-strength pipe.

Wellbore Displacement

Salt

Caprock

Shear zone

Potentialoverpressured zone

Unconsolidatedzone

Saltflow

Casing Strings

Salt


46 Oilfield Review

High-Pressure, High-TemperatureTechnologies

Gunnar DeBruijnCraig SkeatesCalgary, Alberta, Canada

Robert GreenawaySouthampton, England

David HarrisonMike ParrisSugar Land, Texas, USA

Simon JamesClamart, France

Fred MuellerCorpus Christi, Texas

Shantonu RayAberdeen, Scotland

Mark RidingGatwick, England

Lee TempleHouston, Texas

Kevin WutherichHannover, Germany

For help in preparation of this article, thanks to TrevorBouchard, Calgary; Mary Jo Caliandro, Martha Dutton,Gretchen Gillis, John Still and Don Williamson, Sugar Land,Texas; and Lisa Stewart, Cambridge, Massachusetts, USA.AIT, CemCRETE, CemSTRESS, CNL, FlexSTONE, FlexSTONE HT,Litho-Density, Quicksilver Probe, REDA Hotline550, Sensa,SlimXtreme, SLT, ThermaFRAC, WellWatcher, WellWatcherBriteBlue, WellWatcher Ultra and Xtreme are marks ofSchlumberger.Chemraz is a trademark of Greene, Tweed & Co., Ltd.INCONEL and Monel are trademarks of Special MetalsCorporation. Teflon is a registered trademark of E.I. du Pontde Nemours and Company. Viton is a trademark of DuPont

E&P activity increasingly involves operations in high-pressure, high-temperature

downhole conditions. This environment introduces difficult technical concerns

throughout the life of a well. Scientists and engineers are developing advanced tools,

materials and chemical products to address these challenges.

News reports continually remind us about thecost and availability of energy from fossil fuelsand renewable sources. Despite remarkablegrowth in renewable-energy technology duringthe past 20 years, it is well accepted by thescientific and engineering community that theworld’s energy needs will continue to be satisfiedprimarily by fossil fuels during the next fewdecades. Aggressive exploration and productioncampaigns will be required to meet the coming demand.

Finding and producing new hydrocarbonreserves may be a difficult proposition, oftenrequiring oil and gas producers to contend withhostile downhole conditions. Although high-pressure, high-temperature (HPHT) wells are

fundamentally constructed, stimulated, pro ducedand monitored in a manner similar to wells withless-demanding conditions, the HPHT environ -ment limits the range of available materials andtechnologies to exploit these reservoirs.

The oil and gas industry has contended withelevated temperatures and pressures for years;however, there are no industry-wide standardsthat define HPHT conditions and the associatedinterrelationship between temperature andpressure. In an effort to clarify those definitions,Schlumberger uses guidelines that organizeHPHT wells into three categories, selectedaccording to commonly encountered technologythresholds (below).1

1. Belani A and Orr S: “A Systematic Approach to HostileEnvironments,” Journal of Petroleum Technology 60,no. 7 (July 2008): 34–39.

> HPHT classification system. The classification boundaries representstability limits of common well-service-tool components—elastomeric sealsand electronic devices.

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Autumn 2008 47


In this system, HPHT wells begin at 150°C[300°F] bottomhole temperature (BHT) or69 MPa [10,000 psi] bottomhole pressure (BHP).The rationale for this threshold is related to thebehavior of standard elastomeric seals.Engineers who run downhole equipment in thisenvironment have found it prudent to replace theseals before reusing the tools.

Ultra-HPHT wells exceed the practicaloperating limit of existing electronicstechnology—greater than 205°C [400°F] or 138 MPa [20,000 psi]. At present, operatingelectronics beyond this temperature requiresinstalling internal heat sinks or placing thedevices inside a vacuum flask to shield theelectronics from the severe temperatures.

The HPHT-hc classification defines the mostextreme environments—wells with temperaturesand pressures greater than 260°C [500°F] or241 MPa [35,000 psi].2 Such pressure conditionsare unlikely to be seen in the foreseeable future.However, bottomhole tempera tures in geothermaland thermal-recovery wells already exceed 260°C.

It is important to emphasize that theSchlumberger HPHT classification scheme is notlimited to wells that simultaneously satisfy thetemperature and pressure criteria. If eitherparameter falls within one of the three HPHTregions, the well is classified accordingly. Thus, alow-pressure, shallow steamflood project toextract heavy oil lies in the HPHT-hc regionbecause of the high steam temperature.Conversely, reservoirs associated with low-temperature, high-pressure salt zones in the Gulfof Mexico fit an HPHT classification because ofthe high pressure.

A vital HPHT-well parameter is the length oftime that tools, materials and chemical productsmust withstand the hostile environment. Forexample, logging and testing tools, drilling mudsand stimulation fluids are exposed to HPHTenvironments for a limited time, but packers,sand screens, reservoir monitoring equipmentand cement systems must survive for manyyears—even beyond the well’s productive life.

Accordingly, this time factor has a major impacton how scientists and engineers approachproduct development.

Oilfield Review last reviewed the HPHTdomain in 1998.3 Since then, the number of HPHT projects has grown, and the severity ofoperating conditions has steadily increased(above). For example, a recent proprietary survey by Welling and Company on the directionof subsea systems and services reported that 11%of wells to be drilled in the next three to fiveyears are expected to have BHTs exceeding177°C [350°F]. In addition, 26% of respondentsexpect BHPs between 69 and 103 MPa [10,000 and 15,000 psi], and 5% predict evenhigher pressures.

Today, scientists and engineers push thelimits of materials science to meet the technicalchallenges posed by HPHT wells. This articlesurveys tools, materials, chemical products andoperating methods that have been developed forsuccessful HPHT well construction, stimulation,production and surveillance. Case studiesillustrate the application of some solutions.

48 Oilfield Review

> HPHT projects around the world. During the past decade the number of HPHT projects has increased significantly; nevertheless, these projectsrepresent only about 1% of producing reservoirs worldwide. The principal HPHT areas are found in the United States (deepwater Gulf of Mexico anddeep, hot onshore wells), North Sea, Norwegian Sea, Thailand and Indonesia. In addition, thermal-recovery projects to extract heavy oil are located inCanada, California, Venezuela and eastern Europe.

HPHTUltra-HPHTHPHT-hc


Autumn 2008 49

Testing and Qualification of HPHT TechnologiesHPHT conditions amplify risks that exist inconventional wells. In HPHT wells, the marginfor error is greatly reduced, and theconsequences of failure may be more costly andfar reaching. Therefore, before field application,new products and services designed for hostileenvironments must be rigorously tested andqualified to withstand the tougher downholeconditions.4 This qualifi cation includesaccelerated degradation testing aimed atcalculating ultimate service life withoutperforming several years of testing. To meet thisneed, the industry has built state-of-the-artfacilities that allow engineers to conductrealistic evaluations (right). Many tests areperformed according to standard industrymethods; however, increasingly severe downholeconditions are rapidly approaching the limits ofdocumented testing procedures.5

Laboratory evaluations fall into three principalcategories: fluids, mechanical devices and elec -tronics. Engineers pump a plethora of fluidsystems into wells throughout their productivelives. Testing under simulated downhole condi -tions answers two basic questions. Can the fluidbe prepared and properly placed in the well? Willthe fluid be sufficiently stable to perform itsintended functions? The testing protocol is oftencomplex, involving rheology, filtration, corrosionand mechanical-properties evaluations.6

Mechanical devices include seals, screensand packers, along with rotating andreciprocating parts such as shafts, pistons, valvesand pumps. In addition to HPHT exposure,qualification testing also includes contact withhazards such as mechanical shocks, hydrogensulfide [H2S], carbon dioxide [CO2] and erosiveparticle-laden fluids.

Electronic components and sensors, the thirdelement, are particularly vulnerable to hightemperatures. The key challenge involves thestability of plastic or composite materials thatprovide modern electronics with structuralintegrity and insulation. Electronics manufac -turers do not perform extensive R&D in theHPHT domain because the size of the HPHTelectronics market is tiny compared to consumerelectronics such as mobile phones. As a result,oilfield-equipment engineers must determinethe operational time limit of existing electronicsunder simulated downhole conditions.

The availability of sophisticated test facilities,coupled with an intense R&D effort, has resultedin the development of new HPHT products andservices that span all the stages of well opera -tions. Several of these advances are highlightedin the following sections.

2. The “hc” term comes from the steepest mountain-gradeclassifications used by the Tour de France bicycle race.In the French language, “hc” stands for “horscatégorie,” essentially meaning “beyond classification.”

3. Adamson K, Birch G, Gao E, Hand S, Macdonald C, Mack D and Quadri A: “High-Pressure, High-Temperature Well Construction,” Oilfield Review 10, no. 2 (Summer 1998): 36–49.Baird T, Fields T, Drummond R, Mathison D, Langseth B,Martin A and Silipigno L: “High-Pressure, High-Temperature Well Logging, Perforating and Testing,” Oilfield Review 10, no. 2 (Summer 1998): 50–67.

4. Arena M, Dyer S, Bernard LJ, Harrison A, Luckett W,Rebler T, Srinivasan S, Borland B, Watts R, Lesso B and Warren TM: “Testing Oilfield Technologies for Wellsite Operations,” Oilfield Review 17, no. 4 (Winter 2005/2006): 58–67.

5. Organizations governing the testing and qualification ofoilfield products and services include the AmericanPetroleum Institute (API), International Organization forStandardization (ISO), NACE International (NACE) andASTM International (ASTM).

6. For more on laboratory testing of fluids:Dargaud B and Boukhelifa L: “Laboratory Testing, Evaluation and Analysis of Well Cements,” in Nelson EBand Guillot D (eds): Well Cementing–2nd Edition.Houston: Schlumberger (2006): 627–658.Gusler W, Pless M, Maxey J, Grover P, Perez J, Moon Jand Boaz T: “A New Extreme HPHT Viscometer for NewDrilling Fluid Challenges,” paper IADC/SPE 99009,presented at the IADC/SPE Drilling Conference, Miami,Florida, USA, February 21–23, 2006.“Laboratory Techniques for Fracturing-FluidCharacterization,” in Economides MJ and Nolte KG (eds):Reservoir Stimulation. Houston: SchlumbergerEducational Services (1987): C-1–C-3.

> HPHT testing. Special equipment and facilities are required to evaluate fluids, mechanical devicesand electronics at realistic downhole conditions. Logging tools and associated electronics can beoperated in an HPHT casing simulator (top left ) at temperatures and pressures up to 316°C and 207 MPa. HPHT consistometers (top center) can evaluate the thickening and setting behavior ofcement slurries up to 371°C [700°F] and 207 MPa. (Photograph courtesy of Cement Testing Equipment,Inc.) A similar device for measuring the rheological behavior of drilling fluids can operate at 316°Cand 276 MPa [40,000 psi] (top right). (Photograph courtesy of AMETEK, Inc.) For flow-assurancemeasurements, HPHT pressure-volume-temperature (PVT) cells (center) detect fluid-phase changesand bubblepoints at conditions up to 250°C and 172 MPa. For safety, engineers place the equipment inindividual reinforced testing bays (bottom left ) and control it remotely from a central facility (bottomcenter). Before shipment to the field, integrated solutions can be tested in the well at theSchlumberger Sugar Land, Texas facility (bottom right) , rated to 316°C and 241 MPa.


Drilling and Formation EvaluationWhile drilling HPHT wells, engineers frequentlyencounter overpressured formations, weak zonesand reactive shales. In addition, boreholes areoften slim and highly deviated. To maintain wellcontrol, the drilling-fluid hydrostatic pressuremust be high enough to resist the formation porepressure, yet low enough to prevent formationfracturing and lost circulation. As a conse -quence, the acceptable fluid-density range isoften small, requiring careful control of fluidcirculation to avoid pressure surges that exceedformation-fracture pressures. To prevent forma -tion damage or borehole collapse, the drillingfluid must inhibit clay-mineral swelling. Thedrilling fluid must also be chemically stable andnoncorrosive under HPHT conditions.

During the past decade, drilling fluids based onformate salts have been displacing conventionalhalide-base fluids in HPHT wells.7 Fluidscontaining halides are highly corrosive to steel atelevated temperatures and pose environmentalhazards. Corrosion rates associated with formatesolutions are low, provided the fluid pH remains inthe alkaline range. For this reason, formate mudsare usually buffered with a carbonate salt. Unlikehalides, formates are readily biodegradable andmay be used with confidence in environmentallysensitive areas.

Formates are extremely soluble in water andcan be used to create invert emulsions or solids-free brines with densities up to 2,370 kg/m3

[19.7 lbm/galUS], reducing the need forweighting agents.8 Lower solids concentrations

often improve the rate of drillbit penetration andallow better control of rheological properties.Formate brines also have low water activity;consequently, through osmotic effects, theyreduce the hydration of formation clays andpromote borehole stability.9

Statoil reported success with formate-basefluids when drilling high-angle HPHT wells in theNorth Sea.10 The wells are in the Kvitebjørn,Kristin and Huldra fields, with reservoir pres suresup to 80.7 MPa [11,700 psi] and temperatures upto 155°C [311°F]. Long sequences of interbeddedreactive shales are also present. Despite thechallenging environ ment, Statoil experienced nowell-control incidents in all 15 HPHT drillingoperations in those fields during a five-yearperiod. In addition, control of formation clays anddrilling cuttings helped maintain a low solidsconcentration, allowing the operator to routinelyrecycle and reuse the drilling fluid.

HPHT conditions present abundant chal -lenges to scientists and engineers who design andoperate formation-evaluation tools. As mentionedearlier, the most vulnerable tool compo nents areseals and electronics. Measurement physicsdictates direct exposure of most logging-toolsensors to wellbore conditions; thus, they arebuilt into a sonde. Most sonde sections are filledwith hydraulic oil and incorporate a compen -sating piston that balances the inside and outsidepressures to maintain structural integrity andprevent tool implosion. Current sondes areroutinely operated at pressures up to 207 MPa[30,000 psi].

The electronics are separated and protectedinside a specially engineered cartridge section.11

Unlike sonde sections, cartridges are not pressure-compensated because high pressures would crushthe electronics inside. During a logging trip,electronic components remain at atmosphericpressure inside the cartridge housing, which mustresist the external pressure. Housing collapse notonly would destroy the electronics, but also mightdistort the tool to an extent that fishing would benecessary. Pressure protection is provided bytitanium-alloy housings.

Leaks at seal surfaces or joints may also lead toflooding and cartridge destruction. Therefore, O-rings are strategically placed along thetoolstring to seal connections and internalcompartments. To avoid catastrophic failure of theentire toolstring, individual tools are also isolatedfrom each other by pressure-tight bulkheads in amanner similar to those in a submarine. O-ringsfor HPHT applications are composed offluoropolymeric elastomers. Viton elastomer, themost common example, is rated to 204°C [400°F].At higher temperatures, the Viton formulationbreaks down and loses elasticity. For theseextreme situations, Schlumberger engineers havequali fied O-rings fabricated from Chemrazelastomer—an advanced material that is stable toabout 316°C [600°F] but is significantly moreexpensive than its Viton counterpart.12

Current electronic systems for HPHT loggingcan operate continuously at temperatures up to177°C. The temperature inside the cartridge is afunction of the downhole temperature andinternal heat generated by the electronics. Whenhigher external temperatures are anticipated,engineers place the tool inside an insulatingDewar flask—a vacuum sleeve that delays heattransmission. Depending upon the duration ofthe logging run, Dewar flasks allow operations attemperatures up to 260°C. Recently, extendedrun times have become possible with the intro -duction of low-power electronics that generateless internal heat.

Since the mid 1990s, well depths in the Gulfof Mexico have increased rapidly, and BHTs andBHPs have followed suit (left).13 Conversely,borehole size usually decreases with depth. Inresponse to this trend, Schlumberger engineersintroduced the SlimXtreme well loggingplatform—a miniaturized version of the XtremeHPHT logging system (next page).14 This serviceoffers the same suite of measurements as itslarger counterpart, packaged in a 3-in. diametertoolstring. As a result, the system can be runinside openings as small as 31⁄2-in. drillpipe or 37⁄8-in. open hole. In addition, thanks in part to

50 Oilfield Review

> Trend of maximum well depth in the Gulf of Mexico. A significant acceleration of the trend hasoccurred since the mid 1990s. Unprecedented bottomhole conditions are expected within the nextfew years, with BHTs exceeding 260°C and BHPs approaching 241 MPa.

31,000

33,000

27,000

29,000

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Autumn 2008 51

the lower external surface area of the titaniumhousing, the SlimXtreme toolstring can operateat pressures up to 207 MPa.

Chevron applied SlimXtreme technology inthe Gulf of Mexico while logging deepwaterexploratory wells at the Tonga prospect in GreenCanyon Block 727. During logging runs to31,824 ft [9,700 m], the system experienced pres -sures up to 26,000 psi [180 MPa] and continuedto operate successfully. Another Chevronexploratory well, the Endeavour 2 in south Texas,tested SlimXtreme performance at elevatedtempera tures. The toolstring, incorpo ratingportions enclosed within a Dewar flask, was ableto provide reliable data to 21,800 ft [6,645 m] and489°F [254°C].

Deep HPHT wells present additional wireline-logging challenges. Multiple runs are usuallynecessary to acquire the information, and smallboreholes, long cables and heavy toolstringsincrease the risk of the tools becoming stuck.

7. Formate salts are based on formic acid—HCOOH.Sodium, potassium and cesium formate (and combina -tions thereof) are used in drilling-fluid applications.

8. An invert emulsion contains oil in the continuous, orexternal, phase and water in the internal phase.

9. Water activity (aw ) is the equilibrium amount of wateravailable to hydrate materials. When water interactswith solutes and surfaces, it is unavailable for otherhydration interactions. An aw value of one indicates purewater, whereas zero indicates the total absence of“free” water molecules. Addition of solutes (such asformate salts) always reduces the water activity.Byrne M, Patey I, George L, Downs J and Turner J:“Formate Brines: A Comprehensive Evaluation of TheirFormation Damage Control Properties Under RealisticReservoir Conditions,” paper SPE 73766, presented atthe SPE International Symposium and Exhibition onFormation Damage Control, Lafayette, Louisiana, USA,February 20–21, 2002.

10. Berg PC, Pedersen ES, Lauritsen A, Behjat N, Hagerup-Jenssen S, Howard S, Olsvik G, Downs JD,Harris M and Turner J: “Drilling, Completion andOpenhole Formation Evaluation of High-Angle Wells inHigh-Density Cesium Formate Brine: The KvitebjørnExperience, 2004–2006,” paper SPE/IADC 105733,presented at the SPE/IADC Drilling Conference,Amsterdam, February 20–22, 2007.

11. The sonde is the section of a logging tool that containsthe measurement sensors. The cartridge contains theelectronics and power supplies.

12. Viton elastomer is a copolymer of vinylidenfluoride andhexafluoroisopropene, (CH2CF2)n(CF(CF3)CF2)n. Chemrazelastomer is a similar compound that contains morefluorine. Both are related to the well-known Teflonfluoropolymer.

13. Sarian S: “Wireline Evaluation Technology in HPHTWells,” paper SPE 97571, presented at the SPE HighPressure/High Temperature Sour Well Design AppliedTechnology Workshop, The Woodlands, Texas, May 17–19, 2005.

14. Introduced during the late 1990s, Xtreme well-logging toolsrecord basic petrophysical measurements at conditions upto 260°C and 172 MPa [25,000 psi]. The measurementsinclude resistivity, formation density, neutron porosity,sonic logging and gamma ray spectroscopy.Henkes IJ and Prater TE: “Formation Evaluation in Ultra-Deep Wells,” paper SPE/IADC 52805, presented at the SPE/IADC Drilling Conference, Amsterdam, March 9–11, 1999.

> Equipment and software for wireline logging and sampling in HPHT wells.The SlimXtreme platform (left ), designed for slimhole drilling in HPHT andhigh-angle wells, provides a complete suite of downhole measurements inboreholes as small as 37⁄8-in. Engineers run the tools at speeds up to 1,097 m/h[3,600 ft/h], and data can be transmitted to the surface through wireline aslong as 10,970 m [36,000 ft]. Temperature planning software simulates thelogging job and predicts external (red) and internal (blue) tool temperaturesversus time (top right). In this example, the external tool temperature risesand falls as the tool is lowered into the well and then retrieved. However, theinternal tool temperature remains well below the 160°C limit (green),indicating that the electronics will be protected. These simulations are usefulfor optimizing the operation and ensuring tool survival. The applicationconsiders several job parameters, including well conditions, logging speedand the presence of Dewar flasks. The risk of stuck toolstrings increaseswhen logging and sampling from deep, slim HPHT wells. A high-tensiondeployment system (bottom right) mitigates the risk by combining a standardSchlumberger wireline unit, a high-strength dual-drum capstan and high-strength wireline cable. The capstan increases the pulling force that can beexerted on the wireline, allowing retrieval of heavy toolstrings and reducingthe risk of sticking.

Time, min

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CNL compensated neutron log tool

Litho-Density tool

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Caliper sonde

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Fishing operations to retrieve tools from deepholes are expensive, time-consuming andprecarious—possibly resulting in stuck drillpipe,tool damage or tool loss. To minimize the danger,Schlumberger engineers developed an improvedtool-deployment method using high-tension cableand a capstan. The system allows rapiddeployment of the logging string and much higherpulling capacity, reducing the risk of tool sticking.

Another important wireline operationinvolves acquiring fluid samples from hydro -carbon reservoirs and analyzing them downholeor at the surface. Test results provide oilcompanies with information necessary to decidehow to complete a well, develop a field, designsurface facilities, tie back satellite fields andcommingle production between wells.15 HPHTconditions increase the difficulty of downholesampling. In addition, pressurized live-fluidsamples must be safely transported to thesurface and then to nearby laboratories.Sampling operations in HPHT wells are costly,especially offshore; therefore, collecting high-quality samples is crucial to justify the expense.

In 2004, Chevron began drilling exploratorywells into the Lower Tertiary play in the deepwaterGulf of Mexico (see “The Prize Beneath the Salt,”page 4). These wells can be difficult to drill andcomplete, with water depths to 9,800 ft [3,000 m],total well depths exceeding 25,000 ft [7,600 m],and BHPs and BHTs often approaching 20,000 psi[138 MPa] and 392°F [200°C]. In 2006, Chevrondecided to invest considerable resources and rigtime to perform an extended well test (EWT) onthe Jack 2 well, southwest of New Orleans and

175 mi [282 km] offshore. The long-term drillstemtest (DST) was necessary to acquire vital reservoirand production information that would reduceuncertainty and risk involving reservoir compart -mentalization, fluid properties and productivity. At28,175 ft [8,588 m], the Jack 2 test would be thedeepest ever attempted in the Gulf of Mexico.

Before performing the DST, Chevron selectedthe Quicksilver Probe fluid-sampling tool toextract high-purity formation-fluid samples. Thissystem employs a unique multiple fluid-intakesystem to minimize formation-fluid samplecontamination, and it operates in conditions to350°F. Samples acquired by the QuicksilverProbe module contained less than 1% contami -nation after 4 hours of pumping. Fluid-propertiesdata provided by the samples allowed theoperator to make drilling and well-testing proce -dure adjustments that reduced the overall risk.

The Jack 2 EWT also required an HPHTperforating system. Consulting with Chevronpersonnel, Schlumberger engineers built a toolcombination that is rated to 25,000 psi [172 MPa].The Jack 2 perforating system incorporated a 7-in.gun capable of firing 18 shots per foot, as well as aperforating shock absorber and a redundantelectronic firing head. Approximately ninemonths of engineering, manufacturing and testingwere required to achieve full qualification. A final90-day performance test took place at theSchlumberger Reservoir Completions (SRC)Center in Rosharon, Texas, inside a test vesselthat simulated the anticipated downhole condi -tions. The equipment functioned properly, andChevron engineers approved deployment of theperforating equipment to the rig.

The EWT was a success, and the Jack 2 wellsustained a flow rate exceeding 6,000 bbl/d [950 m3/d] of crude oil from about 40% of thewell’s net pay. This result led Chevron and itspartners to request various sizes of HPHTperforating systems for additional appraisal wellsnearby and future field developments elsewherein the deepwater Gulf of Mexico.16

Cementing and Zonal IsolationProviding zonal isolation in deep oil and gas wellssuch as Jack 2 requires use of cement systemsthat are stable in HPHT environments. Thermallystable cements are also necessary in steamfloodwells and geothermal wells.17 The physical andchemical behavior of well cements changessignificantly at elevated temperatures andpressures. Without proper slurry design, theintegrity of set cement may deteriorate,potentially resulting in the loss of zonal isolation.Unlike many other HPHT technologies, wellcements are permanently exposed to downholeconditions and must support the casing andprovide zonal isolation for years.

Portland cement is used in nearly all well-cementing applications. The predominantbinding minerals are calcium silicate hydrates(CSH). At temperatures above about 110°C[230°F], mineralogical transformations occurthat may cause the set cement to shrink, losestrength and gain permeability. This deterio -ration can be minimized or even prevented byadding at least 35% silica by weight of cement.The compositional adjustment causes theformation of CSH minerals that preserve thedesired set-cement properties. Although silica-stabilized Portland cement systems can be usedat temperatures up to about 370°C [700°F], theyare susceptible to other challenges posed bythermal wells.

A thermally stable cement system mayinitially provide adequate zonal isolation;however, changes in downhole conditions caninduce stresses that compromise cement-sheathintegrity. Tectonic stresses and large changes inwellbore pressure or temperature may crack thesheath and can even reduce it to rubble. Radialcasing-size fluctuations induced by temperatureand pressure changes can damage the bondbetween the set cement and the casing or theformation, creating a microannulus. Theseproblems are of particular concern in deep, hotwells and thermal-recovery wells employingcyclic-steam-stimulation (CSS) or steam-assisted-gravity-drainage (SAGD) processes.18

52 Oilfield Review

> FlexSTONE HT cement properties at 200°C compared with those ofconventional cements. To ensure proper bonding between the cement/casingand cement/formation interfaces, FlexSTONE cements can be formulated toprovide significantly more expansion after setting than conventional systems(left ). FlexSTONE HT systems also offer improved zonal-isolation properties,including lower Young’s modulus and lower permeability (right).

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Autumn 2008 53

Until recently, the well cementing industryfocused on one mechanical parameter—unconfined uniaxial compressive strength—toqualify a cement design. The longer-term diffi -culties described above led Schlumbergerscientists to more thoroughly investigate themechanical properties of set cement, along withmodels governing the mechanical behavior ofsteel pipe and rocks. They adapted the models tothe geometry of a well and introducedCemSTRESS software—an application thatanalyzes the behavior of a cement sheath exposedto anticipated downhole conditions. This softwareanalyzes radial and tangential stresses experi -enced by the cement sheath resulting frompressure tests, formation-property changes andtemperature fluctuations. Along with compressivestrength, the CemSTRESS algorithms considerYoung’s modulus, Poisson’s ratio and tensilestrength and help engineers determine theappropriate cement mechanical properties for agiven application.19

CemSTRESS analysis usually indicates thatcement sheaths in CSS and SAGD wells should bemore flexible than in conventional systems. Thiscan be achieved by using cements with lowerYoung’s moduli (previous page).20 In addition, thecement sheath should expand slightly aftersetting to ensure firm contact with the casingand formation. These requirements led to thedevelopment of FlexSTONE HT high-temperatureflexible cement.21 This cement is part of a familythat combines the engineered particle-sizeconcept of CemCRETE technology with flexibleparticles that lower the Young’s modulus.22 Inaddition, expansion after setting can besignificantly higher than that of conventionalcement systems, promoting bonding with thecasing and formation.23 The temperature limit ofFlexSTONE HT cement is about 250°C [482°F].

An operator in the UK region of the North Seahad an ambitious goal of producing gas at asustained 6.8-million m3/d [240-MMcf/d] produc -tion rate from three wells with a BHT of 193°C

[380°F].24 Meeting this goal would requireunusually high drawdown pressures, exertingsigni ficant mechanical stress on the casing,cement sheath and formation. Using CemSTRESSsoftware, Schlumberger engineers determinedthat placing FlexSTONE HT cement across theproduction zone would provide a gasket-like sealcapable of withstanding the severe environment.After cement placement, the production stringswere subjected to pressure tests up to 69 MPa anddrawdown tests exceeding 41 MPa [6,000 psi]. Thecement sheath remained intact. After more thantwo years of production, there have been no well-integrity problems.

Heavy-oil projects involving SAGD wells alsoemploy FlexSTONE HT cement extensively. Aneastern European reservoir contained aparticularly thick crude oil—12,000-MPa-s[12,000-cP] viscosity and a 17°API gravity. Oilmining had been the standard recovery method.To reduce production costs, the operator electedto try the SAGD method in a pilot well. Thisapproach presented multiple well-constructionconcerns: 300-m [984-ft] horizontal sections at aTVD of 228 m [748 ft], temperatures approaching250°C and stresses on the cement sheathresulting from thermal production cycles and asoft formation. FlexSTONE HT cement success -fully withstood the production conditions with noloss of zonal isolation, and the operator hasplanned additional SAGD installations. CSS andSAGD wells in Canada, Venezuela, Egypt,Indonesia and California, USA, have alsobenefited from FlexSTONE HT cement.

CSS and SAGD wells require specialized, high-performance completion equipment to handlethe extreme temperature cycles. Commonelastomeric seals often fail, allowing pressure andfluids to escape up the casing, reducing steam-injection efficiency and increasing the potentialfor casing corrosion. Recently, Schlumbergerengineers began using seals fabricated from ayarn of carbon fibers contained within anINCONEL alloy jacket. These seals are capable of

operating at cycled-steam temperatures up to340°C [644°F] and pressures up to 21 MPa[3,000 psi], allowing reliable deployment ofthermal liner systems (above).

15. Akkurt R, Bowcock M, Davies J, Del Campo C, Hill B,Joshi S, Kundu D, Kumar S, O’Keefe M, Samir M,Tarvin J, Weinheber P, Williams S and Zeybek M:“Focusing on Downhole Fluid Sampling and Analysis,”Oilfield Review 18, no. 4 (Winter 2006/2007): 4–19.Betancourt S, Davies T, Kennedy R, Dong C, Elshahawi H,Mullins OC, Nighswander J and O’Keefe M: “AdvancingFluid-Property Measurements,” Oilfield Review 19, no. 3(Autumn 2007): 56–70.

16. Aghar H, Carie M, Elshahawi H, Ricardo Gomez J,Saeedi J, Young C, Pinguet B, Swainson K, Takla E andTheuveny B: “The Expanding Scope of Well Testing,”Oilfield Review 19, no. 1 (Spring 2007): 44–59.

17. Nelson EB and Barlet-Gouédard V: “Thermal Cements,”in Nelson EB and Guillot D (eds): Well Cementing–2ndEdition. Houston: Schlumberger (2006): 319–341.

18. Alboudwarej H, Felix J, Taylor S, Badry R, Bremner C,Brough B, Skeates C, Baker A, Palmer D, Pattison K,Beshry M, Krawchuk P, Brown G, Calvo R,

Stiles D: “Effects of Long-Term Exposure to UltrahighTemperature on the Mechanical Parameters of Cement,”paper IADC/SPE 98896, presented at the IADC/SPEDrilling Conference, Miami, Florida, February 21–23, 2006.

22. For more on engineered-particle-size cements:Nelson EB, Drochon B and Michaux M: “Special Cement Systems,” in Nelson EB and Guillot D (eds): Well Cementing–2nd Edition. Houston: Schlumberger(2006): 233–268.

23. Cement systems that expand slightly after setting are aproven means for sealing microannuli and improvingprimary cementing results. Improved bonding resultsfrom tightening of the cement sheath against the casingand formation.

24. Palmer IAC: “Jade North Sea HPHT Development:Innovative Well Design Generates Best in ClassPerformance,” paper SPE/IADC 92218, presented at the SPE/IADC Drilling Conference, Amsterdam, February 23–25, 2005.

Cañas Triana JA, Hathcock R, Koerner K, Hughes T,Kundu D, López de Cardenas J and West C: “Highlighting Heavy Oil,” Oilfield Review 18, no. 2(Summer 2006): 34–53.

19. Thiercelin M: “Mechanical Properties of Well Cements,”in Nelson EB and Guillot D (eds): Well Cementing–2ndEdition. Houston: Schlumberger (2006): 269–288.James S and Boukhelifa L: “Zonal Isolation Modelingand Measurements—Past Myths and Today’s Realities,”paper SPE 101310, presented at the SPE Abu DhabiInternational Petroleum Exhibition and Conference,Abu Dhabi, UAE, November 5–8, 2006.

20. Young’s modulus, also called the modulus of elasticity, isthe ratio between the stress applied to an object and theresulting deformation, or strain. Lower Young’s modulicorrespond to more flexible materials.

21. Abbas R, Cunningham E, Munk T, Bjelland B,Chukwueke V, Ferri A, Garrison G, Hollies D, Labat C andMoussa O: “Solutions for Long-Term Zonal Isolation,”Oilfield Review 14, no. 3 (Autumn 2002): 16–29.

> Schlumberger high-temperature liner hanger.Developed for steamflood applications, the linerhanger features seals made from carbon fiberand INCONEL alloy. The tool has permanent slipsand a one-piece mandrel to minimize possibleleak paths and can be rotated while running inthe hole. To date, Schlumberger engineers haveinstalled more than 150 units in Canada, with nopressure-test failures. Some of the systems havesurvived up to 10 thermal cycles to 343°C [649°F].

Upper tiebacksealbore

Permanenthold-down slip

Heavy-oil-thermal(HOT) seal

Permanenthanging slip

Liner connection


Schlumberger high-temperature thermalliner hangers have been used in the Cold Lakefield, where a major operator in Canada isconducting a horizontal-well CSS program.25 Withcustomized liners and carbon-fiber andINCONEL seals at the top of the liner, theoperator has been able to achieve good steamconformance—steam intake spread evenly overthe length of the horizontal well—verified bytime-lapse seismic surveys over the pilot area.

Reservoir Stimulation and ProductionReservoir stimulation encompasses two majortechniques: matrix acidizing and hydraulicfracturing. Both procedures bypass formationdamage incurred during drilling, cementing andperforating, and they also provide an enhancedconnec tion between the formation rock and thewellbore. The goal is to increase hydrocarbonproduction to levels far exceeding what would bepossible under natural-flow conditions.26

Matrix acidizing consists of pumping a low-pHfluid through naturally existing channels in therock, at rates that are sufficiently low to avoidcreating fractures in the formation. The aciddissolves soluble components of near-wellboreformation rock and damaging materialsdeposited by previous well-service fluids, therebycreating a more permeable path for hydrocarbonflow. Acidizing fluids are formulated to stimulatecarbonate or sandstone formations.

Most carbonate acidizing involves reactinghydrochloric acid (HCl) with formations com -posed of calcium carbonate (calcite), calciummagnesium carbonate (dolomite) or both. As theacid flows through perforations and dissolves thecarbonate rock, highly conductive channels calledwormholes are created in the formation.Wormholes radiate from the point of acid injectionand carry virtually all of the fluid flow duringproduction (left). For efficient stimulation, thewormhole network should penetrate deeply anduniformly throughout the producing interval.

HCl is an effective stimulation fluid at lowtemperatures, but it can be problematic when usedat temperatures exceeding about 93°C [200°F]. Athigher temperatures, this mineral acid attacks theformation too rapidly, mini mizing the depth anduniformity of the wormholes. These conditions alsopromote excessive tubular corrosion and requireengineers to add high concentrations of toxiccorrosion inhibitors. Recently, Schlumbergerchemists solved these problems by developingacidizing fluids based on hydroxyethylamino -carboxylic-acid (HACA) chelating agents. Commoncommercial HACA compounds such as tetra -sodium EDTA and trisodium HEDTA have beenused in the oil field for decades, mainly as scale-removal agents and scale inhibitors.27

A variety of HACA compounds underwentlaboratory testing at temperatures up to 200°C.The evaluation consisted mainly of corefloodtests in limestone and corrosion-rate measure -ments involving common tubular metals. Thebest performer was trisodium HEDTA, bufferedto a pH value of about 4. Less acidic than acarbonated beverage, this formulation is far lesscorrosive than conventional mineral acids, andvery low tubular corrosion rates can be achievedby adding small amounts of milder, environ -mentally acceptable corrosion inhibitors. Withits higher pH, trisodium HEDTA reacts moreslowly and creates an extensive, farther-reachingwormhole network rather than a short dominant

54 Oilfield Review

> Wormholes formed during a laboratory-scale matrix acidizing treatment ofa carbonate-formation sample. The length, direction and number ofwormholes depend on the formation reactivity and the rate at which acidenters the formation. Once formed, the wormholes carry virtually all of thefluid flow during production.


Autumn 2008 55

one (right). In addition, HEDTA fluid is far moreefficient than HCl at HPHT conditions. Acomparable level of stimulation may be achievedby pumping less than one-tenth the fluid volume(below right).28

Hydraulic fracturing involves pumping largevolumes of fluid through perforations and into theformation at rates and pressures sufficient to notonly create a fracture, but also propagate it farbeyond the near-wellbore region. The final fluidstage fills the fracture with proppant—silicate,ceramic or bauxite granules with high sphericity—leaving a high-permeability conduit between theproducing formation and the wellbore.29

Fracturing-fluid viscosity is a critical param -eter that governs fracture initiation andpropagation, as well as proppant transport downthe tubulars, through perforations and into thefracture. At HPHT conditions, sufficient fluidviscosity is usually achieved by preparing metal-crosslinked solutions of guar-base polymers. Themost common metal crosslinkers are boron andzirconium.30 However, viscosity attainment alone isnot sufficient to perform a successful HPHTfracturing treatment. To minimize friction-pressure losses as the fluid is pumped downhole,the crosslinking reactions should be delayed untiljust before the fluid enters the perforations. Inaddition, the viscosity should not be undulysensitive to the high-shear-rate environmentcommonly found in the tubulars and perfora tions;otherwise, the fluid will be ill equipped for fracturepropagation and proppant transport, increasingthe likelihood of a premature screenout.31

The characteristics of borate- and zirconate-crosslinked fluids are fundamentally different.Borate crosslinking arises from ionic bonds thatcan break under high-shear conditions; however,the bonds heal and fluid viscosity recovers whena low-shear environment is restored. Zirconate-crosslinked fluids are not as forgiving becausethe linkage results from covalent bonds that formonly once. If the fluid crosslinks and experienceselevated shear too early, the bonds will break

25. Smith RJ and Perepelecta KR: “Steam ConformanceAlong Horizontal Wells at Cold Lake,” paper SPE/PS-CIM/CHOA 79009, presented at the SPE InternationalThermal Operations and Heavy Oil Symposium andInternational Horizontal Well Technology Conference,Calgary, November 4–7, 2002.

26. For more on reservoir stimulation: Economides MJ andNolte KG (eds): Reservoir Stimulation, 3rd Edition. NewYork City: Wiley, 2003.

27. Chelating agents, also known as sequestering agents,are compounds used to control undesirable reactions ofmetal ions (such as Ca, Mg and Fe). For example, theyform chemical complexes that do not precipitate duringacidizing treatments, thereby preventing formation

29. For more on hydraulic fracturing: Economides and Nolte,reference 26.

30. Crosslinks are bonds that link one polymer chain toanother. Boron and zirconium interact with guar-basepolymers, forming linkages that increase the effectivepolymer molecular weight by several orders ofmagnitude and dramatically increase the fluid viscosity.

31. Screenout occurs when proppant particles bridge theperforations and block further fluid ingress. Thiscondition is accompanied by a sudden treatment-pressure increase. A premature screenout occurs when the fracture volume is insufficient, when less than the desired amount of proppant is placed in thefracture, or both.

damage. EDTA and HEDTA are acronyms for ethylene -diaminetetraacetic acid and hydroxyethylene diaminetri-acetic acid.Frenier WW, Fredd CN and Chang F: “Hydroxyamino -carboxylic Acids Produce Superior Formulations forMatrix Stimulation of Carbonates at High Temperatures,”paper SPE 71696, presented at the SPE Annual Technical Conference and Exhibition, New Orleans,September 30–October 3, 2001.

28. Frenier WW, Brady M, Al-Harthy S, Arangath R,Chan KS, Flamant N and Samuel M: “Hot Oil and GasWells Can Be Stimulated Without Acids,” paper SPE 86522, presented at the SPE InternationalSymposium and Exhibition on Formation DamageControl, Lafayette, Louisiana, February 18–20, 2004.

> Acidizing coreflood test with 20% Na3HEDTA. Technicians pumped the acid through a 2.54-cm [1-in.]diameter, 30.5-cm [12-in.] long limestone core at 177°C [350°F]. The Na3HEDTA solution creatednumerous wormholes that formed a complex network. The photograph of the core entrance (left )shows the formation of many wormholes. The CT-scan sequence (right) confirms that the wormholenetwork extends throughout the core length. The upper-left CT-scan image displays the coreentrance, and subsequent core sections continue from left to right.

> Comparing the acidizing efficiency of 15% HCl (purple) and Na3HEDTA(green) at 177°C. This graph shows the amounts of acidizing fluid (expressedin pore volumes) required to radially penetrate 30.5 cm [12 in.] into a 30.5-m[100-ft] interval of 100-mD carbonate formation with 20% porosity. The resultsindicate that, regardless of pumping rate, trisodium HEDTA is more than oneorder of magnitude more efficient than HCl.

1,000

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irreversibly, fluid viscosity will decrease, and thescreenout probability will increase (below).Therefore, it is vital to control the timing and thelocation of crosslinking.

Although less forgiving, zirconate-crosslinkedfluids have been used almost exclusively in HPHTfracturing treatments, mainly because they arethermally more stable than borate fluids. Despitesteady advances in fluid design, achieving

sufficient crosslink control with zirconate fluidshas remained elusive. The crosslinking reactionsare temperature-sensitive, and predicting circu -lating temperatures inside tubulars of HPHTwells is often difficult.

Chemists solved these problems by com -bining the best features of borates andzirconates into one system—ThermaFRACfracturing fluid. The new dual-crosslinker fluid,based on carboxymethylhydroxypropyl guar(CMHPG), features two crosslinking events—anearly low-temperature reaction involving borate,and a secondary temperature-activated oneinvolving zirconate. Borate crosslinking provideslow shear sensitivity, and zirconate bondingcontributes thermal stability (next page).32 Fluidpreparation is simpler and more reliable becauseadditives previously used to stabilize and controltraditional zirconate-only fluids are no longernecessary. Laboratory tests have demonstratedsuitable performance at temperatures from 200° to 375°F [93° to 191°C].

South Texas has long been a major center ofHPHT activity, and operators there have come torely heavily on new technologies to solveproblems. Producing reservoirs are deep andmust frequently be stimulated through longtubing strings or slimhole completions. This wellgeometry is problematic for two main reasons.First, treatment pump rates must be reduced tominimize friction-pressure losses and decreasethe number of pump trucks at the wellsite.33

Lower flow rates limit the fluid pressure thatengineers may apply to initiate and propagate ahydraulic fracture. Second, fracturing fluidsexperience high amounts of shear as they flowthrough small-diameter tubulars, and zirconate-base fluids are particularly susceptible topremature deterioration. Dual-crosslinker fluidshave successfully addressed these problems.

One example involves a well that sufferedcasing collapse after a fracturing treatment.Workover operations to restore communicationand production were unsuccessful, and theoperator’s only remaining option was to sidetrackthe wellbore and install a slimhole completion.The operation involved lowering 12,200 ft[3,719 m] of 23⁄8-in. tubing from surface to theproducing interval and then cementing it inplace. Wellbore integrity was a serious concernbecause of damage resulting from the workoveroperations. In addition, the operator was worriedabout friction-pressure losses and high leakoffrates arising from fluid diversion into theexisting fracture. The thickness of the producingsandstone interval was 46 ft [14 m], and the BHTwas 310°F [154°C].

56 Oilfield Review

> Shear-history behavior of guar fluids crosslinked by borate and zirconate compounds. Rheologicaltesting of fracturing fluids involves two principal devices: a shear-history simulator and a viscometer.The shear-history simulator exposes fracturing fluids to shearing conditions they would experiencewhile traveling down the tubulars toward the perforations. The viscometer measures the fracturing-fluid viscosity at various shear rates, temperatures and pressures. Shear-history studies determinehow shearing in the tubulars would affect fluid viscosity. Technicians measure and plot the rheologicalbehavior of two identical fluids—one that has undergone pretreatment in the shear-history simulator(blue) and one that has not (pink). Test results show that, after prolonged exposure to a high-shear-rateenvironment in the shear-history simulator, the borate-crosslinked fluid recovered and achieved thesame viscosity as its counterpart that did not experience pretreatment (top). The viscosity plotseventually overlapped. On the other hand, the zirconate-crosslinked fluid permanently lost viscosityafter pretreatment in the shear-history simulator (bottom). This effect would increase the potential forscreenout. The baseline viscosities on the plots correspond to a 100-s–1 shear rate. The periodic spikesdenote shear-rate ramps in the viscometer up to about 300 s–1. Viscosity measurements at variousshear rates allow calculation of additional rheological parameters that engineers use to optimizefracturing-fluid designs.

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Autumn 2008 57

The operator approved a ThermaFRAC treat -ment that addressed the anticipated difficulties.The pad volume was unusually large—65% of thetotal job—and the CMHPG concentration washigh—45 lbm/1,000 galUS [5.4 kg/L]—tocompensate for the high leakoff rate.34 To mini -mize friction pressure, the maximum pump ratewas 12 bbl/min [1,908 L/min]. The proppantslurry placed 62,000 lbm [28,120 kg] of 20/40-mesh resin-coated bauxite at concentra -tions up to 8 lbm/galUS [961 kg/m3] of fracturingfluid. Following the success of this treatment, theoperator applied dual-crosslinker fluids inadditional slimhole applications, including onein which 295,000 lbm [133,810 kg] of 20/40-meshceramic and resin-coated ceramic proppant wereplaced into a 74-ft [22.6-m] interval through11,600 ft [3,536 m] of 27⁄8-in. tubing. At thiswriting, more than 60 ThermaFRAC treatmentsinvolving 11 operators have been successfullyperformed in south Texas, at bottomhole tempera -tures between 121° and 191°C [250° and 375°F].

The new fracturing fluid has also been used tostimulate a gas-bearing HPHT sandstone reservoirin northern Germany. The average formation depthis 4,550 m [14,930 ft] TVD, and the BHT isapproximately 150°C. BHPs vary from 25 to 30 MPa[3,630 to 4,350 psi], and the formation-permeability range is 0.1 to 5 mD. In this area,engineers usually perform fracturing treatmentsthrough a dedicated tubing string with the rig inplace. To save money, the operator wanted to beginstimulating wells without the rig, pumping thetreatment through the final well-completion string.

Fracturing fluids are usually prepared withambient-temperature mix water. However, pump -ing a cool fluid through a finished completionwould cause sufficient tubular contraction toexert excessive stress on packers and jeopardizezonal isolation. Therefore, to minimize thermaleffects, it would be necessary to preheat the mixwater to 50°C [122°F]. Zirconate crosslinking istemperature-dependent, and it was unlikely thatreliable rheological control would be possiblewith a traditional single-crosslinker system.

To develop a solution, engineers conductedfluid-design experiments at the SchlumbergerClient Support Laboratory in Aberdeen,Scotland. This facility has testing equipment thatcan simulate both the thermal environment andthe shear environment antici pated in theGerman well. Test results showed that the dual-crosslinker fluid would allow sufficient leeway todesign a treatment compatible with theoperator’s cost-saving goal.

Engineers performed the ThermaFRAC treat -ment in a well with a 30-m [98-ft] producing zone,pumping 184 m3 [48,600 galUS] of fluid with aCMHPG loading of 4.8 kg/m3 [40 lbm/1,000 galUS],and placing 32 metric tons [70,500 lbm] of 20/40resin-coated high-strength proppant in the frac -ture. The resulting fracture conductivity in thiswell was 250% higher than those of offset wellstreated with conventional single-crosslinkerfluids, and the production rate was 30% higherthan the operator’s prediction. Consequently, theoperator has chosen this fluid to stimulate sevenmore wells in this region.

Certain types of HPHT reservoirs would notbenefit significantly from matrix-acidizing orhydraulic-fracturing treatments. Perhaps thebest examples are heavy-oil deposits, in whichthe preferred stimulation method involves oil-

viscosity reduction by steam injection. Steamgeneration comprises approximately 75% of theSAGD operating expenses. Reducing thesteam/oil ratio (SOR) and maintaining anoptimal production rate are keys to improvingprofitability. Reducing steam input saves energycosts, decreases produced-water volume andtreatment expenses, and curtails associated CO2

emissions. A 10 to 25% SOR reduction may beachieved by using electric submersible pump(ESP) systems.

ESPs allow reservoirs to be produced atpressures that are independent of wellhead orseparator pressures, thereby increasing steam-injection efficiency and decreasing the produc tioncost by at least US $1.00 per barrel of produced oil.Numerous Canadian operators, including Encana,Suncor, ConocoPhillips, Nexen, TOTAL, Husky and

32. Guar gum, a powder consisting of the ground endospermof guar beans, is used extensively as a food thickener.Guar-gum derivatives are purified and functionalizedproducts with good thermal stability. Common derivativesfor hydraulic-fracturing applications includehydroxypropyl guar (HPG) and carboxymethyl -hydroxypropyl guar (CMHPG).

33. Friction-pressure loss is the pressure decrease arisingfrom frictional losses that occur as a fluid passes

through pipe. The pressure decrease is mainly a functionof pipe diameter, pipe length, fluid rheological propertiesand flow rate. High friction reduces the available fluidpressure at the pipe outlet.

34. Fracturing treatments consist of two fluid stages. Thefirst stage, the pad, initiates and propagates the fracture.The second stage, the proppant slurry, transportsproppant down the tubulars, through the perforationsand into the fracture.

> Shear-history behavior of ThermaFRAC fluid at 135°C [275°F]. After prolonged exposure to a highshear rate in the shear-history simulator, the viscosity of ThermaFRAC fluid does not change significantly.

Visc

osity

at 1

00 s

–1, c

P

0

200

100

300

400

500

600

800

700

900

1,000

0 50 75 100 125 150 175 20025

Time, minUnshearedSheared at 1,350 s–1 for 5 min

ThermaFRAC Fluid


Blackrock, have installed the REDA Hotline550high-temperature ESP system in steam-injectionwells (left). Rated to operate continuously at up to288°C [550°F] internal motor temperature, or218°C [425°F] bottom hole temperature, theequipment employs high-temperature thermo -plastic motor-winding insulation and is designedto compen sate for variable expansion andcontraction rates of the different materials in thepump. Many of these installations have operatedcontinuously for more than two years.

SurveillanceMaintenance of an optimal reservoir-temperature distribution is vital to efficientheavy-oil production from SAGD or CSS wells;therefore, engineers need to acquire real-timetemperature information to make necessarysteam-injection or production-rate adjustments.For more than a decade, WellWatcher distributedtemperature sensing (DTS) systems have beencapable of transmitting data to surface by lasersignals that travel through Sensa fiber-opticcable.35 However, conventional DTS systems donot function properly in an HPHT environment.

Most optical fibers begin to degrade whenexposed to hydrogen, which occurs naturally inwellbores. This degradation accelerates at hightemperatures, detrimentally affecting signaltransmission and measurement accuracy. Attemperatures above 200°C, conventional opticalfibers exposed to a hydrogen-pressured environ -ment may become unusable within days.

Schlumberger and Sensa engineersresponded by developing WellWatcher BriteBluemultimode optical fiber from a material that ismore thermally stable and chemically resistantto hydrogen (below).36 An improved version,WellWatcher Ultra DTS system, is equipped with

58 Oilfield Review

> REDA Hotline550 ESP artificial lift system. The multicomponent toolstringcan be used in wells with BHTs up to 218°C (center). The heart of the systemis the centrifugal pump, equipped with silicon- or tungsten-carbide bearingsfor durability at extreme temperatures (left ). The number of stages can alsobe adjusted according to the completion requirements. The pump motoremploys metal-to-metal seals to provide a heat-resistant mechanical barrierto fluid entry (right). Cables that transmit power to the motor and data tosurface are protected by insulating armor composed of heavy galvanizedsteel, stainless steel and corrosion-resistant Monel alloy (inset). As ofNovember 2008, the Hotline550 system is operating in more than 100Canadian thermal wells.

Pump

Intake

Motor

> Hydrogen effects on optical-fiber performance after HPHT exposure. Accelerated testing methods determine the high-temperature performance ofWellWatcher BriteBlue multimode fiber (blue) compared with that of conventional single-mode optical fibers (red and orange). Light transmittance of themultimode fiber deteriorates at a significantly lower rate (left ), allowing the fibers to transmit data for years after installation. Unlike the single-mode fibers,the new fiber material maintains the ability to transmit light throughout the useful wavelength range (right).

Ligh

t los

s

Ligh

t los

s

Time, min Wavelength, nm

Standard single-mode fiberPure core single-mode fiberWellWatcher BriteBlue fiber


Autumn 2008 59

the new fiber and can measure temperatureswith ±0.01°C [±0.018°F] accuracy over distancesup to 15 km [9.3 mi] with a 1-m [3.3-ft] spatial resolution.

Since 2007, the new fiber-optic system hasbeen installed in Canadian steamflood comple -tions with BHTs up to 300°C [572°F] (above). Sofar, no discernable reduction in fiber ormeasurement performance has been observed,and the temperature data are providingoperators with reliable guidance for decidinghow to adjust steam injection and oil productionto achieve maximum efficiency (right).

35. Al-Asimi M, Butler G, Brown G, Hartog A, Clancy T,Cosad C, Fitzgerald J, Navarro J, Gabb A, Ingham J,Kimminau S, Smith J and Stephenson K: “Advances inWell and Reservoir Surveillance,” Oilfield Review 14,no. 4 (Winter 2002/2003): 14–35.

36. Multimode optical fiber is mainly used for communica -tion over relatively short distances, such as within abuilding or a campus. Typical multimode links supportdata rates up to 10 Gbits/s over distances up to a fewkilometers. Multimode fiber has a higher “light-gathering”capacity than single-mode optical fiber and allows theuse of lower-cost electronics such as light-emittingdiodes or low-power lasers that operate at the 850-nm wavelength.

> SAGD-well temperature profile acquired by the WellWatcher BriteBlue system.Optical fibers transmit temperature data to surface at a 1-m [3.3-ft] resolution. Thesharp temperature increase indicates that steam injection is effectively confined tothe horizontal interval between about 900 and 1,500 m [2,950 and 4,920 ft].

Sampling position, m

Tim

e, s

Tem

pera

ture

, °C

0

50

100

150

200

250

300

180

160

140

120

100

80

60

40

20

00

5001,000

1,5002,000

166 to 195

138 to 166

109 to 138

81 to 109

53 to 81

25 to 53

3 to 25

Temperature

> WellWatcher BriteBlue fiber installation in a heavy-oil well. Engineers pump the fiber through a conduit inside a coiled tubing string (inset) that is hungfrom the surface across the producing interval.

Steam injection

Oil recovery


Future HPHT Technology DevelopmentsSignificant technologies introduced during the past decade are allowing operators toconfidently address numerous challenges posedby HPHT projects (above). As HPHT activitycontinues to grow and well conditions becomemore severe, more advanced devices andmaterials will be required.

Engineers are working to translate theadvances realized with HPHT wireline logging tothe MWD/LWD environment. The measurementsystems must not only withstand elevatedtemperature and pressure, but also performreliably when exposed to shocks and vibrationsassociated with drilling operations. The goal is to

reduce drilling risk by enabling better wellplacement, improved borehole stability and adecreased number of required trips.

Current chemical research involves extendingthe useful range of additives for primary andremedial cementing, as well as stimulationfluids, into the HPHT-hc realm. This workincludes developing novel sealants for pluggingand abandoning HPHT wells at the end of theiruseful lives, and ensuring long-term isolation toprevent fluid flow between subterranean zonesor to the surface. In addition, research is under -way to develop completion equipment fabricatedfrom materials with better resistance tocorrosive fluids and gases.

Extensive operator involvement in equipmentdesign and manufacture, as well as chemical-product development, is not typical for standardwells; however, operator participation will becrucial to the success of future ultra-HPHT andHPHT-hc operations. Cooperation betweenoperators and service companies will be vital forproper quali fication testing, manufacturing,assembly, testing and installation. Schlumbergerscientists and engineers are committed toparticipating in this cooperative process, helpingthe industry at large advance the technologiesnecessary to meet the world’s growing demandfor energy. — EBN

60 Oilfield Review

> HPHT products and services summary. The range of products and services for HPHT wells spans the productive life of a well. The color codes indicatehow technologies fit into the HPHT, ultra-HPHT and HPHT-hc schemes. Products and services highlighted in this article are shown in boldface.

Drilling

Evaluation

Cementing

Stimulation

Completions

Artificial lift

RSS 150° C

155° C

MWD 175° C

Petrophysics

Reservoir

Geology

Geophysics

Additives

Upper

Lower

Perforating

Monitoring

ESP

Test

Evaluation

Testing

Wireline (SlimXtreme platform) 260° C

LWD 175° C

Wireline 260° C

LWD 150° C

Wireline 175° C

LWD 150° C

Wireline (SlimXtreme platform) 260° C

LWD 150° C

DST 215° C

Tubing conveyed perforating 200° C

Retarder 249° C

Fluid loss 249° C

Quicksilver Probe tool

Subsurface safety and isolation valves

Packers

Screens

Fluids

Tools

Thermal liner hanger

Permanent

WellWatcher Ultra system

REDA Hotline550 ESP

Production logging

Flow control

260° C

260° C

250° C

316° C

Fluids

175° C

230° C

190° C

205° C

218° C

175° C

200° C

200° C

218° C

150° C

175° C

175° C

260° C

340° C

300° C

175° C

35kpsi

30kpsi

32.5kpsi

25kpsi

27.5kpsi

22.5kpsi

20kpsi

17.5kpsi

15kpsi

12.5kpsi

10kpsi

MaximumtemperatureService Domains

Dri

lling

and

Eva

luat

ion

Dev

elop

men

tPr

oduc

tion

Formate drilling fluids

FlexSTONE HT cement

HEDTA acidizing fluid

ThermaFRAC fluid

HPHT>150°C or 10 kpsi

Ultra-HPHT HPHT-hc

Hydraulic-fracturing monitoring

>205°C or 20 kpsi >260°C or 35 kpsi


Marco Aburto Perez has been a Schlumberger DrillingEngineer, North Gulf Coast, since moving to Houston in2006. He began his career in 2001 as a Drilling &Measurements field engineer assigned to US locations,including California, Oklahoma, Wyoming and Alaska.In 2004, he joined Baker Hughes and moved to Mexicoas drillbit applications engineer. Marco has a BS degreein mechanical engineering from Universidad de lasAméricas, Cholula, Puebla, Mexico.

Michele Buia is Seismic Processing Technical Advisorand Geophysical Advisor for Australasia and theMiddle East, based at the Eni E&P headquarters inMilan, Italy. Since 1992, he has held various technicalpositions in data processing, participated in four-com-ponent (4C) survey planning, acquisition and process-ing projects and managed an R&D project to integrateseismic and nonseismic geophysical methods. From2003 to 2008, he led the Eni seismic processing group.Michele received a degree in geology with a special-ization in rock mechanics from the University ofBologna, Italy.

Robert Clyde is the Drilling Engineering andOperations Support Manager for Schlumberger, USGulf of Mexico. His key specialties include deepwaterwell design, drilling optimization and surveillance ofremote drilling operations. Based in Houston since2005, he began his career as a field engineer forAnadrill Schlumberger in 1990 in the UK sector of theNorth Sea. He later relocated to Venezuela where heheld various field management positions withSchlumberger Integrated Project Management andSchlumberger Drilling & Measurements from 1995 to2003. In 2007 and 2008, he led the SchlumbergerDeepwater Engineering Special Interest Group, aworldwide group of around 1,500 Schlumbergeremployees involved in deepwater engineering. Robertholds a BEng degree (Hons) in engineering fromUniversity of Strathclyde, Glasgow, Scotland.

Piero D'Ambrosio has been Schlumberger Drilling &Measurements Deepwater Drilling EngineeringManager for the North America Gulf Coast since 2008.Currently based in Houston, he joined Schlumbergerin the UK in 1997 and began his career as a field engi-neer in Aberdeen. He moved to Assen, TheNetherlands, in 2000 as a drilling engineer, thenbecame directional drilling coordinator. In 2003, hemoved to Bangkok, Thailand, as manager of theDrilling Engineering Center for Thailand, Myanmarand Vietnam. Before taking his current position, hewas a senior drilling engineer in Houston. Pieroobtained a BS degree in mechanical engineering fromUniversidad Metropolitana in Caracas.

Gunnar DeBruijn is Technical Manager forSchlumberger Cementing Services in Canada. He isresponsible for cementing applications in Canada,such as heavy oil, steam-assisted gravity drainage(SAGD), shallow gas, foothills, arctic, offshore anddeepwater wells, including world-record extended-reach wells. He began his career as a field engineerwith Dowell in 1991. Based in Calgary since 2003, hehas worked to adapt Schlumberger cementing tech-nology to the Canadian market. He is a member of the

Association of Professional Engineers, Geologists, andGeophysicists (APEGGA) in Alberta, Society ofPetroleum Engineers (SPE), and the PetroleumSociety of Canada. Gunnar received his BS degree inmechanical engineering from the University ofAlberta in Edmonton, Canada.

John R. Dribus is the Global Geoscience TrainingCurriculum Director and a Principal Geologist forSchlumberger Data & Consulting Services. Based inNew Orleans, he is a reservoir geologist with morethan 30 years of experience in the Gulf of Mexico. Hisassignments have spanned all aspects of exploration,exploitation and production geology for Schlumbergerand for a major oil and gas company, including morethan 15 years in the deepwater Gulf of Mexico, andfive years as a uranium field geologist. His areas ofexpertise are petroleum systems analysis, deepwateranalogs, geological risk analysis and geoscience train-ing and development. John currently serves on theAdvisory Board of the American Petroleum Institute,on the Public Outreach Committee of the AmericanAssociation of Petroleum Geologists (AAPG) and isthe judging chairman for the AAPG Imperial BarrelCompetition. He holds BS and MS degrees in geologyfrom Kent State University, Ohio, USA.

Pablo E. Flores is Vice President for Geophysics inthe Eni E&P Division, based in Milan. He has been inthe exploration business since 1976, when he startedworking for Western Geophysical in Brazil andColombia. He joined Eni (formerly Agip) in 1979, andinitially worked in the seismic processing and studiesgroup, then in domestic exploration. In 1987, he wasposted to Libya as chief geophysicist. Between 1991and 2003, he held various exploration, new venturesand geoscience management positions in Norway, theUK and in the Milan head office. He returned to Milanin 2003 as exploration planning manager for theEurope, Americas, Russia & Australasia Business Unit.In 2005, he became head of Eni GeophysicalCorporate Services. Pablo studied physics and geologyat the Universities of Pisa and Florence, and earnedan MSc degree in geological sciences from theUniversity of Florence, Italy.

José Formigli was recently appointed to a newly cre-ated Executive Manager post in Petrobras domesticE&P, called E&P-PRESAL. This position is specificallydedicated to evaluation and production developmentof presalt discoveries, encompassing the cluster ofrecent strikes in Santos basin, offshore Brazil. Sincejoining Petrobras in 1983, he has worked in severalactivities related to well completion and subsea engi-neering, starting as an offshore company man andlater managing those activities. José was productionmanager of Campos basin, Marlim field asset man-ager, E&P services executive manager and E&P pro-duction-engineering executive manager. He receiveddegrees in civil and petroleum engineering from theInstituto Militar de Engenharia and PetrobrasUniversity, respectively, and an MBA in advanced busi-ness management from the COPPEAD GraduateSchool of Business of the Universidade Federal do Riode Janeiro.

Robert Greenaway has been Product Champion forSchlumberger Fiber Optics & Surface AcquisitionSystems since July 2008. He works in theSouthampton Product Center, England, as part of theCompletions Reservoir Monitoring and Control (RMC)organization. He provides the link between opera-tions, the business team and the product centers toensure the highest quality of measurements and datadelivery. Prior to his current responsibilities, he wasassigned to Schlumberger Sensa* fiber optics as prod-uct and operations support engineer and productchampion in the Southampton Product Center. Hejoined Schlumberger in 2000 at Aberdeen. As a fieldengineer for Coiled Tubing Services from 2000 to 2005,he also was UK product champion for DepthLOG* CTdepth correlation tool in 2003. In this role, Rob com-bined three new technologies, DepthLOG, eFire* firinghead and OrientXact* guns, to implement and per-form the first successful oriented perforating oncoiled tubing in the North Sea using wireless pulsetelemetry. He was a CoilTOOLS* technical supportengineer at the Sugar Land Product Center from 2005to 2006. He holds a BEng degree in mechanical engi-neering from University of Southampton.

David Harrison is Schlumberger Testing ServicesMarketing Communications Manager, based in SugarLand, Texas. Thirty years ago, after obtaining a BSdegree in civil engineering from University ofMemphis, Tennessee, USA, he began his career atJohnston Schlumberger in Bossier City, Louisiana,USA, as a testing field engineer. He has held a varietyof management positions at Flopetrol Johnston andwith Schlumberger Wireline & Testing from 1982 to2000. David moved to Houston in 2000 to assume theposition of training, development and technologyapplications manager for North and South America.He has also served as market systems strategist, busi-ness systems discriminator and marketing businesssystems manager for the Schlumberger WellCompletions & Productivity group.

David Hill, Applied Geophysics Manager atWesternGeco in Gatwick, England, joined the companyin 2000. He is responsible for global geophysical sup-port for WesternGeco. Previously, he worked withAmoco UK for 10 years as an operations geophysicistand designed, acquired and processed 2D and 3D seis-mic surveys to meet the objectives of exploration anddevelopment asset teams. He also worked in variouspositions for Western Geophysical from 1978 to 1990,gaining experience in all the data processing-relateddepartments and in geophysical software development.David received a BSc degree (Hons) in physics and geo-physics from the University of Liverpool, England.

Marianne Houbiers works as a Research Geophysiciston seismic modeling and imaging within the ImprovedOil Recovery Research Program in the StatoilHydroResearch Centre in Trondheim, Norway. She joinedStatoilHydro in 2006. Previously, she worked as a sur-vey methodologist in the methods departments ofStatistics Netherlands and Statistics Denmark.Marianne holds MSc and PhD degrees in theoreticalphysics from Utrecht University, The Netherlands.

Autumn 2008 61

Contributors


Riaz Israel, who is based in Houston, has been aSchlumberger Senior Drilling Engineer for Gulf ofMexico deepwater drilling operations since 2006. Hejoined the company in 2001 as a drilling engineer inTrinidad. Riaz previously worked as a petroleum engi-neer for Mora Oil Ventures Ltd in Trinidad. He holdsan MSc degree in petroleum engineering and a BScdegree in chemical engineering, both from theUniversity of the West Indies, St. Augustine, Trinidadand Tobago. Riaz has been a member of the SPEsince 2000.

Martin P.A. Jackson is a Senior Research Scientistwith the Bureau of Economic Geology at TheUniversity of Texas at Austin. There, he establishedand coleads the Applied Geodynamics Laboratory, anindustry-funded research group that works on salttectonics. He earned BS and BS (Hons) degrees fromthe University of London and a PhD degree from theUniversity of Cape Town, South Africa, for researchon Precambrian high-grade gneiss terranes. TheAAPG has awarded him the J.C. “Cam” SprouleMemorial, George C. Matson Memorial, Robert H.Dott, Sr., Memorial, A.I. Levorsen Memorial and JulesBraunstein Memorial awards. Martin’s currentresearch blends 3D seismic interpretation, modelingand field work on allochthonous salt sheet advancein the Gulf of Mexico, folded evaporite canopies inthe Canadian High Arctic, intrasalt Messinian short-ening in the eastern Mediterranean, salt tectonicson Mars and plate-kinematic reconstruction of ter-restrial salt basins.

Simon James is Technology Manager for the WellIntegrity Technology (WIT) Discipline, at theSchlumberger Riboud Product Center in Clamart,France, a position he has held since 2005. Previously,he was a project manager for WIT where his responsi-bility for deliverables of Cement Sheath Integrity(CSI) resulted in the commercialization ofFlexSTONE HT* technology in 2004. Simon began hisSchlumberger career in 1993 at Dowell in St. Austell,England, as project leader for joint projects involvingmajor operating companies in the areas of lubrica-tion, HPHT rheology, wellbore stability, reservoirdrill-in fluids, corrosion inhibition and automaticmud monitoring. After serving as a senior develop-ment engineer at the Sugar Land Product Center, hemoved to the Schlumberger Riboud Product Center in2000. He is a member of the UK Institute of Physicsand a chartered physicist. He has numerous publica-tions in professional journals and holds 11 patents.Simon received a PhD degree in physics and a BAdegree in natural sciences from the University ofCambridge in England.

Carl Johnson, who is based in Aberdeen, has beenSchlumberger Well Services GeoMarket TechnicalEngineer (Cementing) for the North Sea since 2007.He began his career in 1996 as a cementing engineerat Schlumberger Well Services in Aberdeen. Heworked offshore for several years as a technical engi-neer with major North Sea clients including Shell. In2001, he became a senior cementing instructor at theWell Services Kellyville Training Center in Tulsa. Carljoined the Schlumberger Product Development Teamin Clamart, France, as advanced cementing systemsproduct champion in 2003. He has a BEng degree(First Class Hons) in mechanical engineering fromThe University of Manchester, England.

Jerry Kapoor currently manages the WesternGecoCenter of Excellence for Subsalt Imaging in Houston.He began his career with Geophysical Service Inc. inCroydon, England, and has managed seismic data pro-cessing centers in Stavanger, Houston and Bedford,England. In 1990, he began developing and applyingtechnology to image steep dips and subsalt sediments.Since 1994, he has managed the evolution of theWesternGeco depth-imaging business from prestackdepth migrations to the current state-of-the-art wideazimuth surveys. He has been involved in a number ofsuccessful complex imaging projects in the deepwaterGulf of Mexico.

Sergio Laura, Exploration Manager for Eni Indonesiain Jakarta, joined Eni in 1984. After an initial periodin the Milan head office, he began an internationalcareer that took him to London, Beijing and Cairo,with increasing responsibilities in exploration man-agerial positions. He returned to the Milan headoffice in 2002, as manager for Africa, Middle East,Italy and Southern Europe as well as a director ofseveral Eni subsidiaries. In 2006, he was posted to hiscurrent assignment in Jakarta. Sergio received anMSc degree in geological sciences from the Universityof Genoa, Italy.

Tony Leavitt is Schlumberger In-House SeniorDrilling Engineer for Chevron’s Deepwater Gulf ofMexico operations. He joined Schlumberger inTrinidad in 1991 as a mud logger and an MWD engi-neer. In 1997, he was transferred to South America asengineer in charge of Venezuela West operations forMWD and directional drilling services. Two years later,he became field services manager in Quito, Ecuador,and was the Bolivia Drilling & Measurements locationmanager in 2000. He later returned to Ecuador in2001 as the integrated services coordinator for Eni’sVillano Phase 2 drilling program in the Amazon jun-gle. Tony subsequently worked as a Schlumbergerdrilling optimization engineer for Shell and other Gulfof Mexico independents in 2002, before transferring tohis current location in Houston in 2005. He obtainedhis BS degree in electrical engineering from FloridaAtlantic University in Boca Raton, USA.

Cem Menlikli is a Project Manager in charge of explo-ration in offshore Black Sea Block 3921 at TurkishPetroleum Corporation (TPAO) in Ankara, Turkey. Hejoined the company in 1993 as a reservoir geologist.He later held various positions as seismic interpreterin exploration and development projects on carbonatereservoirs in the southeast Anatolian basin, the con-tinuation in Turkey of the North Arabian plate. In2002, he joined the company’s Black Sea offshoreasset team and has been primarily involved with mod-eling petroleum systems and developing new play con-cepts in the Black Sea. Cem received his BSc degree(Hons) in geological engineering from Middle EastTechnical University (METU) in Ankara; he also hasan MS degree in geophysics from Colorado School ofMines, Golden, USA.

Nick Moldoveanu, Geophysical Advisor in theWesternGeco Center of Excellence for Subsalt Imagingin Houston, has been with Schlumberger Geco-Praklaand WesternGeco since 1989. He has held technicalpositions in data processing, seismic programming,marine acquisition and reservoir seismic services. Heis involved in the development of new acquisition andprocessing techniques for seismic imaging in complexenvironments. Nick received MSc degrees in geo-physics and mathematics from the University ofBucharest, Romania.

Fred Mueller, who is based in Corpus Christi, Texas,is the GeoMarket* Technical Engineer forSchlumberger Well Services, South Texas basin. Hejoined Dowell in 1980 as a field-engineering represen-tative in Bryan, Texas. He has worked in various oper-ational, sales and engineering roles during his 28years with Schlumberger. Fred holds a BS degree inengineering technology from Texas A&M University inCollege Station.

Les Nutt, who is based in Houston, has beenSchlumberger Borehole Seismic Operations Manager,North America, since 2004. He began his career as anarea geophysicist with Geophysical Service Inc. in the UK and Saudi Arabia. He joined Schlumberger inParis in 1981 and then worked as a log analyst andgeophysicist in the Far East and in Europe. He movedto Norway in 1991 as Wireline & Testing marketingmanager. In 1995, he joined the SchlumbergerInterpretation Development team in Paris andHouston before transferring to the SchlumbergerEngineering Center in Japan as marketing manager.Les moved to Houston in 2002 as the geophysicsdomain manager. He earned a BSc degree (Hons) inpure and applied physics and a PhD degree in physicsfrom Queen’s University Belfast, Northern Ireland.

Ed Palmer is a Regional Integrated SolutionsManager for WesternGeco. Based in Gatwick, he man-ages seismic projects in Europe, Africa and the BlackSea. He began his career in 1976 with the Republic ofSouth Africa Department of Minerals and Energy, col-lecting and interpreting geophysical data for ground-water, diamond and mineral exploration projects. In1979, he returned to England to work for GeophysicalService Inc. (GSI) in seismic data processing. As GSIevolved into Halliburton Geophysical Services,Western Geophysical and then WesternGeco, Edgained experience in supervising 2D, 3D and 4Dmarine data processing projects around the world. Heis a graduate of the University of Liverpool, England,with a BSc degree (Hons) in physics and geophysics.

Mike Parris, Schlumberger Stimulation FluidsEngineering Principal Engineer, is working to developfracturing fluids, crosslinkers and additives. Based inSugar Land, he began his career in 1985 in Tulsa, ascomputing center manager for laboratory automation.Mike has held senior development engineering posi-tions at Schlumberger Product Centers in Tulsa and inSugar Land. He received a BS degree in chemistryfrom the University of Oklahoma in Norman.

62 Oilfield Review


Shantonu Ray, who is based in Aberdeen, has beenSchlumberger North Sea Wireline Special ServicesOperations Manager since 2007. He oversees special-ized services including seismic, tractors and HPHTtools with a focus on service quality and HSE. He hasalso served as a Schlumberger InTouch engineer,cased hole business development manager andaccount manager, field service manager, service qual-ity coach, cased hole lead engineer and engineer-in-charge in various locations in India, Japan and Iraq.Shantonu earned a Master of Technology degree inmechanical engineering from the Indian Institute ofTechnology in Mumbai.

Mark Riding, Deepwater Theme Director forSchlumberger Oilfield Services in Gatwick, England,is responsible for corporate strategic planning andtechnology development worldwide. He began his 26-year career as a field engineer for Flopetrol well test-ing and interpretation services and transferred toWireline Open Hole Services in 1990. He has subse-quently worked in various field, sales and manage-ment capacities, including district management forWireline Operations, Trinidad; business manager forTesting Services, Asia; general manager for TestingServices worldwide; and vice president and generalmanager for Subsea Services worldwide. Mark holds aBSc degree in mining and chemical engineering fromthe University of Birmingham in England.

Rob Ross, who is based in Gatwick, is MarineMarketing Manager for WesternGeco. He joinedGeco-Prakla in 1997 and held various positions indata processing, both onshore and offshore, workingin Europe, West Africa and Australasia. He joined themarine geophysical support group in Gatwick in2000. After a period in technical support for geophys-ical operations in Europe, Rob moved to Stavanger,where he spent three years as a Q* project facilitatorand account manager. Rob received his MEng and BAdegrees in chemical engineering and natural sci-ences from University of Cambridge, England, andhis MBA degree from RSM Erasmus University,Rotterdam, The Netherlands.

Craig Skeates is the Project Manager for the HeavyOil Tech Hub team in Calgary, designing new thermalcompletion systems for SAGD wells and other in situproduction techniques involving steam in heavy oil orbitumen. From 1998 to 2002, he was a wireline fieldengineer in Brooks, Alberta, Canada, where he han-dled perforating, production logging, cement evalua-tions and other cased hole operations. Craig has a BSdegree in chemical engineering from University ofSaskatchewan, Saskatoon, Canada.

Martiris F. Smith, Integrated Solutions Manager atWesternGeco, worked for large and small oil compa-nies before joining WesternGeco from BP in 2000.During the last 39 years, he has been a division geo-physicist, manager of geophysics, exploration man-ager and manager of technical services. Thesepositions have taken him to Mozambique, the FarEast, South Africa, Libya, France and the USA. AtWesternGeco he has held positions such as worldwide

marketing manager for seismic data processing andboth North America marketing manager and assetdevelopment manager. Martiris received a BSc degree(Hons) in geology and physics from the University ofNottingham in England and has participated in execu-tive training programs at the Whittemore School ofBusiness and Economics at the University of NewHampshire, Durham, USA, and the Darden GraduateSchool of Business Administration, University ofVirginia, Charlottesville, USA.

Earl Snyder, Indonesia Country Manager forWesternGeco, is based in Jakarta. Before this, he heldseveral positions in operations, marketing and person-nel management for Asia, Africa, South America,Russia and the UK. His early years with the company,from 1993 to 2000, involved land seismic operations inAlgeria, Nigeria and Oman. He also worked as a mar-keting analyst for land operations in Houston. Earlhas a BS degree in electrical engineering fromColorado School of Mines, Golden.

Lee Temple, Sales Engineer for SchlumbergerOilfield Services in Houston, is responsible for identi-fying client needs and providing value-based solu-tions in stimulation, coiled tubing and cementing.Before assuming his current position in 2005, he wasbased in Odessa, Texas, where he was a design andevaluation services engineer, Permian basin. In 1991,he joined Dowell in Beckley, West Virginia, USA,working on the design, execution and evaluation ofcementing and fracturing treatments. He joinedOilfield Services in 2001 in Midland, Texas. Lee alsoheld sales and management positions in Oklahomaand Kansas. He obtained a BS degree in mechanicalengineering from Virginia Polytechnic Institute andState University in Blacksburg.

Mark Thompson is Team Leader for Acquisition andImaging within the Improved Oil Recovery ResearchProgram at the StatoilHydro Research Centre inTrondheim, Norway. Previously, he worked on develop-ment of 4C processing and acquisition technologies,and on time-lapse seismic processing and modeling.He began his career in 1989 as a field geophysicistwith Western Geophysical. Before assuming his cur-rent post, he supervised onboard seismic data pro-cessing projects for Geco-Prakla, based in Gatwick.Mark holds a BSc degree in applied earth sciencefrom Kingston Polytechnic and an MSc degree inpetroleum geology and geophysics from ImperialCollege, both in London.

Robin Walker, Marketing Director for WesternGeco inGatwick, has more than 20 years of technical market-ing and sales experience with the company. In his var-ious roles, he has directed the identity and businessmodel of the Q seismic product, contributed toresearch and engineering technical directions anddefined and monitored engineering activities. Beforetaking his current post, he held positions in Houston,Stavanger, Singapore and Sydney, Australia. Robinbegan his career in 1980 as a staff geologist in the UK,then moved into land seismic data processing beforejoining WesternGeco in 1985. He has a BSc degree ingeology from Royal Holloway and Bedford NewCollege, University of London.

Don Williamson is a Project Manager forSchlumberger Stimulation Fluids Engineering, basedin Sugar Land. Before moving to this position in 2007,he was a senior editor for the Schlumberger OilfieldReview. He has also served as technical manager fordrilling fluids at the Europe-Africa Technology Centerin Aberdeen, as drilling fluids product line specialistfor the Dowell Europe-Africa marketing group in Parisand as drilling fluids operations manager for the GulfCoast GeoMarket area. Don began his career withIMCO-Halliburton in 1978 and joined Schlumberger in1981. He obtained a BS degree in chemistry and biol-ogy at the State University of New York at Albany, USA.

Kevin Wutherich, based in Hannover, Germany, hasbeen Schlumberger Technical Engineer for Stimulationin Europe since 2006. His responsibilities are to designand evaluate stimulation treatments throughoutEurope. Since joining Schlumberger in 2000, he hasheld the positions of field engineer, Fort Smith,Arkansas, USA; field engineer, Elk City, Oklahoma; andDESC* engineer, Oklahoma City, Oklahoma. Hereceived a BASc degree in chemical engineering fromUniversity of Waterloo, Ontario, Canada.

Autumn 2008 63

An asterisk (*) is used to denote a mark of Schlumberger.


The scope of coverage is quite significant and the reference listastounding—it is amazing to see howmuch material is contained within [the book].

Overall, a book well worth itsprice.… Highly recommended.

Field MS: Choice 45, no. 7 (March 2008): 1189.

Seabed Fluid Flow: The Impacton Geology, Biology and theMarine EnvironmentAlan Judd and Martin HovlandCambridge University Press The Edinburgh Building Cambridge CB2 2RU, England 2007. 492 pages. US $160.00ISBN 0-52181-950-4

Submarine fluid seepage has significant effects on seabed mor -phology, mineralization and ecology,impacting the composition of theoceans and atmosphere. This bookdescribes the features and processes ofseabed fluid flow, and demonstratestheir importance to human activitiesand natural environments.

Contents:

• Introduction to Seabed Fluid Flow

• Pockmarks, Shallow Gas, and Seeps:An Initial Appraisal

• Seabed Fluid Flow Around the World

• The Contexts of Seabed Fluid Flow

• The Nature and Origins of Flowing Fluids

• Seabed Fluid Flow and Biology

• Shallow Gas and Gas Hydrates

• Migration and Seabed Features

• Seabed Fluid Flow and Mineral Precipitation

• Impacts on the Hydrosphere and Atmosphere

• Implications for Man

• References, Index

Coming in Oilfield Review

Advances in Magnetic Resonance.Medical science has embracednuclear magnetic resonance (NMR)as a noninvasive method of evaluat-ing humans. Oilfield applications ofa similar technology provide operatorswith noninvasive analysis of theproperties of in situ fluids. This articledescribes recent developments inNMR applications, includingimprovements in traditional acquisi-tion techniques and novel softwareprograms that transform conven-tional static images into dynamic 3Dmaps of the changing characteristicsof the fluid in reservoir rocks.

Monitoring CT Performance. Since its inception, coiled tubing (CT)operations have relied on monitoringof surface parameters to infer thestatus of downhole conditions.Although such measurements arebased on sound engineering princi-ples, most are not capable of distin-guishing subtle downhole changes inreal time. Fiber-optic sensors andtelemetry are now helping operatorsrecognize and adjust to changingconditions during the course of a job.

Matrix Acidizing. With deeper andhotter wells being drilled today, wellstimulation requires new acidizingchemicals and procedures. This arti-cle describes new technologies forboth sandstone and carbonate stim-ulation that are effective at elevatedtemperatures. New fluid formula-tions also allow simpler fluid-place-ment techniques.

64 Oilfield Review

NEW BOOKS

Karst Hydrogeology and GeomorphologyDerek Ford and Paul WilliamsJohn Wiley & Sons, Inc.111 River StreetHoboken, New Jersey 07030 USA2007. 576 pages. US $185.00 hard-cover; US $60.00 paperback ISBN 0-470-84996-7

Originally published in 1989, this impor-tant work on karst studies has beensubstantially revised and updated. Thebook presents the dissolution kinetics,chemical equilibria and physical flowlaws relating to karst environments,and the influence of climate and climatic change on karst development.Also included is information on karstwater resource management and environmental management, includingenvironmental impact assessment, environmental rehabilitation, tourismimpacts and conservation. Throughoutthe text are practical applications ofkarst studies.

Contents:

• Introduction to Karst

• The Karst Rocks

• Dissolution: Chemical and KineticBehaviour of the Karst Rocks

• Distribution and Rate of Karst Denudation

• Karst Hydrology

• Analysis of Karst Drainage Systems

• Speleogenesis: The Development ofCave Systems

• Cave Interior Deposits

• Karst Landform Development inHumid Regions

• The Influence of Climate, ClimaticChange and Other EnvironmentalFactors on Karst Development

• Karst Water Resources Management

• Human Impacts and EnvironmentalRehabilitation

• Notes, Index

… the book is accompanied by adiverse set of online materials thatinstructors and researchers will finduseful, including maps, color versionsof many of the illustrations, and presen-tations by colleagues of the authors.

This book provides an excellentoverview of submarine seepage phenomena, and stimulates ongoingscientific discussions needed to under-stand these systems. We recommendSeabed Fluid Flow to scientists andother professionals, but certainly also to students specializing in fluid-flow-related topics.

Wegener G and Boetius A: Oceanography 20, no. 3

(September 2007): 60.

I found the book to have significantbreadth and detail, and believe it willbe of use to scientists in both academiaand industry.

Hutnak M: Geofluids 7, no. 4 (November 2007): 468.


08-OR-004-0


Autumn 2008

Subsalt Play

Circular Seismic Acquisition

Drilling Through Salt

HPHT Technologies

SCHLUMBERGER OILFIELD REVIEW

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Oilfield Review Autumn 2008