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SCHLUMBERGER OILFIELD REVIEW
SPRING 2000
VOLUME 12 N
UMBER 1
Spring 2000
Oilfield Review
Deepwater Solutions
Rotary Steerable Drilling
Controlling Produced Water
Perforating Design Practices
Shaped-charge perforating is based on developments fromthe weapons industry where the objective is to create holesin a target using penetrating projectiles that cause signifi-cant damage. This is not necessarily the objective when per-forating oil and gas wells. Ideally, perforating jets produceholes through steel casing and cement, which extend somedistance into the formation without impairing the ability ofa reservoir to produce hydrocarbons. However, even withtoday’s technology and advanced shaped charges, theseobjectives are mutually exclusive because perforating isknown to cause damage in reservoir rocks. Optimizing theperforating process while minimizing or removing perfora-tion damage is the focus of a great deal of industry effort.
Underbalanced perforating has evolved to become thepreferred method for mitigating perforating-induced perme-ability impairment. During the past several years, a consid-erable amount of research has been done on the impact ofunderbalanced perforating on well productivity, and also ondeveloping optimal underbalance criteria for specific reser-voir conditions. Shaped charges are also evolving. New linermaterials are under development to increase perforatingeffectiveness while minimizing the damage around perfora-tions. Because well performance is influenced by hole sizeand perforation length beyond near-wellbore formationdamage and fluid invasion, innovative designs have led toimproved deep-penetrating and big-hole charges that maxi-mize completion efficiency and productivity.
Well productivity is just one completion factor that isaffected by perforating practices. Other concerns for pro-duction engineers include well stimulation and sand pro-duction. The right perforating strategies ensure efficientand effective hydraulic fracturing or sand-control treat-ments. Likewise, by combining rock mechanics, sharedearth models and perforating technology, completions canbe optimized for formations that are prone to sanding.Perforation orientation and spacing, optimal underbalanceand selection of the best shaped charges coupled with mod-eling of in-situ stresses provide operators with cost-effectiveoptions for preventing sand production in weak or uncon-solidated formations. Advances in this area could ultimatelylead to screenless completions in wells that currentlyrequire conventional sand-exclusion methods such as gravelpacks or frac packing.
Shaped-charge performance is a critical element of perfo-ration design for any well. However, most, if not all, perforat-ing test data come from measurements in concrete targets atsurface conditions. Algorithms are available that attempt tocorrelate concrete test data with shaped-charge performancein reservoir rock, but these algorithms have proven unreli-able because shaped charges do not always perform as pre-dicted at downhole stress conditions. To better understand
Is Perforating a Mature Technology?
and optimize perforating strategies for a particular reservoir,it is important to test shaped charges at reservoir conditionsusing reservoir cores or outcrop-rock analogs.
Completion engineers routinely use computer programswith built-in algorithms for shaped-charge performance todesign and analyze perforating jobs. Engineers usuallyaccept the output results without fully considering thebasis and validity of these algorithms, which rely on manyassumptions and do not always provide well-specific perfo-rating solutions. Therefore, each engineer should recognizeand understand the shortcomings of these program algo-rithms as well as the potential technical and economicimpact on completion decisions. At the same time, it isimportant to continue addressing design-program and algo-rithm limitations by ongoing perforating research.
In spite of recent developments, much remains to beaccomplished in perforating. The physics of perforating isnot completely understood, and further research is neededto minimize adverse interactions between perforating jetsand formations. Improved perforating predictions, moreshaped-charge performance data under downhole condi-tions, standardized testing procedures, new shaped-chargedesigns and liner materials, and further development ofwell-specific perforating solutions, such as sand control andprevention methodologies, are all needed (see “PerforatingPractices That Optimize Productivity,” page 52). Based ontechnical advancements made during just the past five yearsand all the attention that perforating is currently receiving,it is obvious there is much more to learn about optimizationof the perforating process for well completions.
David UnderdownTechnical AdvisorChevron Production & Technology CompanyHouston, Texas, USA
David Underdown is a Technical Advisor at the Houston Drilling & TechnicalCenter. He is responsible for completion engineering, focusing on sand controland perforating. From 1984 to 1993, he worked for ARCO in Plano, Texas, as acompletion engineer dealing with sand control and formation damage issues.He spent the next two years as President of UNITEC Consulting Company inPlano. From 1995 to 1996, he worked as technical director for the Pall WellTechnology Division of the Pall Corporation in Port Washington, New York,responsible for providing technical support to the division. He joined Chevronin 1996. David earned a PhD degree in physical chemistry from the Universityof Houston. He was editor of SPE Monographs on Sand Control andCompletion Fluids. David is also a member of the SPE Awards Committeeand a technical editor for the SPE Drilling & Completions journal.
Advisory PanelTerry AdamsAzerbaijan International Operating Co., Baku
Syed A. AliChevron Petroleum Technology Co.Houston, Texas, USA
Antongiulio AlborghettiAgip S.p.AMilan, Italy
Svend Aage AndersenMaersk Oil and Gas ASCopenhagen, Denmark
Michael FetkovichPhillips Petroleum Co.Bartlesville, Oklahoma, USA
George KingBP Amoco CorporationHouston, Texas
David Patrick MurphyShell E&P CompanyHouston, Texas
Richard WoodhouseIndependent consultantSurrey, England
Executive EditorDenny O’BrienAdvisory EditorLisa StewartEditorsRussel C. HertzogGretchen M. GillisContributing EditorRana Rottenberg
Senior Production EditorMark E. Teel IllustrationTom McNeffMike MessingerGeorge StewartDavid FierroDesignHerring DesignPrintingWetmore Printing Company, USA
An asterisk (*) is used to denote a mark of Schlumberger.
Oilfield Review is published quarterly by Schlumberger to communicatetechnical advances in finding and producing hydrocarbons to oilfieldprofessionals. Oilfield Review is distributed by Schlumberger to itsemployees and clients.
Contributors listed with only geographic location are employees ofSchlumberger or its affiliates.
© 2000 Schlumberger. All rights reserved. No part of this publicationmay be reproduced, stored in a retrieval system or transmitted in anyform or by any means, electronic, mechanical, photocopying, recordingor otherwise without the prior written permission of the publisher.
Address editorial correspondence to:
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Annual subscriptions, including postage, are 160.00 US dollars, subject to exchange rate fluctuations.
Spring 2000Volume 12Number 1
Schlumberger
30 Water Control
As produced water increases or breaks through at the wrong place, it creates major problems in oil and gas operations. Excess water reduces productivity, increases corrosion and forces operators to expand water treatment and disposal systems. Through case studies we show how complex water problems are being diagnosed and monitored, so that proven solutions can be applied to reduce water production, decrease costs and improve hydrocarbon output.
2 Solving Deepwater Well-Construction Problems
Many new discoveries are highly productive fields in ultradeep water where the environment creates difficult well-construction conditions. We review the challenges of deepwater operations, including drilling in unconsolidated sediments, water-flow hazard identification, pore-pressure prediction, cementing and subsea flow boosting. Case studiesdemonstrate proven methods and new techniques that solve these problems and ensure cost-effective, safe and efficient operations.
75 Contributors
78 Coming in Oilfield Review and New Books
Oilfield Review
1
52 Perforating Practices That Optimize Productivity
A practical, objective-oriented design approach helps operators better apply deep-penetrating charges to bypass invasion, big-holecharges for fracture stimulation or sand-control gravel packing, and new methods that maximize perforation flow area and optimize shotspacing to prevent sanding. We review perforating physics, explosiveshaped charges, damage mitigation, design criteria, strategies and conveyance choices for high-performance perforated completions.
18 New Directions in Rotary Steerable Drilling
Rotary steerable drilling systems allow us to drill specialized well trajectories, including horizontal, extended-reach and other complex profiles, while avoiding the problems of sliding during conventional directional drilling. We explain how rotary steerablesystems work and through field examples demonstrate the increase in penetration rate and improvement in reliability that are obtained with the latest generation of these rotary steerable tools.
2 Oilfield Review
Solving Deepwater Well-Construction Problems
Gérard CuvillierStephen EdwardsGreg JohnsonDick PlumbColin SayersHouston, Texas, USA
Glen DenyerEEX CorporationHouston, Texas
José Eduardo MendonçaPetrobrasRio de Janeiro, Brazil
Bertrand TheuvenySandsli, Norway
Charlie ViseNew Orleans, Louisiana, USA
For help in preparation of this article, thanks to Alain Boitel,Pointe Noire, Republic of Congo; Alan Christie and AshleyKishino, Rosharon, Texas, USA; Gary Dunlap, Rio de Janeiro,Brazil; Frank Mitton and Robin Walker, Houston, Texas; LesNutt, Fuchinobe, Japan; James Nutter, Macae, Brazil; andDavid Viela, Luanda, Angola.AIT (Array Induction Imager Tool), CDR (Compensated Dual Resistivity), DeepCRETE, INFORM (Integrated Forward Modeling), ISONIC (IDEAL sonic-while-drilling tool), MDT (Modular Formation Dynamics Tester), PERFORM (Performance Through Risk Management) and RFT (Repeat Formation Tester) are marks of Schlumberger.
Deepwater wells are key to the oil industry’s future. Constructing
wells in water depths measured in miles and kilometers requires
new solutions and challenges the industry to perform at its best.
Spring 2000 3
Huge volumes of the world’s future oil reserveslie in deep waters at the very limit of our currentreach, and just beyond. By all indications, tomor-row we will be drilling even deeper. The rapidadvances in deepwater exploration and produc-tion (E&P) methods over the past five yearsensure that as soon as one deepwater record isbroken, another surpasses it.
Operators are drawn to the arena of deepwa-ter exploration by the promise of extensivereserves and high production rates that justify theextra expense and risk. Some deepwater fieldsweigh in above the 2 billion-barrel [320 million-m3]mark, and a single well can produce 50,000 bar-rels per day [8000 m3/d]. At the end of 1998, the28 fields producing from water depths of 500 m[1640 ft] or deeper delivered 935,000 B/D[150,000 m3]. Most of these fields are in the Gulfof Mexico and offshore Brazil, but even moredeepwater discoveries have been made or areexpected offshore West Africa, in the Far Eastand on the North Atlantic margin (near right).Analysts report that worldwide, an additional43.5 billion bbl [6.9 billion m3] have been discov-ered in water deeper than 500 m, with the potentialfor an additional 86.5 billion bbl [13.7 billion m3] (farright).1 Only about half of the deepwater acreageexpected to hold hydrocarbons has been explored.Some estimates suggest that 90% of the world’sundiscovered offshore hydrocarbon reserves hidein water depths greater than 1000 m [3280 ft].2
There are multiple definitions of “deep”water, which vary depending on the activitybeing considered. Generally, for well construc-tion, 1500 ft, or 500 m, is considered deep.Deeper than that, the technology requirementschange but solutions are available. And deeperthan 7000 ft, or about 2000 m, is ultradeepwater. Solutions, if available, are tailored toeach project. Government and regulatory agen-cies may adopt other definitions for deep, suchas beyond the break between continental shelfand continental slope, and confer royalty or tax-ation relief on fields that qualify.
Scientific drilling by groups such as the inter-nationally funded Ocean Drilling Program and itspredecessor, the Deep Sea Drilling Project, hasachieved the astounding water depth of 7044 m[23,111 ft]. However, research holes like this oneare drilled without many of the economic andoperational constraints imposed on the offshoreE&P industry.3
The current water depth record in drilling forhydrocarbons is held by a Petrobras well in 9111 ft[2780 m] of water offshore Brazil.4 The record wasbroken four times in 1999, as the depth increasedfrom 7718 to 9111 ft [2353 to 2780 m]—as manytimes as in the five preceding years, when it pro-gressed from 6592 to 7712 ft [2009 to 2351 m].
The greatest challenges in constructing wellsin deep water are related somewhat to the greatdepths, but also to the conditions encountered ineach deepwater oil province. In the deepestwaters, drilling can be accomplished only fromdynamically positioned semisubmersible rigs ordrillships. Conventionally moored drilling rigshave drilled as deep as 6023 ft [1836 m] in theGulf of Mexico. Conditions offshore West Africacan be substantially different from thoseencountered in the Gulf of Mexico, where thepresence of subsea currents makes drilling-risermanagement more critical. More powerful andlarger rigs are required to maintain station under
1998 1999 2000 2001 2002
28
40
54
78
96
Year
Act
ual a
nd fo
reca
st n
umbe
r of d
eepw
ater
pro
duci
ng fi
elds
by
regi
on
0
100
25
50
75US GulfBrazilWest AfricaFar EastOther regions
> Recent production and the forecast for deepwater fields.(Adapted from Thomas, reference 1.)
1. Thomas M: “Into the Ultradeep,” Deepwater Technology,Supplement to Petroleum Engineer International 72, no. 5(May 1999): 1-3, 5, 7.Moritis G: “Options to Produce Deepwater Oil, Gas to Proliferate,” Oil & Gas Journal 97, no. 50 (December 13, 1999): 69-72.
2. Moritis, reference 1.3. Scientific wells can be drilled without blowout preventers
(BOPs) or drilling risers for mud return, and are not cased or completed. Their aim is to produce information,not hydrocarbons, and, in fact, if hydrocarbons or overpressure are detected, drilling is terminated.
4. DeLuca M: “International Focus,” Offshore 60, no. 1 (January 2000): 10.
0
Disc
over
ed a
nd e
stim
ated
pot
entia
l dee
pwat
er re
serv
es w
orld
wid
e,bi
llion
s of
bar
rels
of o
il eq
uiva
lent
75
50
25
150
100
125
USGulf
SouthAmerica
WestAfrica
FarEast
Antarcticadeepwater
basins
Other
Total
DiscoveredPotential
> Billions of barrels of discoveredand potential deepwater reserves.(Adapted from Thomas, reference 1.)
high currents and to carry the extra mud volumeand marine riser needed to construct the well. Inaddition, the extreme water depth may also sig-nificantly impact rig downtime. For example, if arig’s subsea blowout preventer (BOP) malfunc-tions, it can take three days just to retrieve it tosurface for repair.
The primary challenge facing deepwater wellconstruction is to drill a stable hole. In youngsedimentary basins with rapid rates of deposi-tion, such as the Gulf of Mexico and parts of off-shore Brazil and West Africa, sediments canbecome undercompacted during burial. Porepressures can be high and fracture gradients lowcompared with those in land wells at the samedepth, and the window between pore-pressureand fracture gradient can be narrow. Safe well-design and control practice requires advanceknowledge of pore-pressure and fracture gradi-ent. Drilling a hydraulically stable hole can beachieved only by keeping drilling mud weightwithin the margin between fracture and pore-pressure gradient. In some projects, so manystrings of casing are needed to control shallowunconsolidated sediments as well as deeperpressure-transition zones that the reservoir can-not be reached. Or, if it is reached, the diameterof tubing that will fit through the final casing isso small as to render the project uneconomicalbecause of restricted flow rates.
In areas such as the Gulf of Mexico, shallowflow hazards make well construction difficult.These zones below the seabed are capable of flowing water and, when encountered by adrill bit, cause severe borehole stability prob-lems. Water-flow zones also impede logging andreentry in open hole and the setting of cementbehind casing.
In the deepest waters, today’s wells are com-pleted with wellheads and production trees onthe seafloor that connect to flowlines for trans-porting hydrocarbons to surface. The surfacestructures may be floating production, storageand offloading (FPSO) vessels or nearby hostplatforms. Controlling live subsea wells for test-ing, completion and intervention requires spe-cially designed, reliable equipment.5 Fluids oftenmust flow through miles of lines and sometimesrely on submersible pumps or other artificial-lifttechniques in order to reach the surface.6 Thewells may be made more productive by implant-ing permanent monitoring and flow-controldevices downhole.7
Keeping fluids flowing at the highest possi-ble rates requires not only adequate tubing size,but also attention to conditions that can lead toother flow blockages. At the high pressures andlow temperatures that deepwater wellsencounter near the seabed, solid, ice-like com-pounds called gas hydrates can form from mix-
tures of water and natural gas. These solids canblock flow in tubulars, and depressurize explo-sively when brought to surface. They have beenresponsible for offshore drilling catastrophes inthe past. Hydrates can also form naturally at andbelow the seabed, creating a drilling hazard ifpenetrated. Other solids such as paraffins mustalso be prevented from blocking flowlines.
To ensure cost-effective, safe and efficientoperations in deep waters, the industry mustdevelop solutions to these and many other prob-lems. In some cases, the solution will be a newtool or completely new technique; in others, aninnovative application of existing technology willprovide the answer. In this article, we describesome of the newly proven methods and promis-ing directions that will permit the continuedexpansion of E&P activities into deeper waters.
Deepwater ExcellenceThe kinds of advances required to break the barri-ers imposed by the great oceans are not of thesort that can be achieved single-handedly, by anindividual or even by a single company. Oil com-panies, service companies, drilling contractors,academic institutions, government groups andequipment manufacturers are all working towardsolutions. Some oil companies are setting up theirown specialized global deepwater drilling groupsto oversee drilling at the deepwater asset level.Many operators and contractors are participating
4 Oilfield Review
Well Construction
Drilling optimization
Riser technology
Alternative vessels
Drilling fluids
Directional drilling
Cementing technology
Geologyand Geophysics
Seismic(marine, borehole)
Ultradeep formationevaluation
Geotechnicalshallow hazards
Reservoir optimization
Alliances R&D CentersOther Centers of Excellence Product Engineering CentersSubsea Engineering
Productionand Intervention
Application of coiled tubing
Subsea tree systems
Directional drilling
Cementing technology•Production systems•Intervention systems•Intervention vessels
Full field development
Floating production systems
Flow assurance
Completion Systems
Completion technologies
Sand-control systems
Perforating
Well testing
Intelligent systems
Zonal isolation
Production equipment
Deepwater Center of Excellence
> Deepwater Center of Excellence organization. The center works to identify technology gaps, prioritize needs and facilitatethe development of solutions to deepwater problems. Four technical domains link with other elements of the Schlumbergerorganization to transfer knowledge.
Spring 2000 5
in industry consortia, initiatives and joint industryprojects to identify technology gaps and pool theirknowledge and resources. Examples of these arethe Deepstar consortium led by Texaco in the US,PROCAP by Petrobras in Brazil, the Atlantic Mar-gin Joint Industry Group (AMJIG) in the UK andthe Norwegian Deepwater Programme.
To address the demand for current and futuredeepwater technical solutions, Schlumberger hasformed the Deepwater Center of Excellence, asolutions center led by experts in Houston, Texas,USA. The center’s mission is to achieve a globalcooperative effort with the industry, focused onidentifying and developing cost-effective, best-in-class solutions to meet deepwater challenges.
The Deepwater Center of Excellence hasdefined specific methods for meeting these objec-tives. First, the organization must recognize exist-ing successful deepwater applications within allthe company’s groups, prioritize needs for newtechnology and propose technical solutions to theengineering centers and clients. Second, internaland external networks have to be established totransfer knowledge and learning. Experts in theDeepwater Center of Excellence manage and fos-ter the development of solutions in one of fourspecific technical domains—well construction,completion systems, production and intervention,and geology and geophysics (previous page).These are aligned with critical well processes andwith current oil-company structures. Finally, thecenter also acts as the Schlumberger representa-tive in deepwater-related joint industry projects tohelp put the acquired knowledge into practice.
Several joint industry projects (JIPs) have beenformed in attempts to overcome a wide range ofdeepwater E&P obstacles. Some projects havebeen established to investigate ways to reducecosts or operate with less impact on the environ-ment, while others are designed to enable activi-ties in deeper water—without them, industry willnot develop the reserves found in ultradeep water.
Drilling Joint Industry ProjectsOne such JIP is a project to design a new methodfor drilling and constructing deepwater wells witha minimum number casing strings so that deepgeological objectives can be reached with a holesize that allows hydrocarbons to be produced athigh flow rates. In the Gulf of Mexico and basinsoffshore West Africa, high depositional ratescause sediments to accumulate rapidly and reachconsiderable depths without compacting, or giv-ing up their pore water. In these weak, unconsoli-dated formations, pore pressures are high andformation fluids must be kept at bay by heavydrilling mud. However, fracture pressures are low;the great distance from the rig to the formationcreates an unbearably heavy column of mud inthe drillstring and riser, and the weight of the mudfractures the formation unless casing is set. Sev-eral casing strings are set in these upper portions
of the well, reducing the number of contingencystrings left available for deeper difficulties, suchas lost-circulation zones, overpressured forma-tions and other well-control incidents. A deepwa-ter well in this kind of formation might cost morethan $50 million and still not reach its objective.
In 1996, 22 companies joined a JIP aimed atremoving the effect of water depth from deep-water well planning and drilling. The group deter-mined that the most viable solution involvedreducing the weight of the mud on the formationby changing the way mud returns to surface (above). The Subsea Mudlift Drilling JIP, nowmade up of representatives from Conoco, Chevron,Texaco, BP Amoco, Diamond Offshore, GlobalMarine, Schlumberger and Hydril, is developingthis technology and remains on track to deliver itto the industry in 2002.
Conventional
Marine riser
Drillpipe
Mud in riserand drillpipe
Sing
le p
ress
ure
grad
ient
Subsea Mudlift
Marine riser
Mud indrillpipe
Drillpipe
Seawaterin riser
Mud returnto surface
Pres
sure
gra
dien
t 1Pr
essu
re g
radi
ent 2 Casing
depths
Casingdepths
> Conventional (left) and subsea mudlift (right) deepwater drilling technology. In conventional drilling,the weight of the mud column in the riser often is too high to drill without fracturing weak formations.Subsea mudlift technology isolates mud and pumps it back to surface outside the riser to lessen theload, allowing drilling to proceed without fracturing.
5. Christie A, Kishino A, Cromb J, Hensley J, Kent E,McBeath B, Stewart H, Vidal A and Koot L: “Subsea Solu-tions,” Oilfield Review 11, no. 4 (Winter 1999/2000): 2-19.
6. Fleshman R, Harryson and Lekic O: “Artificial Lift for High-Volume Production,” Oilfield Review 11, no. 1 (Spring 1999): 48-63.
7. Algeroy J, Morris AJ, Stracke M, Auzerais F, Bryant I,Raghuraman B, Rathnasingham R, Davies J, Gai H,Johannessen O, Malde O, Toekje J and Newberry P:“Controlling Reservoirs from Afar,” Oilfield Review 11, no. 3 (Autumn 1999): 18-29.Eck J, Ewherido U, Mohammed J, Ogunlowo R, Ford J, Fry L, Hiron S, Osugo L, Simonian S, Oyewole T andVeneruso T: “Downhole Monitoring: The Story So Far,”Oilfield Review 11, no. 4 (Winter 1999/2000): 20-33.
In conventional drilling, the mud columnextends from the rig to the bottom of the well,forming a single mud-pressure gradient (left).The effect of lowering the load in the riser is toreplace the single pressure gradient with a dual-gradient system: a hydrostatic pressure gradientacts from the rig to the seabed, sometimescalled the mudline; a new, higher, mud-pressuregradient acts from the mudline to the bottom ofthe hole. In the dual-gradient system, the pore-,fracture- and mud-pressure gradients becomereferenced to the mudline instead of to the rig(below left).
The decrease in wellbore mud pressure cansave as many as four casing strings in the welldesign (next page, top). The dual-gradient tech-nology allows any well, regardless of waterdepth, to reach its reservoir target with a 121⁄4-in.hole size. The large-bore wells made possible bysubsea mudlift drilling will be able to run 7-in.tubing to the mudline, letting many wells achievetheir highest flow-rate potential. Alternatively,this larger hole size will allow for horizontals ormultilaterals necessary to optimize reservoirdrainage. As a consequence, fewer wells willneed to be drilled to adequately drain a reservoir,resulting in considerable reduction of field devel-opment capital expenditure and greater ultimaterecovery. The lower mud pressure also results infewer well kicks and lost-circulation problems.The JIP estimates these benefits can lead to savings of $5 million to $15 million per well.
There are several ways to reduce the weightof the mud in the drilling riser. The SubseaMudlift Drilling JIP is developing a system withtwo main components. First, a subsea rotatingdiverter isolates the fluid in the riser from thewellbore and diverts the return drilling fluid fromthe base of the riser to the second key compo-nent, a mudlift pump. The mudlift pump directsthe mud back up to the rig in a flowline isolatedfrom the riser and keeps the hydrostatic pres-sure of the mud in the return line from beingtransmitted back to the wellbore.
The system design and preliminary field test-ing will take place in the year 2000 and early2001, and full-scale deepwater tests will follow.The commercial system will be built in 2001 andtested in 2002, opening the way for drilling inhundreds of deepwater leases.
6 Oilfield Review
Dept
h
Pressure
Seawaterhydrostatic
pressure
Conventionalmud hydrostaticpressure
Fracturepressure
Porepressure
Casingdepths
<Single-gradient conventional drilling, requiring manycasing strings. When the margin between pore pressureand fracture pressure is narrow, conventional drilling,with its pressure gradient referenced to the rig, requiresfrequent mud-weight increases, accompanied by casingstrings to avoid fracturing.
Dept
h
Pressure
Seawaterhydrostatic
pressurePore
pressure
Fracturepressure
Dual-gradientmud hydrostaticpressure
Casingdepths
<Dual-gradient drilling for fewer casing strings. Becausethe pore-, fracture- and mud-pressure gradients are refer-enced to the mudline rather than the rig, dual-gradientdrilling permits successful well construction with fewercasing strings even when the margin between pore andfracture pressure is slim.
8. Furlow W: “Shell Moves Forward with Dual GradientDeepwater Drilling Solution,” Offshore 60, no. 3 (March 2000): 54, 96.
9. For selected references on pore-pressure estimation: Bowers GL: “Pore Pressure Estimation from VelocityData: Accounting for Pore-Pressure MechanismsBesides Undercompaction,” SPE Drilling and Completion10, no. 2 (June 1995): 89-95.Dutta NC: “Pressure Prediction from Seismic Data: Implication for Seal Distribution and Hydrocarbon Exploration and Exploitation in Deepwater Gulf of Mexico,” in Moller-Pedersen P and Koestler AG (eds):Hydrocarbon Seals: Importance for Exploration and Production, NPF Special Publication, no. 7. Singapore:Elsevier Science, 1997.
Eaton BA: “The Equation for Geopressure Predictionfrom Well Logs,” paper SPE 5544, presented at the SPE Annual Fall Meeting, Dallas, Texas, USA, September 28-October 1, 1975.Hottman CE and Johnson RK: “Estimation of FormationPressures from Log-Derived Shale Properties,” Journal of Petroleum Technology 16, no. 6 (June 1965): 717-722.Pennebaker ES: “Seismic Data Indicate Depth, Magnitude of Abnormal Pressures,” World Oil 166, no. 7 (June 1968): 73-78.
10. Armstrong P and Nutt L: “Drilling Optimization Using Drill-Bit Seismic in the Deepwater Gulf of Mexico,” paper IADC/SPE 59222, presented at the IADC/SPEDrilling Conference, New Orleans, Louisiana, USA,February 23-25, 2000.
Spring 2000 7
Other JIPs are looking into solving the sameproblem in different ways. Since 1996, ShellE&P has been funding and developing a subseapumping system that accomplishes dual-gradient drilling with existing technology wherepossible.8 Several companies, including FMCKongsberg, Alcatel, Centrilift, Dril-Quip and Robicon have participated in the project, whichinvolves subsea separation of larger cuttings sothat electrical submersible pumps can be usedto return mud to surface. Cuttings are left on the seafloor.
Predicting PressuresIn typical sedimentary basins, formations compactas they are buried. Pore fluids are expelled, sedi-ments compact to form consolidated rocks, andpore pressure increases hydrostatically withdepth. In basins with high rates of deposition,such as the Gulf of Mexico, excess fluids can betrapped in low-permeability sediments as theycontinue to be buried. These formations becomeundercompacted and develop overpressure, or
pore pressure greater than hydrostatic. In over-pressured zones, the rock porosity, or some logmeasurement sensitive to porosity, such as sonictraveltime or resistivity, deviates from the normalcompaction trend. These overpressured zones canbe hazardous during drilling. They can cause kicksif they are not detected and require additional cas-ing strings to keep the mud weight within the win-dow between pore pressure and fracture gradient.
Accurate knowledge of pore pressures is akey requirement for safe and economic deep-water well construction. Before drilling, porepressure can be estimated from other properties,such as local seismic velocities, drilling experi-ence, mud weights, and sonic and resistivitymeasurements in nearby wells.9 The worth ofthe pore-pressure prediction depends on thequality of the input data, suitability of themethod used to compute pore pressure and oncalibration with measured pressures. Althoughnot routinely done, the pore-pressure model canbe enhanced by updating it with local calibrationdata from drilling observations, while-drillinglogs and look-ahead vertical seismic profilesusing either surface sources or the drill bit as asource (below).10
> Fewer casing strings and greater bottomhole completion diameter using the dual-gradient method. The lower number of casing strings in dual-gradient deepwaterdrilling (right) compared with conventional drilling (left) saves money and results inlarger diameter tubing at bottom for greater productivity.
Load Project DataSeismic dataOffset well logsOffset well drilling data
Calibration DataMud weightsKicks, lossesRFT, MDT pressures
Pore-Pressure PredictionPore-pressure profile
Inputs to Well PlanCasing seatsMud weightRisksNew data requirements
Revised Well Plan
Stress ModelFracture gradient
Log Data ProcessingPreprocess editingMechanical stratigraphyOverburden stressVp, resistivity profileTime-depth relationship
Seismic ProcessingInterval velocity profile
Real-Time LogsCheck-shot surveyISONIC, gamma ray,pressure whiledrilling data
>Pore-pressure predictionworkflow. Seismic data, pressures and logs help engineers develop an initialpore-pressure prediction andstress model, which in turn helps fine-tune the well plan.Real-time information acquiredwhile drilling can update thewell plan.
Conventional Dual-Gradient
26
9 5/8
3626
20
133/8
36
20
16
13 3/8
113/4
7 5/8
9 5/8
51/2-in.tubing
7-in.tubing
Casing size, in. Casing size, in.
This approach was the key to success in arecent deepwater Gulf of Mexico three-welldrilling project for EEX Corporation. The first wellwas spudded using a preliminary pore-pressureprediction that required updating during thedrilling process. The prediction was updated andcalibrated with kick information.
In the second well, the new pore-pressureprediction technique was applied. Sonic andresistivity logs, mud weights and drilling experi-ence in an offset well helped create the prelimi-nary pore-pressure model. The new well waspredicted to encounter the same geology as the offset well but would not approach the salt that the offset well encountered near 6500 ft [1980 m] until much deeper.
A normal compaction trend appears in theoffset-well sonic logging data down to about8000 ft [2440 m], where a zone of higher thannormal pressure is penetrated (below). The porepressure predicted from the sonic data can becalibrated by actual pressures measured during the drilling process—a kick occurred at5000 ft [1520 m] where pore pressure surpasseddrilling mud weight. After that, drilling proceeded
overbalanced, with mud that was heavier thannecessary. A similar pore-pressure prediction wasmade from resistivity data.
A danger in applying these pore-pressurepredictions in regions of active salt tectonism isthat the measurements made at the offset-welllocation may not be representative of the geol-ogy traversed by the new well, especiallydeeper, in salt-prone sections. The only informa-tion type common to the two sites is intervalvelocity derived from processing the surfaceseismic line that ties the two wells. Seismicinterval velocities produce a much lower resolu-tion pore-pressure prediction, but still serve todefine both a normal compaction trend and apredicted pressure trend to support the predic-tions from other measurements.
The seismic interval velocities over the newwell location, combined with the log-derivedpredictions from the offset well, help constructthe final predrill pore-pressure prediction (nextpage, top). The seismic-derived pore pressuresindicate a narrowing safe mud-weight windowwith depth—less than 2 lbm/gal [0.24 g/cm3] atthe target depth of 20,000 ft [6100 m].
In all three wells, the pore pressures obtainedusing the Schlumberger calibration method accu-rately predicted the pore pressures encounteredin the well. Each well was drilled with the ser-vices of a Schlumberger PERFORM (PerformanceThrough Risk Management) engineer, who moni-tored the drilling process with while-drilling mea-surements and helped update the well plan.11
Refining Predrill Pressure PredictionsAs the previous example shows, offset-well datacan produce a high-resolution pore-pressure pre-diction. However, the prediction may not hold inthe vicinity of the new well. Adding the pore-pressure information from seismic interval veloci-ties provides areal coverage, but interval velocitieshave several drawbacks. They are not of highenough resolution to produce pore-pressure predictions adequate for well-planning purposes.They also are not physical traveltime velocities,but rather are derived from stacking velocities—by-products of seismic data processing that hap-pen to have the units of distance divided by time.They can correspond to actual seismic velocities
8 Oilfield Review
2200
4400
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0 20Pore pressure, sonic
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> Input data from offset well and corresponding pore-pressure predictions. Sonic data, resistivity measurements and seismic velocities eachshow normal compaction trends at shallow levels but deviate deeper. All three data types lead to comparable pore-pressure predictions that arecalibrated by actual pressures encountered when mud weights are insufficient to prevent kicks (black diamond in track 4).
Spring 2000 9
when the subsurface comprises flat homoge-neous layers. However, each velocity value repre-sents an average over the spatial extent of theseismic source and receivers used—often up to8 km [5 miles] in deep water. And interval veloci-ties are not representative of true subsurfacevelocities in the cases of dipping layers, lateralvariations in velocity or pressure, or changes inlayer thickness, exactly the circumstances inwhich one would not be able to rely on offset-well log data and would hope to use seismicdata for pore-pressure prediction.
Schlumberger geophysicists have devised away to extract physically meaningful velocitiesfrom 3D seismic data to derive an enhanced-resolution predrill pore-pressure prediction.12
The technique, called tomographic inversion, incorporates an automated process that usesall the traveltime patterns in the recorded seis-mic data to produce a laterally varying velocitymodel and so an improved pore-pressure pre-diction (below).
11. Aldred W, Plumb D, Bradford I, Cook J, Gholkar V,Cousins L, Minton R, Fuller J, Goraya S and Tucker D:“Managing Drilling Risk,” Oilfield Review 11, no. 2 (Summer 1999): 2-19.
12. Sayers CM, Johnson GM and Denyer G: “Predrill Pore Pressure Prediction Using Seismic Data,” paperIADC/SPE 59122, presented at the IADC/SPE Drilling Conference, New Orleans, Louisiana, USA, February 23-25, 2000.
Normal compaction trend
4000
Dept
h, ft
0
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20,000
16,000
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5000 30,000
Seismic interval velocitieslbm/galft/sec
> Normal trend observed in seismic interval velocities (track 1) and finalpredrill pore-pressure predictions (track 2) for the new well location.
<A conventional pore-pressure prediction basedon stacking velocities (left) compared with onebased on tomographic inversion (right). The initialprediction has lower resolution, a lower range ofpore pressures and is laterally smoothed. Therefined prediction shows detail that correspondsto subsurface geology accurately.
Conventional Pore-Pressure Prediction
Dept
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m
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e, lb
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Tomography-Based Pore-Pressure Prediction
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16
The method has been tested on a deepwaterwell project for EEX in the Gulf of Mexico. Anexisting 2D marine seismic survey was repro-cessed using tomographic inversion to generatea refined velocity model for transformation topore pressure (left). The resulting velocity modelhas sufficient detail to derive an accurate pore-pressure prediction away from the offset well tothe south. A drilling trajectory between the twosalt bodies imaged in the seismic line couldencounter a predicted low-velocity zone, whichmay indicate the presence of overpressure. Thespatial extent of this anomaly is not well-definedby the stacking-velocity image. However, theimproved resolution in the tomography-basedvelocities allows a more reliable predrill pore-pressure estimate to be made (next page, top).
10 Oilfield Review
Interval Velocities from Stacking
Velo
city
, m/s
ec
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2000
2500
3000
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> Velocity models over existing wells and proposed well location. Interval velocities derived fromstacking velocities (top) do not appear to correspond to the geological interpretation of the seismicline. The interpretation is drawn in fine lines on the image. The refined velocity model constructedusing tomographic inversion (bottom) corresponds to subsurface salt features interpreted in seismicsection and contains enough detail to produce an accurate pore-pressure prediction.
Interval Velocities from Tomography
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Overpressurepredictions
> Pore pressures predicted in the vicinityof the proposed well location and thelow-velocity zone indicated in the seismicvelocity model. The prediction shows anincrease in pressure at about 7600 ft[2320 m].
Spring 2000 11
The proposed well location is in the vicinityof the low-velocity zone, and the pore-pressureprediction shows a corresponding jump in pres-sure at about 7600 ft [2320 m] (previous page,right). The predicted pore pressures are in goodagreement with the actual mud weights subse-quently used to drill the well.
Deepwater Drilling SolutionsA variety of other problems can hinder the well-construction process in deep water. The followingexamples illustrate some of the latest solutions.
Wellbore stability—Cooling of the drillingfluid in the riser can cause higher mud viscosity,increased gel strength and high frictional pres-sure losses. These factors increase the likeli-hood of lost-circulation problems, and drillingengineers must take appropriate steps to avoidexceeding formation fracture pressures. Real-time measurement of annular pressure whiledrilling helps monitor the equivalent circulatingdensity (ECD) of mud to allow drillers to keepwithin the narrow stability window found inmany deepwater holes. Equivalent circulatingdensity is the effective mud weight at a givendepth created by the combined hydrostatic anddynamic pressures.
Real-time monitoring of annular pressurewhile drilling helped during construction of adeepwater well in the Gulf of Mexico (below).13
Mud weight was just below the pore pressurepredicted from seismic interval velocities whena kick occurred in Zone A. Mud weight wasincreased to control the well and 133⁄8-in. casingwas set. The next two hole sections were drilledwithout incident, then another kick was taken inZone B, so 9 5⁄8-in. casing was set to permitanother increase in mud weight. The heaviermud exceeded overburden pressure and somelost circulation was experienced in Zone C, butdrilling continued successfully thereafter.
Dept
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Overburden gradient, lbm/gal
Resistivity pore pressure estimate, lbm/gal
ECD, lbm/gal
Seismic pore pressure estimate, lbm/gal 1710
> Real-time annular pressure while drilling measurements indicating when effective circulating density (ECD) begins to fall outside the margin between pore pressure and fracture pressure. When ECD is too low, pore pressure causes kicks. Increasing mud weight may control the well, but if the margin between pore and fracture pressure is narrow, casing must be set to accommodate the heavier mud.
13. Aldred W, Cook J, Bern P, Carpenter B, Hutchinson M,Lovell J, Rezmer-Cooper I and Leder PC: “Using Down-hole Annular Pressure Measurements to Improve DrillingPerformance,” Oilfield Review 10, no. 4 (Winter 1998): 40-55.
> Two-dimensional predrill pore-pressure predictiondeveloped from a tomography-based velocity model.
Water-flow zones—Since 1987, operatorshave reported hazardous water flows in 60 Gulfof Mexico lease blocks involving 45 oil and gasfields.14 These abnormally pressured formationsare usually sands caught in quickly slumping androtating fault blocks or in reworked channelssealed by impermeable clay. Water flows havebeen reported between 800 and 5500 ft [244 to1680 m] depth below the seafloor. A flow maycontain gas and may develop solid gas hydratesin and near seabed equipment. Uncontrolledwater flow can lead to formation cave-in, and ifinflux is severe enough, the well can be lost.Washouts can undermine the large casing, orconductor pipe, that is the main support struc-ture for the well.
The industry spends an average of $1.6 mil-lion per deepwater well for the prevention orcorrection of problems associated with shallowflows.15 A combination of techniques is used tocombat the problem, including acquiring mea-surements while drilling, setting extra casing,drilling pilot holes, using a riser and pumpingspecial cements. The while-drilling measure-ments—by far the least expensive of thesteps—are designed to identify water-flowzones as soon as they are encountered.
Operators have started to use real-timeannular pressure measurements to detect water-flow zones. An example comes from deepwaterGulf of Mexico, where a water-flow zone wasidentified on gamma ray, resistivity and annularpressure while drilling logs (right).16 The jump inequivalent circulating density indicated possibleinflux of solids. Visual confirmation of water flowwas confirmed by remotely operated video at theseafloor. Mud weight was increased to controlthe flow, and drilling continued. Similar flowzones were detected within the next few hun-dred meters. All the water-flow zones weresafely contained. Early warning of water influxprovided by the real-time measurements made itpossible to keep on drilling to the planned depth.
Deepwater cementing—Water flows alsopresent problems during cementing operations.Water influx can keep cement from solidifying,jeopardizing the integrity of the well. A deep-water consortium including Schlumberger andseveral oil companies sought to formulate acement for deepwater wells that would be able
to hold up against water flows but also be lightenough not to fracture weak formations. The keywas to find a cement with a short transitiontime—the period when it changes from a liquidto a solid—to minimize the interval during whichits strength is too low to hold back water flow.
A foamed deepwater right-angle set (RAS)slurry was the solution. The deepwater RAS hasthe requisite short transition time and early com-pressive strength and thus prevents any waterflow from penetrating the cement bond. As afoam, the cement density can be modified withnitrogen injection during mixing to create aslurry that is light enough to avoid fracturingweak deepwater formations.
The deepwater RAS cement has helped stopwater flow and provided successful cement jobsin more than 50 deepwater wells, even atrecord-breaking depths. This includes cementingthe conductor and surface strings for theChevron Atwater 18 #1 well in 7718 ft [2352 m]of water in the Gulf of Mexico.
Foamed cement requires a nitrogen supply, spe-cialized equipment for injecting it, and a cementingteam trained in its use—all of which may be challenging to coordinate on a deepwater rig.
12 Oilfield Review
Dept
h, m
Attenuation resistivityGamma ray0
A
150 0 10 8 9
500 0 0 10 2000 3000
0 2 50 100
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> Detecting water-flow zones in deepwater wells with annular pressure while drillingmeasurements. Three water-flow zones A, B and D (light blue highlight) were identifiedwith the help of the while-drilling data. In each case, increasing the mud weight successfully controlled the flow, and drilling continued to total depth.
Conventionalcement 68
DeepCRETEcement 11
0 25 50 75
Setting time, hr
Spring 2000 13
An alternative to foamed cement, DeepCRETEtechnology, has been developed for such deep-water wells. DeepCRETE cement strengthensquickly even at temperatures as low as 4°C[39°F], reducing waiting-on-cement times.17
Operators offshore Angola, Africa report signif-icant savings with DeepCRETE cement for wellconstruction in deepwater areas, where the low-temperature environment causes long settingtimes and ordinary cements suffer from losses dueto the low fracture gradient. In one case, using aconventional cement in a well with a bottomholecirculating temperature of 12°C [54°F], the 15.8-lbm/gal [1.89-g/cm3] slurry exceeded the fracturegradient at the seabed. It took 68 hours to achievethe first 500-psi [3.4-MPa] setting. In the secondcase, with DeepCRETE cement, a 12.5-lbm/gal[1.5-g/cm3] slurry set in 11 hours with no evidenceof cement loss to fracturing (right). The 57-hourreduction in rig time translated to savings of$475,000.
Reservoir evaluation—Difficulties in deep-water well construction manifest themselvesagain later as challenges in formation evalua-tion. Low fracture gradients and water-flowzones cause washouts and inadequate cement-ing, leading in turn to adverse hole conditionsfor logging. Logging-while-drilling (LWD) mea-surements help obtain formation-evaluationinformation before hole conditions deteriorate.This technique has been successful in therapidly growing market offshore Angola, wheredeepwater production is projected to reach 1.38million B/D [219,000 m3/d] by the year 2005 (right).18 In a well drilled in 1200-m [3940-ft]
14. Minerals Management Services, US Department of Interior. http://www.mms.gov. andhttp://www.gomr.mms.gov/homepg/offshore/safety/wtrflow.html
15. Alberty M: “Cost Analysis of SWF Preventative, Remedial Measures in Deepwater Drilling,” Offshore 60,no. 1 (January 2000): 58, 60, 62, 64.
16. Aldred et al, reference 13.17. Boisnault JM, Guillot D, Bourahla B, Tirlia T, Dahl T,
Holmes C, Raiturkar AM, Maroy P, Moffett C, Mejia GP,Martinez IR, Revil P and Roemer R: “Concrete Develop-ments in Cement Technology,” Oilfield Review 11, no. 1(Spring 1999): 16-29.
18. “Kuito Kicks off for Angola,” Offshore Engineer 24, no. 10(October 1999): 26-28.
> Faster setting DeepCRETE cement for controlling water flow and savingrig time. In this deepwater offshore Africa example, a conventionalcement system exceeded the fracture gradient at the seabed and took68 hours to set. The DeepCRETE cement, a less dense slurry, set in 11hours with no fracturing.
ANGOLA
ZAIRE
CONGO
GABON
NAMIBIA
EQUATORIALGUINEA
CAMEROON
AFRICA
> Offshore Angola, where production from deepwater wells is estimated togrow to 1.38 million B/D in five years.
deep water offshore Angola, CDR CompensatedDual Resistivity tool measurements were madeto determine casing and coring points (left).After drilling several hundred meters into thereservoir with oil-base mud (OBM), substantialmud losses were incurred. These were believedto originate at the bottom of the hole. WirelineAIT Array Induction Imager Tool measurementsrun seven days later, after mud losses totaled300 m3, showed a completely different logresponse between about X050 and X130 m com-pared with the earlier CDR results. Increasedvalues of wireline resistivity indicated the shalesection had been altered and possibly fracturedby the OBM.
Similar cases often have been documentedin the past, but less common with OBM is thereversal observed in the order of the AIT curves.Here, the deeper reading AIT resistivities exhibithigher values than the near-reading ones. Tounderstand these results, Schlumberger engi-neers modeled the formation, fracture and mea-surements using INFORM forward modelingsoftware. Different fracture openings and rela-tive angles of intersection with the boreholewere tested to find the conditions under whichthe observed reversal of the AIT curves wouldoccur (next page, top). The INFORM modelingshowed that a fracture dipping at 75° can repro-duce the order of the AIT readings.
Constructing Productive WellsAchieving optimal hydrocarbon production fromdeepwater wells requires special attention to flowassurance. Assuring flow is a multidisciplinaryeffort, covering issues from asphaltene depositionand hydrate formation to hydrocarbon flow proper-ties and flowline reliability. Any potential problemthat could hinder flow from the reservoir to theproduction export vessel or pipeline falls under theheading of flow assurance.
Offshore Brazil and elsewhere, deepwaterdevelopment layouts have been constrained byreservoir pressures. Reservoir pressure controlledthe distance that could be tolerated between welland platform without critical flow loss. Pressuredecline could be combated by water injection, orbackpressure could be reduced by gas lift. How-ever, gas-lift efficiency suffers in wells with thelong horizontal tie-backs typical of subsea com-pletions. Sustaining oil production from thesedeepwater subsea wells requires new solutionsto increase flow rates, simplify production facilitylayouts, decrease the number of platforms and
14 Oilfield Review
CDR-attenuation
CDR-phase shift
AIT 10
AIT 30
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Gamma Ray0 150API 0.2 2000ohm-m
Dept
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X100
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> Comparison between while-drilling logs from the CDR Compensated Dual Resistivity tool and wirelinelogs from the AIT Array Induction Imager Tool series. The AIT curves acquired after significant mudloss exhibit indications of alteration and fracturing between X050 and X130 m. However, the order ofthe curves, with deeper reading measurements seeing higher resistivity, seemed unusual for invasionby oil-base mud.
SOUTH
AMERICA
AlbacoraAlbacora East
Roncador
Marlim
Marlim South
Campos
Campos
Vermelho
PargoCarapeba
100 m
400 m
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B R A Z I L
> Offshore Brazil, the site of the deepwater subsea electrical submersible pump test.
Spring 2000 15
reduce investments and operating costs. Severalsolutions are being investigated, including down-hole boosting, subsea multiphase pumps and sub-sea separation.
Downhole pumps—In 1992, the PetrobrasPROCAP program initiated a project to developthese boosting technologies. The downholeboosting method was the first to reach the fieldin deepwater offshore Brazil, in the form of theelectrical submersible pump.19 Petrobras alreadyhad significant experience with electrical sub-mersible pumps on fixed towers in shallowerwater and in dry completions onshore. In oneoffshore development from eight fixed towers inthe area comprising the Carapeba, Pargo andVermelho oil fields of the Campos basin, 132wells produce with these pumps (right).
For use of electrical submersible pumps to befeasible in the deepest water, the pumps wouldneed to assure flow through extended tie-backsto surface facilities. It was important to test theviability of the method in shallow water beforeinvesting in the development of a deepwater sys-tem. Six other companies cooperated in thedevelopment and installation of the system: Redaand Lasalle (both now part of Schlumberger),Tronic, Pirelli, Cameron and Sade-Vigesa. A Redapump was installed in subsea well RJS-221,powered from the Carapeba 1 fixed tower 1640 ft[500 m] away. From there, with only the energyfrom the pump, production flowed to the Pargo 1platform 8.4 miles [13 km] away. The pump wasput into operation in October 1994 and func-tioned for 34 months before a failure occurred.
19. Mendonça JE: “Electrical-Submersible-Pump Installationin a Deepwater Offshore Brazil Well,” Journal ofPetroleum Technology 50, no. 4 (April 1998): 78-80.Mendonça JE: “Deepwater Installation of an ElectricalSubmersible Pump in Campos Basin, Brazil,” paper OTC8474, presented at the 1997 Offshore Technology Confer-ence, Houston, Texas, USA, May 5-6, 1997.
AT90AT60AT30AT20AT10
AIT curves
1 cm
Relative angle = 75°
Shale resistivity, 0.5 ohm-m
Fracture resistivity, 1000 ohm-m
AIT-
H, o
hm-m
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1000
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0.1-20 -10 0 10 20
Offset from fracture, cm
<Forward modeling of AIT response to inclinedfracture. INFORM forward modeling showed thata fracture dipping at 75° can reproduce theobserved order of the AIT curves.
The installation in RJS-221 demonstratedexcellent longevity compared with dry-completioninstallations, and proved the method for subseause. This encouraged Petrobras to develop thetechnology further for deep water. The deepwatertest site, well RJS-477, in the East Albacora oilreservoir is in 3632-ft [1107-m] deep water. InJune 1998, as a result of the pump installation,RJS-477 began to produce to Albacora field Platform P-25, moored 4 miles [6.4 km] away in1886 ft [575 m] of water (above). The power sys-tem has been developed for a range of 15 miles[24 km], which will allow, for example, Camposbasin wells within the 3775-ft [1150-m] water-depth mark to produce to high-capacity facilitiesmoored or fixed in shallower water.
The electrical submersible pump is the key tothe success of the new method.20 High interven-tion costs in deep water mean that equipmentreliability and longevity are crucial. Integrationof the completion system with electrical sub-mersible pump equipment is fundamental, andshould be addressed in the planning stages ofdeepwater wells. Both of the wells involved inthe test, RJS-221 and the deepwater RJS-477,were drilled to test new reservoirs before elec-trical submersible pumps were considered forthese subsea wells and so were not designed toaccommodate a submersible pump. Restrictionsin the liner and casing size in RJS-477 presentedchallenges to the design of the pump system.
For the deepwater electrical submersiblepump installation, new equipment was devel-oped for the extreme water depth and long-distance power transmission. This included theReda pump; Pirelli subsea power cables; Tronicsubsea power connectors; subsea power trans-former and long-distance power transmission bySiemens; and the deepwater horizontal produc-tion tree by Cameron.
This deepwater prototype has so far com-pleted two years of run-life with no failures.Petrobras considers the system to be proven toits design limits.
Subsea boosting—Statoil, BP Amoco, ExxonMobil and Petrobras have investigated thepossibility of deploying subsea multiphaseboosting pumps as an alternative to subsurfacedownhole pumping. This option becomes attrac-tive when the production from a large number ofwells can be commingled subsea and boostedfrom a production manifold or when the flowingpressure in the reservoir drops below the bub-blepoint. Deploying multiphase pumps on theseafloor, closer to the reservoir than if deployedat the sea surface, permits the efficient additionof pressure head to the flow and allows for ahigh-power system.
The equipment was first deployed in Decem-ber 1997 in the Lufeng field operated by Statoil inthe South China Sea (below). Five multiphaseboosting pumps manufactured by Framo Engi-neering were installed in 330 m [1082 ft] of water
16 Oilfield Review
Mooredproductionplatform
Power cableand flowline
Subseawellhead
Electricalsubmersiblepump
Perforations
> Subsea electrical submersible pump sending production from Well RJS-477 in 3632-ft[1107-m] deep water to Albacora field Platform P-25, four miles away in shallower water.
> Deploying a multiphase boosting pump in theLufeng field, South China Sea.
Spring 2000 17
Deepwater WaveAlong with increases in recovery percentages inexisting fields, deep water is one of the indus-try’s main hopes for balancing supply anddemand from the year 2005 onward. To realizethis hope, technological solutions and projectmanagement methods must result in perfor-mance levels that will allow deepwater projectsto compete economically with other sources ofoil and gas. The industry is making measurableprogress in this direction. In the 1980s producinga barrel of oil from a well in 200 m [656 ft] ofwater cost between $13 and $15 for an averagefield. Now technological advances have reducedthat figure to $5 to $7.21
The way forward into deeper water willcome from many directions. Beyond some depth,all production will be from subsea develop-ments. Advances in subsea flowlines, productiontrees, electrical power distribution systems, fluidseparation and reinjection technology and multi-phase metering and pumping will be necessaryto derive economical production from the10,000-ft [about 3000-m] water depths that soonwill be explored. These advances will allow thesubsea industry to move an increasing amountof activity to the seabed.
Deepwater and other offshore wells thatundergo well testing produce fluids that need tobe transported or otherwise disposed of, raisingenvironmental and operational safety concerns.Schlumberger is participating in a joint industryproject with BP Amoco, Conoco and Norsk Hydroto examine the feasibility of well testing withoutproducing hydrocarbons to the surface. The pro-ject will investigate technology to circulate flu-ids through a downhole testing system. The sys-tem will acquire pressure and flow-rate datadownhole rather than at the surface withouthaving to flare hydrocarbon fluids or transportcollected liquids for remote disposal. The resultwill be improved operational safety and reducedenvironmental impact.
The industry recognizes that deep watershold a key to its future survival and success.Diverse new technologies have brought explo-ration in deep and ultradeep water within thegrasp of oil companies. As we go further anddeeper, we are sure to find new challenges andopportunities. —LS
20. Reda has installed 100% of the world’s subsea electricalsubmersible pumps.
21. Thomas, reference 1.
(above left). Since then, the pumps have liftedmore than 50 million barrels [8 million m3] of liq-uid. Pump operations have been trouble-free. TheFPSO Navion Munin can perform intervention on the subsea pump using its own crane, thusallowing for cost-effective retrieval if needed.
Another deployment of multiphase pumps isunder way in the Topacio field offshore EquatorialGuinea, where ExxonMobil is running two Framopumps in more than 500 m of water to boost pro-duction from a satellite field (above right).
Other subsea developments that producefrom multiple wells may require a subsea multi-phase flowmeter. Framo Engineering has devel-oped a subsea multiphase flowmeter that allowstesting of individual wells. This type of solutionwas selected by BP Amoco for their develop-ment of the Machar field. A separate subseamodule allows the boosting of the multiphaseproduction once the wells water-out.
Application of these solutions to developmentsin deeper water will eventually allow for more cost-effective tie-backs than are currently achievable.
Subsea separation—Several companies areinvestigating concepts in subsea fluid separa-tion. Separating fluids subsea will avoid liftinglarge volumes of water all the way to surface forprocessing and disposal. This can reduce liftingcosts and allow economies in topside water pro-cessing and handling capacities. The savingsmay extend the economic life of deepwater pro-jects and reduce development risks.
Framo subseabooster pumps
> Five subsea multiphase booster pumps in the Statoil development of the Lufeng field.
> The subsea multiphase boosting pump built for the ExxonMobil operation in the Topacio field, offshore EquatorialGuinea.
1. For an example of mastering subsalt directional drillingchallenges: Cromb JR, Pratten CG, Long M and Walters RA:“Deepwater Subsalt Development: Directional DrillingChallenges and Solutions,” paper IADC/SPE 59197, presented at the 2000 IADC/SPE Drilling Conference,New Orleans, Louisiana, USA, February 23-25, 2000.
2. Bram K, Draxler J, Hirschmann G, Zoth G, Hiron S andKühr M: “The KTB Borehole—Germany’s SuperdeepTelescope into the Earth’s Crust,” Oilfield Review 7, no. 1(January 1995): 4-22.
Spring 2000 19
In rare emergency situations, directional-drilling technology is essential, for example toconstruct relief wells for blowouts. Less diresituations, such as sidetracking around anobstruction in a wellbore, also benefit from theability to control the wellbore trajectory. Furtherdownstream, directional drilling is used to con-struct conduits for oil and gas pipelines thatprotect the environment.3
Like other drilling operations, there is also aneed for cost-effective performance in direc-tional drilling: Drilling expenses account for asmuch as 40% of the finding and developmentcosts reported by exploration and productioncompanies.4 Offshore, eliminating a day of rigtime can save $100,000 or more. Acceleratingproduction by a day generates similar returns.5
Clearly, without advanced directional drillingtechnology, it might not be physically possible todrill a given well, the well might be drilled in asuboptimal location or it might be more expen-sive or risky. Rotary steerable systems allow usto plan complex wellbore geometries, includinghorizontal and extended-reach wells. They allowcontinuous rotation of the drillstring while steer-ing the well and eliminate the troublesome sliding mode of conventional steerable motors.The results have been dramatic: The PowerDriverotary steerable system contributed to the drillingof the world’s longest oil and gas productionwell, the 37,001-ft [11,278-m] Wytch Farm M-16SPZ well, in 1999. This article reviews thedevelopment of directional drilling technology,explains how new rotary steerable tools operateand presents examples that demonstrate howthese new systems solve problems and reduceexpenses in the oil field.
3. Barbeauld RO: “Directional Drilling OvercomesObstacles, Protects Environment,” Pipeline & GasJournal 226, no. 6 (June 1999): 26-29.
4. “Drill into Drilling Costs,” Hart’s E&P 73, no. 3 (March 2000): 15.
5. For several examples of the economic value of advanceddrilling technology: Djerfi Z, Haugen J, Andreassen E andTjotta H: “Statoil Applies Rotary Steerable Technologyfor 3-D Reservoir Drilling,” Petroleum EngineerInternational 72, no. 2 (February 1999): 29, 32-34.
Certain situations require advanced drilling tech-nology (next page). Local geology might dictate acomplicated well trajectory, such as drillingaround salt domes, salt tablets or salt sheets.1
Reservoir drainage or production from a particu-lar well might improve if a well penetrated mul-tiple fault blocks or was constructed horizontallyto intersect fractures or to maximize wellboresurface area within the reservoir. A multilateraltypically drains several reservoir compartments.Small compartments in mature fields can also beproduced economically if directional wells arelocated skillfully.
Operators drill extended-reach wells to reser-voirs that cannot be exploited otherwise withoutunacceptable cost or environmental risk, forinstance to drill from a surface location onshoreto a bottomhole location offshore rather thanconstructing an artificial island. Drilling multiplewells from one surface location has been stan-dard practice offshore for years and is now com-mon in restricted onshore locations, like rainforests, for environmental protection. There arealso instances in which the operator wants todrill a vertical wellbore, notably the deep well ofthe KTB Program (German Continental DeepDrilling Program), and uses a steering system tokeep the hole straight.2
18 Oilfield Review
New Directions in Rotary Steerable Drilling
Geoff DowntonStonehouse, England
Andy HendricksMount Pearl, Newfoundland, Canada
For help in preparation of this article, thanks to VinceAbbott, New Orleans, Louisiana, USA; Julian Coles,Kristiansund, Norway; Greg Conran, Barry Cross, IanFalconer, Jeff Hamer, Wade McCutcheon, Eric Olson,Charlie Pratten, Keith Rappold, Stuart Schaaf and DebSmith, Sugar Land, Texas, USA; Torjer Halle and Paul Wand,Stavanger, Norway; Randy Strong, Houston, Texas; MikeWilliams, Aberdeen, Scotland; and Miriam Woodfine,Mount Pearl, Newfoundland, Canada.ADN (Azimuthal Density Neutron), CDR (Compensated DualResistivity), InterACT Web Witness, PowerDrive, PowerPakand PowerPulse are marks of Schlumberger.
Initially developed to drill extended-reach wells, rotary steerable systems
are also cost-effective in conventional drilling applications because they
reduce drilling time significantly. Improvements in rate of penetration as
well as in reliability have prompted worldwide deployment of these tools.
Trond Skei KlausenNorsk HydroKristiansund, Norway
Demos PafitisSugar Land, Texas, USA
> Directional inclinations. Surface obstructions or subsurface geological anomalies might preclude drilling a straight hole. Reservoir drainage can be optimizedby drilling an inclined wellbore. In an emergency, such as a blowout, a directional relief well reduces subsurface pressure in a controlled manner.
Evolution of Directional Drilling TechnologyThere have been astonishing advances in drillingtechnology since the primitive cable-tool tech-niques used to drill for salt hundreds of yearsbefore the development of modern techniques.The advent of rotary drilling, whose timing andorigins are subject to debate but which occurredaround 1850, allowed drillers greater control inreaching a specified target.6 Further advancesdepended on the development of accurate sur-veying systems and other downhole devices.
Improvements in drilling safety have accom-panied the progress in drilling technology. Forexample, pipe handling has been increasinglyautomated by “iron roughnecks” to minimize thenumber of workers on the rig floor. Unsafe toolshave been removed, such as kelly spinners replac-ing spinning chains. Bigger and better drilling rigshandle loads more securely. Kick-detection soft-ware and use of devices that detect annular pres-sure changes help improve hole cleaning andretain well control.7 These and other advance-ments in modern drilling operations have reducedaccidents and injuries substantially.
The first patent for a turbodrill, a type of down-hole drilling motor, was awarded in 1873.8
Controlled directional drilling began in the late1920s when drillers attempted to keep verticalholes from becoming crooked, sidetrack aroundobstructions or drill relief wells to regain control ofblowouts. There were even cases of drilling acrossproperty boundaries to drain oil and gas reservesillegally. The development of the mud motor was apowerful complement to advances in surveyingtechnology. Since then, positive-displacementmotors (PDM), which are placed in the bottomholeassembly (BHA) to turn the bit, have drilled mostdirectional wellbores. Exotic well designs con-tinue to push the limits of directional-drilling tech-nology, resulting in the combination of rotary andsteerable drilling systems now available.
Determining the inclination of a wellbore was akey problem in directional drilling until accuratemeasuring devices were invented. Directional sur-veys provide at least three vital pieces of informa-tion: the measured depth, the inclination of thewellbore and the azimuth, or compass direction, ofthe wellbore. From these, the wellbore locationcan be calculated. Survey techniques range frommagnetic single-shot surveys to more sophisti-cated gyroscopic surveys. Magnetic surveys recordthe well inclination and direction at a given point(single shot) or many points (multishot) using aninclinometer and a compass, a timer and a camera.Gyroscopic surveys provide more accuracy using aspinning mass pointed in a known direction. Thegyroscope maintains its orientation to measureinclination and direction at specific survey stations.The industry is currently developing unintrusivegyroscopic surveying methods that can be usedwhile drilling.
Modern measurements-while-drilling (MWD)systems send directional survey information to sur-face by mud-pulse telemetry—survey measure-ments are transmitted as pressure pulses in thedrilling fluid and decoded at surface while drillingis in progress. In addition to direction and inclina-tion, the MWD system transmits information aboutthe orientation of the directional drilling tool.Survey tools indicate only where a well has beenplaced; it is the directional tools, from the simplewhipstock to advanced steerable systems, thatoffer the driller control over the wellbore trajectory.
Before the development of leading-edge steer-able systems, expedient placement of drill collarsand stabilizers in the BHA allowed drillers to buildor drop angle (above). These techniques allowedsome control over hole inclination, but little or nocontrol over the azimuth of the wellbore. In someregions, experienced drillers could take advantageof the natural tendency of the drill bit to achievelimited wellbore deviation in a somewhat pre-dictable manner.
20 Oilfield Review
6. For more on the likely origins of drilling techniques andoil and gas industry history: Yergin D: The Prize: The EpicQuest for Oil, Money & Power. New York, New York,USA: Simon & Schuster, 1991.
7. For more on measuring annular pressure while drilling:Aldred W, Cook J, Bern P, Carpenter B, Hutchinson M,Lovell J, Rezmer-Cooper I and Leder PC: “UsingDownhole Annular Pressure Measurements to ImproveDrilling Performance,” Oilfield Review 10, no. 4 (Winter1998): 40-55.For more on drilling risk: Aldred W, Plumb D, Bradford I,Cook J, Gholkar V, Cousins L, Minton R, Fuller J, Goraya Sand Tucker D: “Managing Drilling Risk,” Oilfield Review11, no. 2 (Summer 1999): 2-19.
8. Anadrill: PowerPak Steerable Motor Handbook. Sugar Land, Texas, USA: Anadrill (1997): 3.For more on the use of turbodrills in multilateral wellconstruction: Bosworth S, El-Sayed HS, Ismail G, Ohmer H,Stracke M, West C and Retnanto A: “Key Issues inMultilateral Technology,” Oilfield Review 10, no. 4(Winter 1998): 14-28.
9. McMillin K: “Rotary Steerable Systems Creating Niche inExtended Reach Drilling,” Offshore 59, no. 2 (February1999): 52, 124.
10. For several general articles about stuck pipe: Oilfield Review 3, no. 4 (October 1991).
11. Mims M: “Directional Drilling PerformanceImprovement,” World Oil 220, no. 5 (May 1999): 40-43.
Build assembly Pendulum or drop assembly
> Changing direction without a downhole motor. Careful placement of stabilizers and drill collarsallow the directional driller to build angle (left) or drop angle (right) without a steerable BHA.Generally, the placement and gauge of the stabilizer(s) and flexibility of the intermediatestructure determine whether the assembly will build or drop.
Spring 2000 21
Steerable motors, which use a downhole tur-bine or PDM to generate power and a BHA witha fixed bend of approximately 1⁄2°, were devel-oped in the early 1960s to allow simultaneouscontrol of wellbore azimuth and inclination.9
Today, a typical steerable motor assembly con-sists of a power-generating section, throughwhich drilling fluid is pumped to turn the drill bit,a bend section of 0 to 3°, a drive shaft and the bit(below left).
Directional drilling with a steerable motor isaccomplished in two modes: rotating and sliding.In the rotating mode, the entire drillstring turns inthe same manner as ordinary rotary drilling andtends to drill straight ahead.
To initiate a change in the wellbore direction,the rotation of the drillstring is halted in such aposition that the bend in the motor points in thedirection of the new trajectory. This mode, knownas the sliding mode, refers to the fact that thenonrotating portion of the drillstring slides alongbehind the steerable assembly. While this tech-nology has performed admirably, it requires greatfinesse to correctly orient the bend in the motorbecause of the torsional compliance of the drill-string, which behaves almost like a coiled spring,twisting to the point of being difficult to orient.Lithological variations and other parameters alsoinfluence the ability to achieve the planneddrilling trajectory.
Perhaps the greatest challenge in conventionalslide drilling is the tendency of the nonrotatingdrillstring to become stuck.10 During periods ofslide drilling, the drillpipe lies on the low side ofthe borehole. This leads to uneven fluid velocities
around the pipe. In addition, the lack of drillpiperotation diminishes the ability of the drilling fluidto remove cuttings, so a cuttings bed may form onthe low side of the hole. Hole cleaning is affectedby rotary speed, hole tortuosity and bottomholeassembly design, among other factors.11
Sliding-mode drilling decreases the horse-power available to turn the bit, which, combinedwith sliding friction, decreases the rate of pene-tration (ROP). Eventually, in extreme extended-reach drilling projects, frictional forces duringsliding build to the point that there is insufficientaxial weight to overcome the drag of thedrillpipe against the wellbore, and furtherdrilling is not possible.
Finally, slide drilling typically introduces sev-eral undesirable inefficiencies. Switching fromthe sliding mode to the rotating mode whiledrilling with steerable tools can result in a moretortuous path to the target (below right). The
Power section
Surface-adjustablebent housing
Bearing section andstabilizer
> Steerable BHA. This simple yet ruggedPowerPak steerable assembly consists of apower-generating section, a surface-adjustablebent housing, a stabilizer and the drill bit.
> Optimizing trajectory. Directional drilling in the sliding and rotating modes typically results ina more irregular and longer path than planned (red trajectory). Doglegs can affect the ability torun casing to total depth. The use of a rotary steerable system eliminates the sliding mode andproduces a smoother wellbore (black trajectory).
numerous undulations or doglegs in the wellboreincrease wellbore tortuosity, which in turnincreases apparent friction while drilling and run-ning casing. During production, gas may accumu-late in the high spots and water in the low spots,choking production (above). Despite these chal-lenges, directional drilling with a steerable motorremains cost-effective and is still the mostwidely used method of directional drilling.
The next advance in directional drilling tech-nology, still in its infancy, is the rotary steerablesystem (RSS). These systems allow continuousrotation of the drillstring while steering the bit. Currently, the industry classifies rotarysteerable systems into two groups, the moreprevalent “push-the-bit” systems, including thePowerDrive system, and the less mature “point-the-bit” systems (left).
How Does a Rotary Steerable System Work?The PowerDrive system is mechanically uncom-plicated and compact, comprising a bias unit anda control unit that add only 121⁄2 ft [3.8 m] to thelength of the BHA.12 The bias unit, locateddirectly behind the bit, applies force to the bit ina controlled direction while the entire drill-string rotates. The control unit, which residesbehind the bias unit, contains self-powered elec-tronics, sensors and a control mechanism toprovide the average magnitude and direction ofthe bit side loads required to achieve the desiredtrajectory (below).
The bias unit has three external, hinged padsthat are activated by controlled mud flow througha valve. The valve exploits the difference in mudpressure between the inside and outside of the
22 Oilfield Review
GasOil
Water
> Optimizing flow during production. The high and low spots in the undulating well-bore (top) tend to accumulate gas (red) and water (blue), impeding the flow of oil. A smoother profile (bottom) allows oil to flow to surface more readily.
Power generatingturbine
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Sensor packageand control system
Applied force> Rotary steerable system designs characterizedby their steady-state behavior. In point-the-bitsystems (left), the bit is tilted relative to the rest of the tool to achieve the desired trajectory.Push-the-bit rotary steerable systems (right)apply force against the borehole to achieve thedesired trajectory.
Control unit Bias unit
Control electronics TurbineTurbine Steering actuator pad
> The PowerDrive rotary steerable system.
Spring 2000 23
bias unit (right). The three-way rotary disk valveactuates the pads by sequentially diverting mudinto the piston chamber of each pad as it rotatesinto alignment with the desired push point—thepoint opposite the desired trajectory—in thewell. After a pad passes the push point, therotary valve cuts off its mud supply and the mudescapes through a specially designed leakageport. Each pad extends no more than approxi-mately 3⁄8 in. [1 cm] during each revolution of thebias unit. An input shaft connects the rotary valveto the control unit to regulate the position of thepush point. If the angle of the input shaft is geo-stationary with respect to the rock, the bit isconstantly pushed in one direction, the directionopposite the push point. If no change in directionis needed, the system is operated in a neutralmode, with each pad extended in turn, so that the pads push in all directions and effectively“cancel” each other.
The control unit maintains the proper angularposition of the input shaft relative to the forma-tion. The control unit is mounted on bearings thatallow it to rotate freely about the axis of the drill-string. Through its onboard actuation system, thecontrol unit can be commanded to hold a fixedroll angle, or toolface angle, with respect to therock formation. Three-axis accelerometer andmagnetometer sensors provide informationabout the inclination and azimuth of the bit aswell as the angular position of the input shaft.Within the control unit, counter-rotating turbineimpellers mounted at opposite ends of the con-trol unit develop the required stabilizing torqueby carrying high-strength permanent magnetsthat couple with torquer coils in the control unit.The torque transmission from the impellers to thecontrol unit is controlled by electrically switchingthe loop resistance of the torquer coils. The
upper impeller, or torquer, is used to torque theplatform in the same direction as drillstring rota-tion, while the lower impeller turns it in theopposite direction. Additional coils generatepower for the electronics.
The tool can be customized at surface andpreprogrammed according to the expectedranges of inclination and direction. If the instruc-tions need to be changed, a sequence of pulsesin the drilling fluid transmits new instructionsdownhole. The steering performance of thePowerDrive system can be monitored by MWDtools as well as the sensors in the control unit;this information is transmitted to surface by thePowerPulse communication system.
The datum used to set the geostationaryangle of the shaft is provided either by a three-axis accelerometer or by the magnetometer triadmounted in the control unit. For near-verticalholes, an estimate of magnetic North is used asthe reference for determining the direction ofdeviation. For holes that deviate more than a fewdegrees from vertical, the accelerometers pro-vide the steering reference.
One of the many benefits of using a roll-sta-bilized platform to determine the steering direc-tion is its insensitivity to drillstring stick-slipbehavior. Additional sensors in the control unitrecord the instantaneous speed of the drillstringwith respect to the formation, thereby providinguseful data about drillstring behavior. Shock and thermal sensors are also carried by the con-trol unit to record additional information aboutdownhole conditions. Information about drillingconditions is continuously sampled and logged bythe onboard computer for immediate transmis-sion to surface by the MWD system or for laterretrieval at surface. This information has helpeddiagnose drilling problems, and, coupled with theMWD, mud logging and formation records, isproving to be extremely valuable in optimizingfuture runs.
Control shaft Disk valve Actuator
Right turn
> Pushing the bit. Mud flow through a three-way disk valve actuates three external pads (top). The padspush against the borehole at the appropriate point in each rotation to achieve the desired trajectory—in this case, turning right (top right)—and extend outward up to 3⁄8 in. [1 cm]. The illustrations at thebottom show the tool with the pads retracted (left) and extended (right).
12. For additional details about the workings of thePowerDrive tool: Clegg JM and Downton GC: “TheRemote Control of a Rotary Steerable Drilling System,”presented at the British Nuclear Energy SocietyConference on Remote Techniques for HazardousEnvironments, London, England, April 19-20, 1999.For several case histories from Wytch Farm field:Colebrook MA, Peach SR, Allen FM and Conran G:“Application of Steerable Rotary Drilling Technology toDrill Extended Reach Wells,” paper IADC/SPE 39327,presented at the 1998 IADC/SPE Drilling Conference,Dallas, Texas, USA, March 3-6, 1998.
Getting from Here to ThereHaving the capability to control well trajectorydoes not guarantee a perfect well. Successfuldirectional drilling involves careful planning. Tooptimize well plans, the geologist, geophysicistand engineers must work together from the out-set, rather than working in sequence using anincomplete knowledge base. Given a certain sur-face location and a desired subsurface target,the directional planner must assess cost,required accuracy and geological and technicalfactors to determine the appropriate wellboreprofile—slant, S-shaped, horizontal or perhaps a more exotic shape. Drilling into another well-bore, known as a collision, is unacceptable, soanticollision software is typically used to plan a safe trajectory.13
It is also important to select the appropriateRSS for the job. For sticky situations, a tool withpad assemblies or other exterior components thatrotate with the collar, such as the PowerDrive sys-tem, minimizes the risk of stuck pipe and allowsbackreaming of the wellbore. The RSS also mustbe capable of achieving the desired build rate.
Real-time communication and formationevaluation capabilities are critical to success insome situations. The PowerDrive system links to the PowerPulse MWD system and the suite of Schlumberger logging-while-drilling (LWD)systems. A short hop, which is a short-distancetelemetry system that does not require hard
wiring, can be placed inside the PowerDrive toolto facilitate real-time upward communication(above). The short hop connects the PowerPulsetelemetry system interface with the MWD systemby sending magnetic pulses and confirms thatinstructions have been received from the surface.
Bit selection for rotary steerable systems isgreater than for steerable motor assembliesbecause toolface control is good even whenaggressive drill bits are used.14 Directional con-trol with a PDM and an aggressive bit can be dif-ficult because an aggressive bit may generatelarge fluctuations in torque. Variations in torquealter the toolface to the detriment of directionalcontrol. A short, polycrystalline diamond compact(PDC) bit, for example the Hycalog DS130,maximizes the performance of the PowerDriverotary steerable system. The versatility of thePowerDrive tool also permits the use of other bitdesigns, such as roller-cone bits.
Rotating the drillstring improves hole clean-ing dramatically, minimizes the risk of stuck pipe,and facilitates directional control. The power atthe bit is not compromised by the need to per-form slide drilling operations. Directional controlcan be maintained beyond the point wheretorque and drag make sliding with a motor inef-fective. The benefits of increased ROP comparedwith a traditional sliding assembly are realizedwhen using the PowerDrive system.
PowerDrive Systems in High GearSince its first commercial run in 1996, thePowerDrive tool has demonstrated that elim-ination of sliding while directionally drillingdramatically increases the overall rate of pene-tration. The elimination of the sliding mode alsomakes unusual well trajectories possible, as thefollowing case histories demonstrate.
There have been 230 PowerDrive tool runs todate, including thousands of hours of operationin more than 40 wells. The longest single rundrilled a 5255-ft [1602-m] section.
In the Njord field of the Haltenbanken area offwestern Norway, operator Norsk Hydro first usedthe PowerDrive system to drill the reservoir sec-tion of the A-17-H well, finishing 22 days aheadof schedule. This success set the stage for amuch more challenging multitarget well with asinusoidal profile to manage the dual challengesof geological uncertainty and poor reservoir con-nectivity. The A-13-H well was drilled with thePowerDrive system in April 1999. The unusual W-shaped trajectory was planned to penetratethe primary reservoir in multiple fault blocks(next page, top).
The well penetrated the heterogeneousJurassic Tilje formation, which is predominantlysandstone with minor occurrences of mudstoneand siltstone, in four fault blocks. The reservoir iscompartmentalized by steeply dipping, hydrocar-bon-sealing fault planes separated by as much as30 to 50 m [98 to 164 ft] of throw. An additionalcomplication is that horizontal permeability in theTilje reservoir is significantly better than verticalpermeability, so producing it from a horizontalwellbore is preferable.
24 Oilfield Review
13. For more on integrated well-planning software:Clouzeau F, Michel G, Neff D, Ritchie G, Hansen R,McCann D and Prouvost L: “Planning and Drilling Wellsin the Next Millennium,” Oilfield Review 10, no. 4 (Winter 1998): 2-13.
14. A full discussion of bit selection is beyond the scope ofthis article, but will be addressed in an upcomingOilfield Review article. For this discussion, an aggres-sive bit is one that has been designed to drill quicklyusing long cutters that produce large cuttings. Lessaggressive bits have shorter teeth that produce smallercuttings by grinding. Other issues that affect bit functioninclude rotary speed, weight on bit, torque, flow rateand the nature of the formation being drilled.
> BHA configurations. The PowerDrive system can be run without a real-time communications system(top), with real-time short-hop communications (middle) or with a short-hop extender that allows real-time communications using a flex collar when a higher build rate is required (bottom).
4°/100 ftno real-time communications
4°/100 ftreal-time communications
8°/100 ftreal-time communications
PPI-communications
interface subStabilizer Control unit
collarBias unit
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Short-hop probe
15. For more on data delivery, including the InterACT WebWitness system: Brown T, Burke T, Kletzky A, Haarstad I,Hensley J, Murchie S, Purdy C and Ramasamy A: “In-Time Data Delivery,” Oilfield Review 11, no. 4 (Winter 1999/2000): 34-55.
16. For more on extended-reach drilling and productionoperations in the Wytch Farm field: Algeroy J, MorrisAJ, Stracke M, Auzerais F, Bryant I, Raghuraman B,Rathnasingham R, Davies J, Gai H, Johannessen O,Malde O, Toekje J and Newberry P: “ControllingReservoirs from Afar,” Oilfield Review 11, no. 3 (Autumn 1999): 18-29.Allen F, Tooms P, Conran G, Lesso B and Van de Slijke P:“Extended-Reach Drilling: Breaking the 10-km Barrier,”Oilfield Review 9, no. 4 (Winter 1997): 32-47.
Spring 2000 25
Real-time porosity, resistivity and gamma raymeasurements from the ADN Azimuthal DensityNeutron and CDR Compensated Dual Resistivitysystems allowed the operations team to geologi-cally steer the well into the desired locationusing the RSS. Intentional departures from theplanned trajectory were decided on the basis ofreal-time formation evaluation measurements.The InterACT Web Witness system transmitteddata in real time from the Njord drilling platformto the operations offices in Kristiansund andBergen so that the drilling and geological opera-tions team could make timely drilling decisions.15
In the past, a fishhook-shaped well wouldhave been drilled to intersect the reservoir in justtwo fault blocks. The combination of the RSS andreal-time formation evaluation enabled a seek-and-find approach, rather than guesswork, in anarea in which seismic uncertainty is as much as100 m [328 ft], to optimize the trajectory andimprove reservoir drainage by drilling into fourfault blocks. The penetration of the additionalfault blocks saved the expense and risk of drillinganother well. The A-13-H well would have beenimpossible to drill with conventional directionaldrilling technology. Using the rotary steerable
system cost $1 million less than the previous wellin the field because it cut well construction timeby half. Use of PDC bits with the PowerDrive toolmore than doubled ROP.
Rotary steerable systems open up new hori-zons for well planning, reservoir management andeven field development. Rotary steerable systemsmean that fewer wells are drilled, but those thatare drilled penetrate more targets. By intersectingfour fault blocks rather than two, the A-13-H wellachieved the geological objectives of two wellsand improved reservoir drainage dramatically.Well placement can be optimized by real-timetrajectory adjustments based on measurementsby combining the newest real-time formationevaluation tools with the PowerDrive system.Smaller platforms with fewer slots requiresmaller investments while optimizing fielddrainage and reducing the cost per barrel.
The PowerDrive system extended the life ofthe Njord field as a whole because of the flexibil-ity of the system. It has allowed access to reservesthat would have been considered uneconomicwith standard technology.
PowerDrive tool performance in 1999 averageda mean time between failures of 522 hours in theUnited Kingdom. In 2000, UK activity has increasedto three or more runs per month. Typical drillingoperations include complicated designer wells withmultiple build and turn sections. In 1998, the WytchFarm M-17 well was drilled through the narrowSherwood sandstone reservoir and between twofaults using the PowerDrive tool.16 This well set thecurrent record for a bit run, drilling 1287 m [4222 ft]in 84 hours while achieving a 110° turn at high incli-nation (below).
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> Longest bit run at Wytch Farm. The PowerDrive tool was used in two runs on the M-17 well, the second of which established the field recordfor longest bit run, with 1287 m of 81⁄2-in. hole drilled in 84 hours. The plan view of the well trajectory (left) shows the 110° turn. The three-dimensional view (right) illustrates the high inclination that accompanied the turn. Use of the PowerDrive tool saved seven days of rig time.
< A-13-H well path. The W-shaped wellintersected the Tilje reservoir in four separate fault blocks (top). Other well configurations used in the area, such asfishhook-shaped wells, would have penetrated only two fault blocks (bottom).
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Proposal Actual
Maximizing the cost-effectiveness of expen-sive directional wells with complex trajectories is a major challenge facing drilling engineers.Success depends on drilling tools that offer inher-ent efficiency, reliability and capabilities thatsupersede conventional systems. In Malaysia, thePowerDrive rotary steerable system demonstratedits prowess in two wells, the Bekok A1 ST and A7 ST, for operator Petronas Carigali. In both wells,the system performed flawlessly, with no failuresand no restrictions to drilling operations, such as having to backream. Steering was excellent inboth cases despite the relatively soft formationsbeing drilled.
On Bekok A7 ST, 1389 m [4557 ft] were drilledat an average of 51 m/hr [167 ft/hr], with holeinclinations varying from 40 to 70 degrees. Buildsand turns averaged 3°/30 m [3°/100 ft] (left). Byoptimizing bit selection, weight-on-bit, mud flowrate and rpm, PowerDrive technology achieved a45% higher penetration rate than the best everrecorded with downhole motors: The PowerDrivetool drilled 513 m/day [1683 ft/day], saving fivedays of rig time, while the best motor per-formance, in the Bekok A5 well, was only 360 m/day [1181 ft/day]. Valuable rig time wasalso saved because wiper trips decreased from atraditional average of one per 300 m [980 ft] toone per 700 m [2300 ft]. The well reached totaldepth in only two-thirds the time specified in thedrilling plan, resulting in significant cost savings.
On Bekok A1 ST, the PowerDrive system was used to drill 1601 m [5253 ft] of the 81⁄2-in.[21.6-cm] landing section of the well, cuttingthree days from the scheduled drilling program(next page, top left). Rates of penetration were300% higher than those experienced withconventional assemblies in offset wells, withcorrespondingly fewer wiper trips. Minimal tortu-osity, no micro doglegs and a smooth wellboreface allowed rapid, trouble-free deployment of the 7-in. [17.8-cm] liner. Total savings throughuse of the PowerDrive system are estimated at US$200,000.
The second development well in a field in theViosca Knoll planning area was the first applica-tion of a rotary steerable tool by a major operatorin the Gulf of Mexico. The operator’s goal inselecting the PowerDrive system was to save rigtime by increasing ROP with improved hydraulicsand also improving hole cleaning above the levelsachievable with a steerable PDM configuration.These improvements would help mitigate or elim-inate expensive and time-consuming stuck-pipeproblems caused by expanding shales—a fre-quent occurrence in the area—and allow tightercontrol on the equivalent circulating density ofthe drilling mud. Use of the rotary system would
26 Oilfield Review
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Build and turn 3.00° per 30 m
Bekok A7 ST
Bekok A7
Hold angle 69.35°7-in. liner 2190 MD 1692 TVD 69.2° 198.5° az 1369 departure
TD 8.5-in. section 2600 MD 1696 TVD 69.2° 198.5° az 1369 departure
ActualProposal
-1280
-720 -560 -400 -240 -80 80
-1120
-960
-800
-640
-480
-320
-160
0
160
320
480
Disp
lace
men
t (no
rth/s
outh
), m
Displacement (east/west), m
Bekok A7
KOP360 MD 358 TVD17.7° 347.43° az23N 7W
7-in. liner
Bekok A7 ST
Hold
azim
uth 19
8.93°
> Plan view (top) and section view (bottom) of theBekok A7 ST planned well trajectory, shown in blue,and the actual trajectory, shown in red.
Spring 2000 27
ensure that cuttings were held in suspension atall times, overcoming settling problems associ-ated with sliding during PDM operations.
The PowerDrive system was used to drill outfrom the 95⁄8-in. [24.4-cm] casing shoe at 11,660 ft[3554 m]. After a formation integrity test wasperformed, the fluid system was displaced with14.9 lbm/gal [1.79 g/cm3] diesel-base drillingmud. This was the first time the tool had beenused with diesel-base fluid, so the potential forproblems was anticipated. The tool successfullydrilled 2767 ft [843 m] at a turn and drop rate ofup to 1.6° per 100 ft [30 m] (right).
The planned directional profile includeddrilling a 1300-ft [396-m] tangent section before
dropping and turning left through two geometri-cally tight targets. The tangent, or hold, sectionallowed the team to evaluate the directionalperformance of the system before initiating theturn. Excellent penetration rates were achievedwhile steering with the PowerDrive tool. Thesmall pressure drop across the tool allowedbetter use of available hydraulic horsepowercompared to a steerable motor. Flow rates weresome 50 gal/min [0.2 m3/min] higher than previ-ous motor runs, promoting improved hole clean-ing and faster rates of penetration. Hole-cleaningefficiency was monitored using an annular pres-sure sensor in the MWD string so that the holecould be cleaned as quickly as it could be drilled.
> Plan view (top) and section view (bottom) ofthe Bekok A1 ST planned well trajectory, shownin blue, and the actual trajectory, shown in red.
-4000 -3750 -3500 -3250 -3000-3000
-3250
-3500
-3750
RIH with PowerDrive tool
POOH with PowerDrive tool
Drop and turn2° per 100 ft
-4000
-4250
-4500
-4750
-5000
Displacement (east/west), ft
Disp
lace
men
t (no
rth/s
outh
), ft
1050
1100
1150
1200
1250
1300
RIH with PowerDrive tool
1350
1400
Departure from vertical, ft4500 5000 5500 6000
Verti
cal d
ispl
acem
ent,
ft
ActualProposal
Drop and turn 2° per 100 ft 35.14° 13,448 ft MD
POOH with PowerDrive tool
> Rotary steerable drilling in the Gulf ofMexico. A development well in a field inthe Viosca Knoll area was drilled using a rotary steerable system to improve ROPand hole cleaning. The proposed trajec-tory is shown in blue. The PowerDrivetool achieved the desired trajectory, asshown in red in the vertical section view(top) and plan view (bottom). The rotarysteerable tool was removed after drilling2767 ft and a PDM drilled the remainder of the hole at a rate that was two andone-half times slower.
0
400
800
1200
1600
2000
0 400 800 1200 1600 2000 2400 2800
True
ver
tical
dep
th, m
Vertical section, m
Tie-in 8.5° 418 measured depth
Build and turn 3.00° per 30 m75.71° 1117 measured depth
Bekok A1
Bekok A1 STHold angle 75.71°
ActualProposal
-1800
-2400 -1800 -1200 -600 0
-1200
-600
0
Disp
lace
men
t (no
rth/s
outh
), m
Displacement (east/west), m
Tie-inBekok A1
Bekok A1 ST
Kickoffpoint
Overall, the PowerDrive assembly was used todrill 420 ft [128 m] of cement and the shoe trackand formation from 11,660 to 14,427 ft [3554 to4397 m]. This was achieved in 42 drilling hours atan average penetration rate of 66 ft/hr [20 m/hr].
At 14,427 ft measured depth, it becameapparent that the rotary steerable system was nolonger receiving commands from the surface. Thetool continued to drill according to the last
command received, a low-side orientation thatinduced a slight turn to the right. At this stage, itwas imperative to initiate a left-hand turn, and atrip was required to retrieve the tool. Becausethe nature of the failure was unknown initially,and because the wellbore temperature wasapproaching the temperature limits of the rotarysteerable assembly, a conventional steerablemotor was selected to finish drilling the interval.
Subsequent analysis confirmed that an elas-tomer bearing had failed, allowing the turbinepower assembly to rotate eccentrically in the toolcollar. Wear inside the collar indicated that theturbine fins were striking the inner collar wall,preventing the tool from receiving new com-mands. It was later determined that the mud haddegraded the bearing material. For future appli-cations, an upgraded, more durable elastomerhas been developed, proven effective and is now in use.
The results with a steerable motor on the fol-lowing run provided an interesting comparison ofthe efficiency of the two systems because thesame type of bit was run, the same formationwas drilled and similarly demanding directionalwork was performed. Penetration rates achievedwhile rotating with the conventional steerablemotor approached those of the PowerDrive sys-tem. However, the extra time necessary to orientthe toolface, along with lower penetration rateswhile sliding, greatly increased overall drillingtimes. The steerable motor drilled 1303 ft [397 m]in 48 hours at an average ROP of 27 ft/hr [8.2 m/hr], almost two and one-half times slowerthan the PowerDrive system.
This example clearly demonstrates thatincreased ROP offsets higher rig rates and morethan compensates for the additional expense ofthe rotary steerable tool, resulting in overall timeand cost savings (left). This well was drilled 10days ahead of plan. Nevertheless, furtherimprovement in rotary steerable drilling perfor-mance remains a key objective for Schlumberger.
28 Oilfield Review
> Drilling efficiency improvements.Use of the PowerDrive system contributed to drilling the VioscaKnoll development well 10 daysahead of plan.
17. Schaaf S, Pafitis D and Guichemerre E: “Application of aPoint the Bit Rotary Steerable System in DirectionalDrilling Prototype Well-bore Profiles,” paper SPE 62519,prepared for presentation at the 2000 SPE/AAPGWestern Regional Meeting, Long Beach, California,USA, June 19-23, 2000.
0
2000
4000
6000
8000
10,000
0 20 40 60 80
12,000
14,000
16,000
18,000
Mea
sure
d de
pth,
ft
Actual daysRisked plan days
Minimum plan days
Number of drilling days
Spring 2000 29
Driving into the FutureThe ability of the PowerDrive rotary steerable sys-tem to drill long sections quickly and reliably hasled to high demand for the 39 tools now available.The manufacturing of 16 additional PowerDrivetools during the first quarter of 2000 increasedworldwide access to these systems. The tools aremanufactured in the UK, but maintenance andrepairs are performed in several regional centers,close to where the tools are used.
The PowerDrive675 system, the 63⁄4-in. tooldescribed in this article, is now proven tech-nology (right). Schlumberger is working to setnew industry standards for rotary steerablesystems. The PowerDrive900, a 9-in. push-the-bit tool designed to drill 121⁄4-in. and largerholes, is undergoing field trials at present, with commercialization expected in the secondhalf of 2000.
A point-the-bit tool design, whose drilling tra-jectory is determined by the bit direction ratherthan the orientation of a longer section of theBHA, will fulfill demands for greater bit and sta-bilizer selection, including bicenter bits, andhigher build rates. Schlumberger has tested aprototype point-the-bit tool in various locationsworldwide and drilled upwards of 100 ft/hr [30 m/hr].17 This prototype tool extends the flowand temperature ranges of the push-the-bit
systems while maintaining a relatively compactsize. Survey data are gathered close to the bitand sent to the surface for real-time trajectoryfeedback and control. For each of these systems,the goal is cost-effective drilling in mainstreamoperations, rather than the current economicrestriction to only the most extreme applications.Operators certainly will continue to push the lim-its of reach and depth (left).
Further refinements in remote communicationlinks to operator offices will allow experts toreceive data, consult with rig personnel and sendback commands to the mud pumps, a criticalcapability when drilling complex wells.Eventually, the shape of wellbores will be limitedonly by economics and ingenuity. —GMG
Steady deviationcontrolled by downhole motor,
independent of bit torque. Problemsof controlling toolface throughelastic drillstring are avoided.
Cleaner holeeffect of high inclination is offset
by continuous pipe rotation
Continuous rotationwhile steering
Smooth holetortuosity of wellbore is reduced
by better steering
Less risk ofstuck pipe
Less dragimproves control of WOB
Lower cost per barrel
Time savingsdrill faster while steering and
reduce wiper trips
Longer extended reachwithout excessive drag
Completioncost is reduced
andworkover
is made easier
Longerhorizontal
rangein reservoir with
good steering
Fewer wellsto exploit areservoir
Lower cost per footFewer platformsto develop a field
> Benefits of the PowerDrive system. Continuous rotation of the drillstring improves manyaspects of well construction and ultimately translates into saving time and money.
35,000
30,000
25,000
20,000
15,000
10,000
5000
00 5000 10,000 15,000 20,000 25,000 30,000 35,000 40,000
5:1Ratio
2:1Ratio
1:1 Ratio
True
ver
tical
dep
th, f
t
Displacement, ft
Shell Auger
BP ClydeBP Gyda
Maersk, QatarAmoco Brintnell 2-10
Statoil Sleipner PhillipsZijiang
Total Austral
Total AustralCN-1
BP M-14
BP M-11BP Amoco
M-16Z
> Extending the envelope. Reach of 10 km [6.2 miles] or more is possible at relatively shallowdepths. Displacement becomes restricted with increasing depth, as shown by the purple envelope.
Oilfield Review30
Water Control
Bill BaileyMike CrabtreeJeb TyrieAberdeen, Scotland
Jon ElphickCambridge, England
Fikri KuchukDubai, United Arab Emirates
Christian RomanoCaracas, Venezuela
Leo RoodhartShell International Exploration and ProductionThe Hague, The Netherlands
Today, oil companies produce an average of three barrels of
water for each barrel of oil from their depleting reservoirs.
Every year more than $40 billion is spent dealing with unwanted
water. In many cases, innovative water-control technology can
lead to significant cost reduction and improved oil production.
For help in preparation of this article, thanks to AndrewAcock, Houston, Texas, USA; Kate Bell and AnchalaRamasamy, BP Amoco Exploration, Aberdeen, Scotland;Leo Burdylo, Keng Seng Chang and Peter Hegeman, SugarLand, Texas; Alison Goligher, Montrouge, France; DouglasHupp, Anchorage, Alaska, USA; Lisa Silipigno, OklahomaCity, Oklahoma, USA; and David Wylie, Aberdeen. FloView, FrontSim, GHOST (Gas Holdup Optical SensorTool), MDT (Modular Formation Dynamics Tester), NODAL,PatchFlex, PLT (Production Logging Tool), PosiSet, PSPLATFORM (Production Services Platform), RST (ReservoirSaturation Tool), SqueezeCRETE, TPHL (three-phase fluidholdup log), USI (UltraSonic Imager) and WFL (Water Flow Log) are marks of Schlumberger. Excel is a mark ofMicrosoft Corporation. MaraSEAL is a mark of Marathon OilCorporation. PrecisionTree is a mark of Palisade Corporation.
Oil and water
Water
Free-waterlevel
Oil, gas and water
Gas and water
Free-oillevel
Reservoir containing water, oil and gas.The figure shows the fluid distribution in a typical reservoir before production orinjection begins. Above the free-oil level,water saturation will be at its irreduciblevalue. The transition zone between thefree-oil and free-water levels is character-ized by a gradual increase in water satura-tion to 100%. In this zone, both oil andwater are partially mobile. The thickness ofthe transition zone depends on factorssuch as pore size, capillary pressure andwettability. There is a transition zonebetween the hydrocarbon and water layers where water and oil saturation vary.In general, low-permeability rocks willhave thicker transition zones.
Spring 2000 31
Given the worldwide daily water production ofroughly 210 million barrels [33.4 million m3] ofwater accompanying every 75 million barrels[11.9 million m3] of oil, many oil companies couldalmost be called water companies. Water-handling costs are high—estimates range from 5 to more than 50 cents per barrel of water. In a well producing oil with an 80% water cut, thecost of handling water can be as high as $4 perbarrel of oil produced. In some parts of the NorthSea, water production is increasing as fast asreservoir oil rates are declining.
Water affects every stage of oilfield life fromexploration—the oil-water contact is a crucial fac-tor for determining oil-in-place—through develop-ment, production, and finally to abandonment(below). As oil is produced from a reservoir, waterfrom an underlying aquifer or from injectors even-tually will be mixed and produced along with the
oil. This movement of water flowing through a reservoir, into production tubing and surface-processing facilities, and eventually extracted fordisposal or injected for maintaining reservoir pres-sure, is called the ‘water cycle’ (above).
Oil producers are looking for economic waysto improve production efficiency, and water-con-trol services are proving to be one of the fastestand least costly routes to reduce operating costsand improve hydrocarbon production simultane-ously. The economics of water productionthroughout the water cycle depend on a numberof factors such as total flow rate, productionrates, fluid properties like oil gravity and watersalinity, and finally the ultimate disposal methodfor the water produced. Operational expenses,
Oila
ndw
aterDry o
il
W
ater
ProcessingDemulsifiers/corrosionFacility debottlenecking
TreatingCleaningDischarge
Water shutoffScale and hydrate controlCorrosion inhibitor
Profile modificationWater diversionFluid monitoringGel treatmentsPermeability modifiersDamage removal
> The water cycle. The transport of water through the field startswith flow in the reservoir leading to production, and then surfaceprocessing. Finally, the water isdisposed of at the surface orinjected for disposal or pressuremaintenance.
including lifting, separation, filtering, pumpingand reinjection, add to the overall costs (below).In addition, water-disposal costs can vary enor-mously. Reports vary from 10 cents per barrelwhen the unwanted water is released into theocean offshore to over $1.50 per barrel whenhauled away by trucks on land. Although thepotential savings from water control alone aresignificant, the greatest value comes from thepotential increase in oil production and recovery.
Managing the cycle of water production, sep-aration downhole or at the surface, and disposalinvolves a wide range of oilfield services. Theseinclude data acquisition and diagnostics usingdownhole sensors; production logging and wateranalysis for detecting water problems; reservoirmodeling to characterize flow; and various tech-nologies to eliminate water problems such asdownhole separation and injection, chemical andmechanical shutoff, and surface water separa-tion and production facilities.
In this article, we focus on the detection andcontrol of excess water production. First, wereview the many ways in which water can enterthe wellbore. Then, we describe measurementsand analysis to identify these problem types.Finally, we examine treatments and solutions.Case studies demonstrate applications in individ-ual wells, on a field scale and in surface facilities.
32 Oilfield Review
Lifting
Separation
De-oiling
Filtering
Pumping
Injecting
Capex/OpexUtilitiesCapex/OpexUtilitiesChemicalCapex/OpexChemicalsCapex/OpexUtilitiesCapex/OpexUtilitiesCapex/OpexTotal cost/bblTotal chemicalsTotal utilitiesTotal wellsSurface facilities
$0.044$0.050$0.087$0.002$0.034$0.147$0.040$0.147$0.012$0.207$0.033$0.030$0.842$0.074$0.102$0.074$0.589
5.28%6.38%
10.36%0.30%4.09%
17.56%4.81%
17.47%1.48%
24.66%3.99%3.62%100%
8.90%12.16%
8.89%70.05%
$0.044$0.054$0.046$0.003$0.034$0.073$0.041$0.068$0.010$0.122$0.034$0.030$0.559$0.075$0.010$0.075$0.309
7.95%9.62%8.27%0.45%6.16%
12.99%7.25%
12.18%1.79%
21.89%6.01%5.45%100%
13.41%17.87%13.40%55.33%
$0.044$0.054$0.035$0.003$0.034$0.056$0.041$0.047$0.010$0.091
$0..034$0.030$0.478$0.075$0.100$0.075$0.227
9.29%11.24%
7.24%0.52%7.20%
11.64%8.47%9.85%2.09%
19.06%7.03%6.37%100%
15.67%20.88%15.66%47.80%
$0.044$0.054$0.030$0.003$0.034$0.046$0.041$0.030$0.010$0.079$0.034$0.030$0.434$0.075$0.100$0.075$0.184
10.25%12.40%
6.82%0.58%7.94%
10.58%9.34%6.87%2.31%
18.15%7.75%7.02%100%
17.28%23.03%17.27%42.41%
$0.044$0.054$0.049$0.003$0.034$0.081$0.041$0.073$0.011$0.125$0.034$0.030$0.578$0.075$0.101$0.075$0.328
7.69%9.30%8.55%0.43%5.95%
13.92%7.00%
12.63%1.84%
21.61%5.81%5.27%100%
12.96%17.38%12.95%56.71%
20,000 B/D 50,000 B/D 100,000 B/D 200,000 B/D Average
Surface processing Wells, producers Wells, injectors
SeparationLiftingInjectionCost
1 Well 7000 ftRecompletionTotal 1 wellCost for waterTotal productionTotal waterCost for water lift
0.00251.92
1.2$0.028
kw/bblkw/bblkw/bblPer kw-hr
$1,000,000.00300,000
$1,600,000.00$400,000.00
1,000,0009,000,000
$0.04
Drill and completePer completion3 Completions
bbl @ 90% water cutbbl @ 90% water cut$/bbl
1 Well 7000 ftRecompletionTotal 1 wellTotal injectedCost for water injection
$600,000.00200,000
$1,000,000.0032,850,000
$0.03
Drill and completePer completion3 Completions3 Completions$/bbl
>Water-cycle cost. The table shows typical estimated water-handling costs per barrel—capital and operating expenses (Capex and Opex), utilities andchemicals—lifting, separation, de-oiling, filtering, pumping and injection for fluid production varying from 20,000 to 200,000 B/D [3181 to 31,810 m3/d].
1.0
0
WOR
WOR economic limit
Added recovery
Oil production, bbl
A
B
C
D
>Water control to increase well productivity and potential reserves. As most wellsmature, the water/oil ratio (WOR) increases with production (A) due to increasingamounts of water. Eventually, the cost of handling the water approaches the value ofoil being produced and the WOR “economic limit” (B). Water-control methodologyand technology reduce the well’s water production (C) enabling continued economicoil production. Water control results in increased economic recovery in the well (D).
Spring 2000 33
Water SourcesWater is present in every oil field and is the mostabundant fluid in the field.1 No operator wants toproduce water, but some waters are better thanothers. When it comes to producing oil, a keyissue is the distinction between sweep, good (oracceptable), and bad (or excess) water.
“Sweep” water—Sweep water comes fromeither an injection well or an active aquifer thatis contributing to the sweeping of oil from thereservoir. The management of this water is a vital part of reservoir management and can be a determining factor in well productivity and theultimate reserves.2
“Good” water—This is water that is producedinto the wellbore at a rate below the water/oilratio (WOR) economic limit (previous page, top).3 Itis an inevitable consequence of water flowthrough the reservoir, and it cannot be shut offwithout losing reserves. Good-water productionoccurs when the flow of oil and water is commin-gled through the formation matrix. The fractionalwater flow is dictated by the natural mixing behav-ior that gradually increases the WOR (top right).
Another form of acceptable water productionis caused by converging flow lines into the well-bore (middle right). For example, in one quadrantof a five-spot injection pattern, an injector feedsa producer. Flow from the injector can be charac-terized by an infinite series of flowlines—theshortest is a straight line from injector to pro-ducer and the longest follows the no-flow bound-aries from injector to producer. Waterbreakthrough occurs initially along the shortestflowline, while oil is still produced along slowerflowlines. This water must be considered goodsince it is not possible to shut off selected flow-lines while allowing others to produce.
Since good water, by definition, produces oilwith it, water management should seek to maxi-mize its production. To minimize associatedwater costs, the water should be removed asearly as possible, ideally with a downhole sepa-rator (bottom right). These devices, coupled withelectrical submersible pumps, allow up to 50% ofthe water to be separated and injected downholeto avoid lifting and surface-separation costs.
1. Kuchuk F, Sengul M and Zeybek M: “Oilfield Water: A Vital Resource,” Middle East Well Evaluation Review22 (November 22, 1999): 4-13.
2. Kuchuk F, Patra SK, Narasimham JL, Ramanan S andBanerji S: “Water Watching,” Middle East WellEvaluation Review 22 (November 22, 1999): 14-23; andalso Kuchuk F and Sengul M: “The Challenge of WaterControl,” Middle East Well Evaluation Review 22(November 22, 1999): 24-43.
Injector
Incr
easi
ng ti
me
Water front Producer
Oil and water
Only water
Only Oil
Only Oil
> Good and bad water. Good water needs to be produced with oil. It cannotbe shut off without shutting off oil. Downhole separation may be a solution.Bad water does not help production, and it depletes pressure.
Injector
Producer
Wat
er
Oil
Oil
Water
Simulating water flow in a reservoir.FrontSim streamline reservoir simulationsoftware is ideal for demonstrating whathappens to fluids flowing in a reservoir.The streamlines represent the flow ofwater from injector to producer. The simulator requires geological, structuraland fluid information. The plot shows onequadrant of a uniform five-spot injectionpattern where the water from the mostdirect streamline is the first to breakthrough to the producer. The water fromthese streamlines is considered goodwater because it cannot be shut off without decreasing oil production.
Productionzone
Injectionzone
Oil
Water
Reservoirfluid in
Oil and somewater out
Water out
Downhole separator.Separating water down-hole reduces the costs oflifting the excess water.Typical downhole separa-tors are 50% efficient. Theexcess water is injectedinto another formation.
3. Water/oil ratio (WOR) is the water production ratedivided by oil production rate. It ranges from 0 (100% oil)to infinite (100% water). Also commonly used are theterms ‘water cut’ or ‘fractional water flow’ defined aswater production rate divided by total production rate asa percentage or fraction, respectively. Correspondencebetween these measures can be easily calculated
(for example, a WOR of 1 implies a water cut of 50%). The WOR economic limit is the WOR at which the cost of the water treatment and disposal is equal to the profitfrom the oil. Production beyond this limit gives a negativecash flow. This can be approximated by the net profitfrom producing an incremental unit volume of oil dividedby the cost of an incremental unit volume of water.
“Bad” water—The remainder of this articledeals principally with the problems of excesswater. Bad water can be defined as water that isproduced into the wellbore and produces no oil orinsufficient oil to pay for the cost of handling thewater—water that is produced above the WOReconomic limit. In individual wells, the source ofmost bad-water problems can be classified as oneof ten basic types. The classification of waterproblem types presented here is simplistic—manyvariations and combinations can occur—but it isuseful for providing a common terminology.4
Water ProblemsThe ten basic problem types vary from easy tosolve to the most difficult to solve.
Casing, tubing or packer leaks—Leaks throughcasing, tubing or packers allow water from non-oil-productive zones to enter the production string(below left). Detection of problems and applicationof solutions are highly dependent on the well con-figuration. Basic production logs such as fluid den-sity, temperature and spinner may be sufficient todiagnose these problems. In more complex wells,WFL Water Flow Logs or multiphase fluid loggingsuch as the TPHL three-phase fluid holdup log canbe valuable. Tools with electrical probes, such asthe FlowView tool, can identify small amounts ofwater in the production flow. Solutions typicallyinclude squeezing shutoff fluids and mechanicalshutoff using plugs, cement and packers. Patchescan also be used. This problem type is a primecandidate for low-cost, inside-casing water shut-off technology.
Channel flow behind casing—Failed primarycementing can connect water-bearing zones to thepay zone (below middle). These channels allowwater to flow behind casing in the annulus. A sec-ondary cause is the creation of a ‘void’ behind thecasing as sand is produced. Temperature logs oroxygen-activation-based WFL logs can detect this
water flow. The main solution is the use of shutofffluids, which may be either high-strength squeezecement, resin-based fluids placed in the annulus,or lower strength gel-based fluids placed in the for-mation to stop flow into the annulus. Placement iscritical and typically is achieved with coiled tubing.
Moving oil-water contact—A uniform oil-water contact moving up into a perforated zonein a well during normal water-driven productioncan lead to unwanted water production (belowright). This happens wherever there is very lowvertical permeability. Since the flow area is largeand the rate at which the contact rises is low, itcan even occur at extremely low intrinsic verticalpermeabilities (less than 0.01 mD). In wells withhigher vertical permeability (Kv > 0.01 Kh), coningand other problems discussed below are morelikely. In fact, this problem type could be consid-ered a subset of coning, but the coning tendencyis so low that near-wellbore shutoff is effective.Diagnosis cannot be based solely on known entryof water at the bottom of the well, since otherproblems also cause this behavior. In a verticalwell, this problem can be solved easily by aban-doning the well from the bottom using a mechan-ical system such as a cement plug or bridge plugset on wireline. Retreatment is required if the
OWC moves significantly past the top of the plug.In vertical wells, this problem is the first in ourclassification system that extends beyond thelocal wellbore environment.
In horizontal wells, any wellbore or near-wellbore solution must extend far enough upholeor downhole from the water-producing interval tominimize horizontal flow of water past the treat-ment and delay subsequent water breakthrough.Alternatively, a sidetrack can be considered oncethe WOR becomes economically intolerable.5
Watered-out layer without crossflow—Acommon problem with multilayer productionoccurs when a high-permeability zone with aflow barrier (such as a shale bed) above andbelow is watered out (above). In this case, thewater source may be from an active aquifer or awaterflood injection well. The watered-out layertypically has the highest permeability. In theabsence of reservoir crossflow, this problem iseasily solved by the application of rigid, shutofffluids or mechanical shutoff in either the injectoror producer. Choosing between placement of ashutoff fluid—typically using coiled tubing—or amechanical shutoff system depends on knowingwhich interval is watered out. Effective selectivefluids, discussed later, can be used in this case toavoid the cost of logging and selective place-ment. The absence of crossflow is dependent onthe continuity of the permeability barrier.
Horizontal wells that are completed in justone layer are not subject to this type of problem.Water problems in highly inclined wells com-pleted in multiple layers can be treated in thesame way as vertical wells.
34 Oilfield Review
Injector Producer
> Casing, tubing orpacker leaks.
> Flow behind casing. > Moving oil-water contact.
>Watered-out layer without crossflow.
Spring 2000 35
Fractures or faults between injector andproducer—In naturally fractured formationsunder waterflood, injection water can rapidlybreak through into producing wells (above). Thisis especially common when the fracture systemis extensive or fissured and can be confirmedwith the use of interwell tracers and pressuretransient testing.6 Tracer logs also can be used toquantify the fracture volume, which is used forthe treatment design. The injection of a flowinggel at the injector can reduce water productionwithout adversely affecting oil production fromthe formation. When crosslinked flowing gels areused, they can be bullheaded since they havelimited penetration in the matrix and so selec-tively flow in the fractures. Water shutoff is usu-ally the best solution for this problem.
Wells with severe fractures or faults oftenexhibit extreme loss of drilling fluids. If a conduc-tive fault and associated fractures are expectedduring drilling, pumping flowing gel into the wellmay help solve both the drilling problem and thesubsequent water production and poor sweepproblems—particularly in formations with lowmatrix permeability.
In horizontal wells, the same problem canexist when the well intersects one or more faultsthat are conductive or have associated conduc-tive fractures.
faults or fractures that intersect an aquifer(above right). As discussed above, pumping flow-ing gel may help address this problem.
Coning or cusping—Coning occurs in a verti-cal well when there is an OWC near perforationsin a formation with a relatively high vertical per-meability (below). The maximum rate at which oilcan be produced without producing waterthrough a cone, called the critical coning rate, isoften too low to be economic. One approach,which is sometimes inappropriately proposed, isto place a layer of gel above the equilibriumOWC. However, this will rarely stop coning andrequires a large volume of gel to significantlyreduce the WOR. For example, to double the crit-ical coning rate, an effective gel radius of at least50 feet [15 m] typically is required. However, eco-nomically placing gel this deep into the formationis difficult. Smaller volume treatments usuallyresult in rapid water re-breakthrough unless thegel fortuitously connects with shale streaks.
A good alternative to gel placement is to drillone or more lateral drainholes near the top of theformation to take advantage of the greater dis-tance from the OWC and decreased drawdown,both of which reduce the coning effect.
In horizontal wells, this problem may bereferred to as duning or cusping. In such wells, itmay be possible to at least retard cusping withnear-wellbore shutoff that extends sufficientlyup- and downhole as in the case of a rising OWC.
Fractures or faults from a water layer—Water can be produced from fractures that inter-sect a deeper water zone (above middle). Thesefractures may be treated with a flowing gel; thisis particularly successful where the fractures donot contribute to oil production. Treatment vol-umes must be large enough to shut off the frac-tures far away from the well.
However, the design engineer is faced withthree difficulties. First, the treatment volume isdifficult to determine because the fracture volumeis unknown. Second, the treatment may shut offoil-producing fractures; here, an overflush treat-ment maintains productivity near the wellbore.Third, if a flowing gel is used, it must be carefullytailored to resist flowback after the treatment. Incases of localized fractures, it may be appropriateto shut them off near the wellbore, especially ifthe well is cased and cemented. Similarly, adegradation in production is caused whenhydraulic fractures penetrate a water layer.However, in such cases the problem and environ-ment are usually better understood and solutions,such as shutoff fluids, are easier to apply.
In many carbonate reservoirs, the fracturesare generally steep and tend to occur in clustersthat are spaced at large distances from eachother—especially in tight dolomitic zones. Thus,the probability of these fractures intersecting avertical wellbore is low. However, these fracturesare often observed in horizontal wells wherewater production is often through conductive
4. Elphick J and Seright R: “A Classification of WaterProblem Types,” presented at the Petroleum NetworkEducation Conference’s 3rd Annual InternationalConference on Reservoir Conformance ProfileModification, Water and Gas Shutoff, Houston, Texas,USA, August 6-8, 1997.
5. Hill D, Neme E, Ehlig-Economides C and Mollinedo M:“Reentry Drilling Gives New Life to Aging Fields,” Oilfield Review 8, no. 3 (Autumn 1996): 4-17.
6. A fissure is an extensive crack, break or fracture in a rock.
Injector
Producer
Fault
Fault
> Fractures or faults between an injector anda producer.
> Fractures or faults from a water layer (vertical well).
> Fractures or faults from a water layer(horizontal well).
> Coning or cusping.
Poor areal sweep—Edge water from anaquifer or injection during waterflooding through apay zone often leads to poor areal sweep (right).Areal permeability anisotropy typically causes thisproblem, which is particularly severe in sand chan-nel deposits. The solution is to divert injectedwater away from the pore space, which hasalready been swept by water. This requires a largetreatment volume or continuous viscous flood,both of which are generally uneconomic. Infilldrilling is often successful in improving recovery inthis situation, although lateral drainholes may beused to access unswept oil more economically.
Horizontal wells may extend through differentpermeability and pressure zones within the samelayer, causing poor areal sweep. Alternatively,water may break through to one part of the wellsimply because of horizontal proximity to thewater source. In either case, it may be possibleto control water by near-wellbore shutoff suffi-ciently up- and downhole from the water.
Gravity-segregated layer—In a thick reservoirlayer with good vertical permeability, gravity seg-regation—sometimes called water under-run—can result in unwanted water entry into aproducing well (below). The water, either from anaquifer or waterflood, slumps downward in thepermeable formation and sweeps only the lowerpart of the reservoir. An unfavorable oil-watermobility ratio can make the problem worse. Theproblem is further exacerbated in formations withsedimentary textures that become finer upward,since viscous effects along with gravity segrega-tion encourage flow at the bottom of the formation.Any treatment in the injector aimed at shutting offthe lower perforations has only a marginal effect in
sweeping more oil before gravity segregationagain dominates. At the producer there is localconing and, just as for the coning case describedearlier, gel treatments are unlikely to provide last-ing results. Lateral drainholes may be effective inaccessing the unswept oil. Foamed viscous-floodfluids may also improve the vertical sweep.
In horizontal wells, gravity segregation canoccur when the wellbore is placed near the bot-tom of the pay zone, or when the local criticalconing rate is exceeded.
Watered-out layer with crossflow—Watercrossflow can occur in high-permeability layersthat are not isolated by impermeable barriers(below right). Water production through a highlypermeable layer with crossflow is similar to theproblem of a watered-out layer without crossflow,but differs in that there is no barrier to stop cross-flow in the reservoir. In these cases, attempts tomodify either the production or injection profilenear the wellbore are doomed to be short-lived
36 Oilfield Review
because of crossflow away from the wellbore. It isvital to determine if there is crossflow in the reser-voir since this alone distinguishes between thetwo problems. When the problem occurs withoutcrossflow, it can be easily treated. With crossflow,successful treatment is less likely. However, inrare cases, it may be possible to place deep-pene-trating gel economically in the permeable thieflayer if the thief layer is thin and has high perme-ability compared with the oil zone. Even underthese optimal conditions, careful engineering isrequired before committing to a treatment. Inmany cases, a solution is to drill one or more lat-eral drainholes to access the undrained layers.
Horizontal wells completed in just one layerare not subject to this type of problem. If a highlyinclined well is completed in multiple layers,then this problem occurs in the same way as in avertical well.
Knowing the specific water-control problem isessential to treating it. The first four problemsare relatively easily controlled in or near thewellbore. The next two problems—fracturesbetween injectors and producers, or fracturesfrom a water layer—require placement of deeperpenetrating gels into the fractures or faults. Thelast four problems do not lend themselves to sim-ple and inexpensive near-wellbore solutions, andrequire completion or production changes as partof the reservoir management strategy. Any oper-ator wishing to achieve effective, low-risk, rapidpayout water shutoff should initially concentrateon applying proven technology to the first sixproblem types.
Injector Producer Injector Producer
> Poor areal sweep.
> Gravity-segregated layer. >Watered-out layer with crossflow.
Aqui
fer
Cumulative oil, bbl
WOR economic limit
Log
WOR
> Recovery plot. The recovery plot shows the increasing trend in water/oilratio with production. If the extrapolated WOR reaches the economic limitwhen the cumulative oil produced reaches the expected recoverablereserves, then the water being produced is considered good water.
> Production history plot. A time, days plot of the water and oil flowrates against time can be helpful in identifying water problems. Anysudden simultaneous change indicating increased water with areduction in oil is a signal that remediation might be needed.
Spring 2000 37
Well Diagnostics for Water Control In the past, water control was thought of as sim-ply a plug and cement operation, or a gel treat-ment in a well. The main reason for the industry’sfailure to consistently control water has been alack of understanding of the different problemsand the consequent application of inappropriatesolutions. This is demonstrated by the number oftechnical papers discussing the treatments andresults with little or no reference to the geology,reservoir or water-control problem. The key towater control is diagnostics—to identify the spe-cific water problem at hand. Well diagnostics areused in three ways:• to screen wells that are suitable candidates for
water control• to determine the water problem so that a suit-
able water-control method can be selected• to locate the water entry point in the well so
that a treatment can be correctly placed.When a reliable production history is avail-
able, it often contains a wealth of informationthat can help diagnose water problems. Severaldifferent analytical techniques using information,such as water/oil ratios, production data and log-ging measurements, have been developed to dis-tinguish between the different sources ofunacceptable water.
Recovery plot—The recovery plot is asemilog plot of WOR against cumulative oil pro-duction (above). The production trend can be ex-trapolated to the WOR economic limit todetermine the oil production that will beachieved if no water-control action is taken. If theextrapolated production is approximately equalto the expected reserves for a well, then the wellis producing acceptable water, and no water con-trol is needed. If this value is much less than theexpected recoverable reserves, the well is pro-ducing unacceptable water and remedial actionshould be considered if there are sufficientreserves to pay for intervention.
Production history plot—This plot is a log-logplot of oil and water rates against time (belowleft). Good candidates for water control usuallyshow an increase in water production and adecrease in oil production starting at about thesame time.
Decline-curve analysis—This is a semilogplot of oil production rate versus cumulative oil(below). A straight-line curve can be expected fornormal depletion. An increased decline may indi-cate a problem other than water, such as severepressure depletion or damage buildup.
1000
100
10
Oil a
nd w
ater
pro
duct
ion
rate
, B/D
1
0.1120,00080,000 100,00060,0000 20,000 40,000
Cumulative oil, bbl
Water
Oil
> Decline curve. Any sudden change in the slope of the usualstraight-line decline in oil production rate is a warning that excesswater, as well as other problems, may be affecting normal production.
10,000
1000
0
100
10
1
0.1
Time, days
Barre
ls p
er d
ay
10 100 10,0001000
Water flow rate
Oil flow rate
Diagnostic plots—A diagnostic log-log plotof WOR versus time can be used to help deter-mine the specific problem type by making com-parisons with known behavior patterns (left).Three basic signatures distinguish between dif-ferent water breakthrough mechanisms: openflow through faults, fractures, or channel flowbehind casing; edgewater flow or a moving OWC;and coning problems.7 Edgewater flow interpre-tations have been constructed from numericalsimulation and field experience.8 The time-derivative of the WOR also can be used, but theuncertainty or noisy nature of field measure-ments generally limits its application. The inter-pretation engineer can learn to recognize themany variations in these profiles and minimizethe problem of nonuniqueness, when combinedwith other data.
The usefulness of WOR diagnostic plots indetermining multilayer water encroachment isillustrated by an example in a field operated by amajor North Sea operating company. A medium-size reservoir with a moderate-to-high energyshoreface structure had been heavily bioturbated,giving rise to substantial permeability variations(next page, top). No significant shale barriers werepresent, and the 360-ft [110-m] thick reservoirfrom X590 to X950 ft [X180 to X290 m] gentlydipped into an aquifer. The edges of the reservoirwere bounded by sealing faults and truncated byan unconformity. A vertical well was perforatedacross 165 ft [50 m] in the middle of this unit. NoOWC or gas-oil contacts (GOC) were present inthe reservoir.
The WOR-diagnostic plot generated frommonthly well-test data shows the effect of the per-meability variation in the reservoir strata (nextpage, bottom). The plot illustrates watering-out ofhigh-permeability layers, which contribute tocrossflow in the reservoir. The ratio of break-through times (1800:2400:2800) gives an indication
38 Oilfield Review
100
10
1.0
0.1
WOR
WOR
100
10
1
0.0001
0.1
0.01
0.001
WOR
100
10
1
0.000110,0001000100
Time, days
101
0.1
0.01
0.001
WOR
WOR
WOR'
WOR'
WOR
> Diagnostic-plot profiles characterizing water breakthrough mecha-nisms. An open flow path (top) shows a very rapid increase. This profileindicates flow through a fault, fracture or a channel behind casing,which can occur at any time during the well history. Edgewater flow(middle) generally shows a rapid increase at breakthrough followed bya straight-line curve. For multiple layers, the line may have a stair-stepshape depending on layer permeability contrasts. A gradual increase(bottom) in the WOR indicates the buildup of a water cone early in thewell’s life. It normally levels off between a WOR of 1 and 10. The slopeof WOR decreases. After the water cone stabilizes, the WOR curvebegins to look more like that for edge flow. The magnitude of the slope,WOR’, is shown in red in the two lower profiles.
Spring 2000 39
of the permeability ratios in these layers. Thecumulative oil produced and the relative perme-ability-height products of the layers might be usedto estimate the remaining reserves in the lowerpermeability parts of the formation from X590 toX670 ft [X204 m].
The observed WOR response shows that lay-ers with higher permeabilities have watered out.Although there is no direct evidence of verticalconnection between these layers, an understand-ing of the depositional environment and theimpact of bioturbation can help resolve thisissue. Some communication between the high-permeability layers is likely, as well as possiblevertical communication within the remaining low-permeability zone. Any near-wellbore attempt tocontrol water from the high-permeability layerswill depend on vertical isolation over a largeareal extent between the remaining reservesabove X670 ft and the watered-out layers below.This can be confirmed with MDT ModularFormation Dynamics Tester measurements oflayer pressures, vertical interference testing,shale correlations and production logs.
Shut-in and choke-back analysis—The pro-duction history of most wells includes periods ofchoke-back or shut-in. Analysis of the fluctuatingWOR can provide valuable clues to the problemtype. Water-entry problems, such as coning or asingle fracture intersecting a deeper water layerwill lead to a lower WOR during choke-back orafter shut-in. Conversely, fractures or a faultintersecting an overlying water layer has theopposite effect. Such systems are not stableover geologic time but certainly can be inducedduring production.
7. Chan KS: “Water Control Diagnostic Plots,” paper SPE 30775, presented at the SPE Annual TechnicalConference and Exhibition, Dallas, Texas, USA, October 22-25, 1995.
8. Yortsos YC, Youngmin C, Zhengming Y and Shah PC:“Analysis and Interpretation of Water/Oil Ratio in Water-floods,” SPE Journal 4, no. 4 (December 1999): 413-424.
X590
X680
X770
X860
X950300025002000150010005000
Mea
sure
d de
pth,
ft
Horizontal permeability, mD
Wellbore
Perforations
> Horizontal permeability variations in a North Sea reservoir. Significant permeability variation results in effective layer isolation, thereby encouraging preferential flow along high-permeability layers. The well is perforated in the middle sectionof the reservoir.
10
1.0
0.1
0.01
0.0011000 2000 3000 4000 5000
Production time, days
WOR
1
2 34
> Diagnostic plot from monthly well-test data. The plot shows howaquifer water breaks through at about 1800 days (point 1) with asharp increase in WOR corresponding to a sudden water satura-tion change at the flood front. This breakthrough is most likely tobe from the highest permeability layer. The WOR gradually risesuntil 2100 days as normal for edgewater flow. The water inflowstabilizes from point 2 indicating that the layer is virtually wateredout, leading to a constant WOR. This value suggests that the firstlayer to break through contributes approximately 14% of the totalpermeability-height product—the key formation factor determiningthe flow rate. At 2400 days (point 3), the breakthrough of water isseen through the interbedded high-permeability layers. The curveappears to be less steep at this breakthrough because the WORis starting at a higher value. At the end of this period, the WOR isapproximately 0.24, suggesting that 10% of the permeability-height product comes from the second layer, which has wateredout. The last distinctive increase (point 4) represents final break-through of the remaining high-permeability layers.
3000
2000
1000
0
Flow
ing
pres
sure
, psi
Flow rate, B/D1000 2000 3000 4000
Oil Water Total flow rate
Water
Oil
100 mD, 4 ft
20 mD, 20 ft
> Multilayer NODAL analysis. The modeled well (insert) used for the NODAL analysis has two layers, each with a differentthickness and permeability. The multilayer analysis shows theindividual and total flow rates of the oil and water layers as theyare produced together at different pressures.
One well from the Middle East showed a pro-duction rate of 7000 bbl [1112 m3] of water perday and 400 bbl [64 m3] of oil per day after eachshut-in (above). These rates reversed after a fewdays of production. Production data suggest thatthe apparent cause was a conductive fault con-necting the oil reservoir to a shallower watered-out reservoir. In wells with the water source at ahigher pressure than the oil, choking back thewell causes the WOR to increase. The choke-backtest offers a useful diagnostic method to distin-guish between these two problems.
When production history data are of low qual-ity, a short-term production choke-back test canbe performed with several different choke sizes.The pressure should be monitored along withWOR from a separator or, preferably, a three-phase flowmeter, to accurately determinechanges in the WOR with drawdown pressure.This can be performed only if the well has suffi-cient wellhead pressure to flow at several ratesand so should be done early in the life of the well.
NODAL analysis—The design of a productionsystem depends on the combined performance ofthe reservoir and the downhole tubing or reservoir“plumbing” system (above right).9 The amount ofoil, gas and water flowing into a well from thereservoir depends on the pressure drop in the pip-ing system, and the pressure drop in the pipingsystem depends on the amount of each fluid flow-ing through it. The deliverability of a well oftencan be severely diminished by inadequate perfor-mance or design of just one component in the sys-tem. An analysis of a flowing wellbore and theassociated piping, known as NODAL analysis, isfrequently used to evaluate the effect of eachcomponent in a flowing production system fromthe bottom of a well to the separator.
NODAL analysis is also used to determine thelocation of excessive flow resistance, whichresults in severe pressure losses in tubing sys-tems. The effect of changing any component inthe system on production rates can be deter-mined.10 For example, a commonly held belief isthat choking back a well that produces water willreduce the water cut. This is certainly the case forconventional coning. In other cases, it depends onthe problem type as well as the reservoir pres-sures. For example, if a well is shut in for anextended period of time, the WOR (measuredwhen the well is put on line again) will depend onthe water problem and pressures involved.
A 35° inclined North Sea black-oil producer is perforated and producing from five differentlayers. Each layer is known to be isolated fromthe others by impermeable shale barriers with nocrossflow between them. A nearby injector andan aquifer provide pressure support. The wellproduced 29,000 B/D [4608 m3/d] with a watercut of 90%. A recent production log in this wellshows significant shut-in crossflow from lowerlayers into the upper—possibly a thief—layer.NODAL analysis was performed to match the PLTProduction Logging Tool analysis for both shut-inand flowing conditions, thereby providing confi-dence in any prediction of anticipated additionaloil production obtained from various water shut-off treatments (next page, top).
Although NODAL analysis is a standardmethodology for modeling wellbore response,there are two important considerations in its usein this application. First was the need to calibratethe computed flow responses in the face ofaggressive shut-in crossflow, and second, a rela-tively high number of separate layers wereinvolved. The analysis included six steps.
40 Oilfield Review
9. Elphick J: “NODAL Analysis Shows Increased OilProduction Following Water Shutoff,” presented at thePetroleum Network Education Conference’s 2nd AnnualInternational Conference on Reservoir ConformanceProfile Modification, Water and Gas Shutoff, Houston,Texas, USA, August 19-21, 1996.
10. Beggs HD: Production Optimization Using NODALAnalysis. Tulsa, Oklahoma, USA: OGCI Publications, Oil & Gas Consultants International, Inc., 1991.
11. A switch angle determines when primarily verticalmultiphase correlations should be replaced by primarilyhorizontal ones. Is important to note that there are nomultiphase-flow pressure-drop correlations in the publicdomain suitable for all inclination angles.
14,000 1.8
1.6
1.4
1.2
1.0
0.8
0.6
0.4
0.2
0.0
12,000
10,000
8000
6000
4000
2000
0 200 400 600 800 1000
Wat
er/o
il ra
tio
Tota
l liq
uid
rate
, B/D
Time, days
WOR
Liquid rate
> Production rates during choke-back. Production dataduring the choke-back period in a Middle Eastern wellshow that choking back the production rate 50% resultsin a dramatic increase in the WOR.
Laye
rs
Zonal flow rates, STB/D-6000 -4000 -2000 0 2000 4000 6000 8000
Option 1 oilOption 1 water
L1
L2
L3
L4
Option 1 (shut off just Layer 5)
Laye
rs
Zonal flow rates, STB/D0 1000 2000 3000 4000 5000 6000 7000 8000
Option 2 oilOption 2 water
L3
L4
Option 2 (shut off Layers 1, 2 and 5)
NODAL analysis to predict benefits of watercontrol. The two options proposed for this wellwere to either simply shut off Layer 5 with a plugand produce from the upper layers, or shut offLayers 1, 2 and 5, leaving Layers 3 and 4 to produce. The first option (top) would produce an expected net increase in production of 1328BOPD [211 m3/d], whereas the second choice(bottom) predicts a net increase in production of1647 BOPD [262 m3/d]. The second option is moreexpensive and probably requires setting a plugto isolate Layer 5 and cementing Layers 1 and 2.The operator chose option 1.
Spring 2000 41
• Model construction—Basic model constructionrequired a detailed deviation survey, pressure-volume-temperature (PVT) properties, charac-teristics of the reservoir in the near-wellboreregion for each layer and perforation locations.
• Geology—Geological information about thedepositional environment around the well wasnecessary to estimate the degree and lateralextent of impermeable barriers. The wellexhibited good lateral extent of such barriers.Elsewhere in the field, variation in depositionalenvironment caused uncertainty in the continu-ity of permeability barriers, degrading confi-dence in the sustainability of the localizedshutoff treatments.
• Layer pressures—Individual layer pressureswere obtained from shut-in data. Formationskin damage factors were initially assumed tobe zero.
• Correlation selection—A multiphase flow cor-relation comparison was conducted on thebasic system to determine the degree of varia-tion exhibited by the models and the impact ofcorrelation parameters, such as switch angles.11
This step involves matching well-test data.
• Shut-in crossflow—First, the shut-in crossflowexhibited by the PLT tool measurements wasmodeled, enabling skin damage for each layerto be evaluated. The process required a trialand error approach, in which rough estimates(from earlier tests) of each layer’s productionindex were sequentially adjusted to match the
data. Well histories were also consulted todetermine if any skin due to drilling or opera-tional considerations could be expected. In thisexample, none was expected.
• Flowing crossflow—The process was repeatedfor flowing conditions and several rates wereanalyzed. Shutting in all but one net-producinglayer at a time can speed up processing. Theproduction index and non-Darcy skin factors ofeach layer were then adjusted to match thedata. The final calibrated model provided agood match to all the data.
The calibrated NODAL analysis model wasthen used to determine the estimated incremen-tal production for two different shutoff options.The first option would completely shut off all pro-duction from the lowest layer, Layer 5 (below).This option leaves Layers 1 to 4 open, and the netresult is an increase in oil production from 2966 to4294 BOPD [471 to 682 m3/d]. Water productionwould decrease from 26,510 to 12,742 BWPD[4212 to 2025 m3/d]. The second option wouldinvolve sealing off the nonhydrocarbon-producingLayers 1, 2 and 5, and producing from Layers 3 and 4. This option results in oil productionincreasing to 4613 BOPD [733 m3/d], which is onlyabout 300 BPD [47 m3/d] more than option 1. The
Laye
rs
Zonal flow rates, STB/D-5000 0 5000 10,000 15,000 20,000
Calculated oilCalculated water
Measured oilMeasured water
L1
L2
L3
L4
L5
>Matching NODAL analysis with production measurements. The bluebars represent water flow while the green bars are oil flow measured byproduction logging tools. The circles represent the results of the NODALanalysis. Layers 2 and 5 are fully watered out. Layer 1 is taking on waterand some oil, as indicated by the negative flow rates, because it haslower in-situ reservoir pressure than the flowing wellbore pressure.
difference between current performance and thatpredicted from shutting in one or more layers wasused as the basis for justifying the treatments.
The production log data showed that waterwas being produced from all but one of the upperlayers. Most of the unwanted water came fromthe lowest layer. Because of reduced formationpressures, the uppermost layer was stealing asmall quantity of the oil and water being pro-duced below. As expected, the liquid volumesentering this thief zone decreased as productionincreased. At the expected high production ratessuch losses were considered tolerable. The oper-ator decided on option 1, setting a plug justbelow Layer 4, completely isolating Layer 5.
Production logs—Accurate production logs,such as those from the PS PLATFORM ProductionServices measurements can show water entryinto the wellbore.12 This tool can determine flowand holdup for each fluid phase in vertical, devi-ated and horizontal wellbores.13 The addition ofnew optical and electrical sensors incorporatinglocal probe measurements and phase-velocitymeasurements have resulted in major improve-ments in the diagnosis in both complex and sim-ple wells with three-phase flow. Such advancesin reliable and accurate production logging, par-ticularly in deviated wells with high water cuts,represent a major step forward in identifying andunderstanding water-problem types.
For example, an operator drilled a horizontalwell in the Gulf of Mexico through a small gassand that was producing excessive water after ashort time on production. In this well, the mostlikely source of the unacceptable water wasthought to be edge water from the lower aquifer.If the edge water was entering at the heel of thewell, then a cost-effective solution would be torun coiled tubing into the well and cement theportion around the heel, leaving the coiled tubingin place to allow production from the toe of thewell. This would delay further water productionuntil the water advanced past the cement plug.However, if water was coming from the toe of thewell, then it was possible to cement the lowerportion of the well using coiled tubing and apacker in the screen. A final scenario, waterentering from the middle of the well, would makeit difficult to isolate the water entry and continueproduction from the toe and heel. The operatorneeded to know the exact entry point of thewater production to take proper remedial action.
The logging program included the basic PSPLATFORM tool string along with the GHOST GasHoldup Optical Sensor Tool and the RSTProReservoir Saturation Tool run on coiled tubing.The GHOST, FloView holdups and spinner-derivedfluid velocity represent fluids inside the com-pletion screen, while the TPHL log and WFLmeasurements respond to flow both inside andoutside the screen (left).
The WFL water velocity measurements arecombined with the GHOST and TPHL holdup mea-surements to calculate the water flow-rate pro-file. In this example, more than 50% of the waterproduction is coming from the toe of the well,flowing behind the screen and in the openholegravel-pack annulus. The GHOST measurementalso identified additional water entering midwayalong the horizontal wellbore at X450 ft [X137 m].Since most of the gas is coming from the toe ofthe well, the operator decided to continue pro-duction without further intervention.
42 Oilfield Review
Measureddepth, ft
X200
X300
X400
X500
X600
Devi > 90° Gas
Water
TPHL TPHL
True vertical depthftX070 X055
Gas
GHOST
Holdup1 0
WaterWater profile
WFLwater flow rate
1 0
Deviation
Gamma rayAPI20 70
85 95deg WFLwater velocity
ft/min0 500
Gas profile
Gas flow rateB/D B/D0 1200 0 25,000
Gas
Holdup
Water
Waterentry
Waterentry
> Downhole flow profile. Track 1 contains gamma ray (green) and wellbore deviation (solid black) fromopenhole logs. The measured depth is shown in track 2. In track 3, gas (red) and water holdup (blue)measured by the GHOST Gas Holdup Optical Sensor Tool clearly identify water entering the horizontalsection of the wellbore at X450 ft and X640 ft. Track 4 shows gas (red) and water (blue) contributionsacross the entire wellbore and annulus, which is plotted against the wellbore trajectory profile. Theseindependent phase holdups are derived from the TPHL three-phase holdup log. Increasing water in theprofile can be seen as the wellbore turns more vertical above X350. Track 5 shows TPHL gas (red) andwater (blue) holdup logs. The WFL Water Flow Log water-velocity measurements (blue circles) areshown in Track 6. Track 7 contains a water flow-rate profile computed from the TPHL holdup and WFLvelocity. Track 8 contains the gas flow-rate profile computed using GHOST holdup data.
Spring 2000 43
Through-casing imaging tools, such as the USIUltraSonic Imager tool can help evaluate thequality of the cement job in a well and identifyflow channels behind casing. For example, in awell in New Mexico that was producing onlywater, the existence of a channel above the per-forations was confirmed (above). The well beganproducing oil after a cement squeeze and is cur-rently flowing 50 BOPD [8 m3/d] and no water.
Special Diagnostics for Vertical CommunicationWater crossflow has two clearly defined forms. Inaddition to crossflow in the reservoir, which hasalready been discussed, crossflow also occursinside the wellbore. Both kinds of crossflow areinterdependent and deserve careful consideration.
A potential for wellbore crossflow existswhenever the wellbore penetrates multiple lay-ers at different pressures. The pressure differ-ence is maintained only when and where there iscontinuous isolation between each layer. Thisimplies that reservoir crossflow and wellborecrossflow are mutually exclusive for any pair oflayers. Some reservoirs, for example those withstacked sand channels, have local shale barriersextending hundreds of meters. However, suchreservoirs may contain globally distant verticalconnections that lead to crossflow and pressurecommunication even though they exhibit localisolation with transient pressure variationsbetween layers during a choke-back test. Thisgives a mixture of the watered-out layer prob-lems with and without crossflow.
Identifying the presence of crossflow in theformation is critical. Watered-out layers withoutcrossflow can be easily treated at the wellbore,
while there are no simple solutions if the layersare not isolated by impermeable barriers.Additionally, watered-out layers without cross-flow will be subject to crossflow within the well-bore during shut-in. Several diagnostic methodsare useful in determining vertical communication.
Multirate tests—With little additional effort, aproduction log can be turned into a multirate pro-duction log, or ‘multilayer test,’ by measuring theproduction rate of each layer at several differentproducing pressures with station measurementspositioned between each layer. This helps deter-mine the productivity index and average reservoirpressure for each layer.14 In this way, crossflowpotential can be assessed using NODAL analysis.
Wireline-conveyed formation testers—Wireline formation pressure measurements,such as those from the MDT tool or the RFTRepeat Formation Tester tool can show if the lay-ers are in pressure communication.15 If layershave different pressures and are not in wellborecommunication, then they are isolated (below). Ifthey show the same pressure, they may be incommunication or they may have simply beenproduced (and injected) at similar rates, givingthe same pressure.
12. Lenn C, Kuchuk F, Rounce J and Hook P: “Horizontal WellPerformance Evaluation and Fluid Entry Mechanisms,”paper SPE 49089, presented at the SPE Annual TechnicalConference and Exhibition, New Orleans, Louisiana, USA,September 28-30, 1998.
13. Akhnoukh R, Leighton J, Bigno Y, Bouroumeau-Fuseau P,Quin E, Catala G, Silipigno L, Hemmingway J, HorkowitzJ, Hervé X, Whittaker C, Kusaka K, Markel D and Martin A: “Keeping Producing Wells Healthy,” Oilfield Review 11, no. 1 (Spring 1999): 30-47.
14. Hegeman P and Pelissier-Combescure J: “ProductionLogging for Reservoir Testing,” Oilfield Review 9, no. 2(Spring 1997): 16-20.
15. AL Shahri AM, AL Ubaidan AA, Kibsgaard P and Kuchuk F:“Monitoring Areal and Vertical Sweep and ReservoirPressure in the Ghawar Field using Multiprobe WirelineFormation Tester,” paper SPE 48956, presented at theSPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA, September 27-30, 1998.
X100
X200
X300
Depth, ft
Channel Channel
Perforations
> A channel that produces water. The image ofthe cement in the annulus behind casing helpedto identify a water channel. The USI UltraSonicImager tool images—amplitude (track 1) andtransit time (track 2)—confirm that a large openchannel exists in the cement annulus behind thecasing just above the perforations.
X100
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5200 5400 5600 5800 6000 6200 6400
X300
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X500
X700
X400
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X200Upper Jurassic
Tarbut
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Initialreservoirpressures
> Pressure measurements showing layer isolation. Pressure measure-ments, such as those from the MDT tool, can be used in in-fill wells toestablish the pressure in each layer after a period of production in thefield. When pressure differences exist between layers due to differen-tial depletion, they show that the layers are isolated from each otherby vertical permeability barriers.
Vertical interference test—A vertical inter-ference test performed with the MDT tool willshow effective vertical permeability near thewellbore. Vertical permeability can be deter-mined from the change in formation pressuremeasured by a pressure probe, as formation fluidis pumped from the formation by a second (sam-pling) probe located about 2.3 ft [0.7 m] fartheralong the wellbore face.16
Shale correlations—Log correlations candemonstrate whether extensive shale barriersexist across a field. Excellent shale correlationsfrom well to well suggest that reservoir layersare isolated by impermeable rock and that cross-flow is unlikely.
Spinner survey during shut-in—A productionlog (spinner) may detect wellbore crossflow dur-ing well shut-in, a clear sign of a pressure differ-ence between isolated layers.
Choke-back test—Choke-back tests or produc-tion data can provide a useful diagnosis of verti-cal communication through the detection ofpressure differences.
Water-Control SolutionsEach problem type has solution options thatrange from the simple and relatively inexpen-sive mechanical and chemical solutions, to themore complex and expensive reworked comple-tion solutions. Multiple water-control problemsare common, and often a combination of solu-tions may be required. Today, in addition to thetraditional solutions described above, there arenew, innovative and cost-effective solutions forwater-control problems.
Mechanical solutions—In many near-wellbore problems, such as casing leaks, flowbehind casing, rising bottom water and watered-out layers without crossflow, mechanical orinflatable plugs are often the solution of choice.The PosiSet mechanical plugback tool can bedeployed on coiled tubing or wireline, and is afield-proven technology that ensures reliablewellbore shutoff in cased- and openhole environ-ments (right).
When the wellbore must be kept open tolevels deeper than the point of water entry, athrough-tubing patch may be the answer. Forexample, a new coiled tubing- or wireline-deployed, inside-casing patch called the PatchFlexsleeve has been used successfully in many appli-cations worldwide (far right). It is particularly wellsuited to through-tubing water or gas shutoff,injection-profile modifications and zonal isolation.The inflatable sleeves are custom-built to matchthe length of the perforated intervals and can
withstand wellbore crossflow pressures. Once set,the sleeve becomes a composite liner inside thecasing that is millable using through-tubing tech-niques if a subsequent squeeze operation isdesired, or it can be reperforated later to allowreentry to the zones. The only disadvantage of thecomposite liner is a reduction of less than 1 in. [2.5 cm] in the wellbore diameter. However, othermechanical patch remedies take up even more ofthe available casing inner diameter.
Shell UK Exploration and Production reducedwater cut in a North Sea well from 85% to 10%by using a PatchFlex sleeve to isolate the water-producing intervals. The PS PLATFORM loggingtool quantified fluid contributions from each pro-ducing zone. Two 4-ft [1.2-m] perforated intervalswere identified as producing most of theunwanted water. The RST readings confirmed the
44 Oilfield Review
> PosiSET mechanical plugback tool application.The PosiSET through-tubing plug is used fornear-wellbore water shutoff. The wireline- orcoiled tubing-deployed plug uses a positiveanchoring system with upper and lower slip-anchors (top) that isolate water-producing layers in both open and cased holes (bottom).
> The PatchFlex sleeve. A flexible compositecylinder made of carbon fiber, thermosettingresins and a rubber skin, the PatchFlex sleeve isbuilt around an inflatable setting element that isattached to a running tool and run into a well on a wireline. When the sleeve is positioned oppositethe area to be treated, a pump within the runningtool inflates the sleeve using well fluid. The resinsare then heated until fully polymerized. The inflat-able setting element is then deflated and extractedto leave a hard, pressure-resistant sleeve that fitssnugly, even in damaged or corroded casing.
Spring 2000 45
high water saturation in the water-producingintervals. In addition, the RST saturation analysisidentified two more unperforated oil zones belowthe other producing zones. A traditional bridgeplug could shut off the water-producing zone, butwould also block the new oil zones beneath.Using PatchFlex technology, Shell shut off thewater-producing zones and produced the new oilzones below them.
Chemical solutions—Chemical treatmentsrequire accurate fluid placement. Coiled tubingwith inflatable packers can help place most treat-ment fluids in the target zone without risk to oilzones. Coiled tubing dual injection is a process ofpumping protective fluid down the coiled tubingto the casing annulus and delivering the treat-ment fluid through the coiled tubing (right).
SqueezeCRETE cement is another keyweapon in the armory of water-control solu-tions.17 Its low fluid loss and capability to pene-trate microfractures narrower than 160 micronsmake it ideal for remedial treatment of tubingleaks caused by flow behind pipe. Once set, thiscement shows high compressive strength, lowpermeability and high resistance to chemicalattack. SqueezeCRETE treatment is often usedwith common cement for shutting off perfora-tions when the problem is watered-out layers, orrising bottom water or OWCs. Other applicationsinclude sealing gravel packs, casing leaks orchannels behind casing.
Rigid gels are highly effective for near-wellbore shutoff of excess water (right). Unlikecement, gels can be squeezed into the target for-mation to give complete shutoff of that zone or toreach shale barriers. They have an operationaladvantage over cement treatments because theycan be jetted rather than drilled out of the well-bore. Typically based on cross-linked polymers,products like MaraSEAL and OrganoSEAL-Rsystems can be easily mixed and have a longworking life. They can be bullheaded into the for-mation to treat specific water problems such asflow behind casing and watered-out layers with-out crossflow, or selectively placed in the waterzone using coiled tubing and a packer.18
Another solution is a flowing gel that can beinjected into small faults or fractures, but onlypenetrates formations with permeabilities greaterthan 5 darcies. Large volumes (1000 to 10,000 bbl)[159 to 1589 m3] of these inexpensive fluids oftensuccessfully shut off extensive fracture systemssurrounding waterflood injector or producing
wells.19 Like rigid gels, products such as Marcitand OrganoSEAL-F systems are cross-linked poly-mers that are simple to mix, have a long (up tothree days) working time before becoming rigid,and can be pumped through completion screens.
Smart or selective fluids in the form of poly-mers and surfactants are being developed for for-mation matrix treatments near the wellbore.These treatments, called relative permeabilitymodifiers, produce a permanent gel-like material
16. Crombie A, Halford F, Hashem M, McNeal R, Thomas EC,Melbourne G and Mullins OC: “Innovations in WirelineFluid Sampling,” Oilfield Review 10, no. 3 (Autumn 1998):26-41.
17. Boisnault JM, Guillot D, Bourahla A, Tirlia T, Dahl T,Holmes C, Raiturkar AM, Maroy P, Moffett C, Mejía GP,Martínez IR, Revil P and Roemer R: “Concrete Develop-ments in Cementing Technology,” Oilfield Review 11, no. 1 (Spring 1999): 16-29.
18. These gels will not penetrate formations with perme-ability less than 25 mD.
19. O’Brien W, Stratton JJ and Lane RH: “MechanisticReservoir Modeling Improves Fissure Treatment GelDesign in Horizontal Injectors, Idd El Shargi North DomeField, Qatar,” paper SPE 56743, presented at the SPEAnnual Technical Conference and Exhibition, Houston,Texas, USA, October 3-6, 1999.
> Coiled tubing dual injection. In water-control problems where the treatment fluid placement is critical, a coiled tubing-conveyedinflatable packer (A) can be used to provide wellbore isolationbetween the oil (B) and watered-out (C) zones. In this gravel-pack example, a treatment fluid (D) to stop unwanted water entry ispumped through the coiled tubing into the lower watered-out zoneand a protective fluid (E) is simultaneously pumped through theannulus into the oil-producing zone.
> Rigid-gel application using coiled tubing. Pumping a rigid gel (A)into the watered-out zone can shut off water entry from a layerwithout crossflow. A coiled tubing inflatable packer (B) isolates the oil-producing zone (C) from the watered-out zone (D).
Oil zone B
Watered-out zone C
A
D
D E
E
Treatment fluid
Protective fluid
Tubing
Coiled tubing
PackerGravelpack
Packer
Casing
Oil zone C
Watered-out zone D
Barrier
Tubing
Coiled tubing
Packer
Casing
Packer B
A Rigid gel
to stop flow in water layers, but retain fluid behav-ior in oil layers to allow production to continue. Insome applications, they offer the potential of per-forming a selective treatment simply by using alow-cost bullheading method of placement.
Treatments for water problems in horizontalwells are most effective when the treatmentzone is isolated from the remainder of the well-bore. In cased holes, and to some extent in open-holes, this is achieved mechanically withinflatable packers. However, when a screen orliner has been run but left uncemented, suchmechanical devices are not effective in isolatingthe open annular space behind the pipe.Developed for such situations, the AnnularChemical Packer (ACP) achieves zonal isolationusing coiled tubing-deployed packers or bridgeplugs (right).20 The objective of the ACP is toachieve full circumferential coverage over a rela-tively small length while leaving the liner free ofmaterial that might obstruct fluid flow or toolpassage through the section. A low-viscosity,cement-based fluid is pumped through coiled tub-ing and a straddle-packer assembly and placedthrough the small slots in the pipe. Once placed,the fluid immediately develops high gel strengthto prevent slumping and ensures complete annu-lar filling and isolation.
Completion solutions—Alternative comple-tions, such as multilateral wells, sidetracks,coiled-tubing isolation and dual completions, cansolve difficult water problems such as risingOWCs, coning, incomplete areal sweep andgravity segregation.21 For example, coproducingwater is a preferred strategy for coning in high-value wells. It involves perforating the water legand using dual completions (below).
Injector ProblemsInjectors can induce problems if the injectionwater is not properly filtered, because it maycontain particles large enough to cause matrixplugging. Or, if it is not treated properly withproduction chemicals such as bactericide andoxygen scavengers, damage can build up. Both ofthese can increase injection pressure until a frac-ture is initiated. Initially short, these fractureswill grow in length and height to maintain injec-tivity as the fracture faces become plugged.22
When induced fractures extend vertically overseveral layers, the operator no longer has controlover the vertical sweep. It is difficult to regaincontrol of the injection profile.
Thermal fracturing, often encountered off-shore, is caused by the stress reduction in theinjection zone from cool-down. The zone with the highest injectivity cools down first and then fractures—taking even more injection fluid andcausing poor vertical sweep (below). In thesecases, it is difficult to avoid thermal fracturing.The best strategy may be to ensure that all zonesare fractured, either thermally or hydraulically, toensure a more even injection profile. Sometimesif a high-permeability layer is adjacent to a low-permeability layer, the thermal fracture can breakinto the high-permeability zone, taking all theinjection water and leaving the low-permeabilityzone unswept.
46 Oilfield Review
> Annular Chemical Packer. ACP technology involves placement of a cement-based fluid into the annular space between an uncemented slotted liner andthe formation. The fluid is conveyed to the treatment zone using coiled tubingand injected between an inflatable packer assembly to fill the annulus over aselected interval. It is designed to set in this position forming a permanent,impermeable high-strength plug, fully isolating the volume of the annulus.
> Fighting water with dual drains. One solution to water-coning problems (left) is to perforate the water legof the formation and coproduce (middle) the water to eliminate the water cone. This low-cost approachmay increase the water cut, but improves the sweep efficiency and long-term reserve potential. Alternatively, the water and oil can be produced separately through the tubing and annulus (right).
> Thermal fracturing in an injector well.Fractures can be initiated in injector wellsthrough pressure and thermal stressinduced by cold-water entry. As a result,the vertical sweep profile is compromised.
Descaling
not
successful
Resetplug
Plug set
OK
Plug not
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OK
Decision tree for a well with scale. The decision tree presents different possiblescale treatment outcomes represented bybranches with the economic losses or profitsand the probabilities of reaching the end ofeach branch. Circular nodes (yellow) representchance nodes where two or more possibleoutcomes exist. The outcome of each branchis independent of any other node, and theprobability of each branch is described by a unimodal probability distribution (green)computed from Monte Carlo simulations.Square nodes (blue) represent decisions in which the branch selected is a matter of choice, with no element of chance. Thebranch endings represent revenues—calledvalue maximization. These help compare different scenarios in an optimal allocation of scarce resources.
Spring 2000 47
Evaluating RiskJustification of a treatmentin any well is based on the valueof the increased hydrocarbon produc-tion expected. The key word here is‘expected,’ which indicates a degree of uncer-tainty in the analysis. Some water-control treat-ments can guarantee substantial productionincrease. In such circumstances, the primary ele-ment of uncertainty is the job success itself. Whenthe incremental production is relatively small (orwas based on several assumptions) not only doesjob-risk come into play, but also the prediction itselfbecomes a key risk. Therefore, the value of a water-control treatment to the operator needs to be quan-tified. An analysis incorporating the multifacetedcomponents of risk can be undertaken using themethods of quantitative risk analysis (QRA).
D e c i s i o ntrees are valuable
tools to visualize andquantify all the options avail-
able to a decision-maker and theprobability of their outcomes. As an illus-
tration, PrecisionTree, provided by PalisadeCorporation, is a decision-analysis program usedwith the Excel spreadsheet program. The softwarecan be coupled to Monte Carlo methods, furnishinga ‘risked decision tree’ to analyze water-controloptions for specific wells (above).
Field-Wide Water ControlWater-control problems, diagnostic techniquesand solutions have been discussed in the contextof their application to individual wells within afield. However, if diagnostic techniques are modi-fied and extended to large number of wells in a
field, then there is greater reduction in total fieldwater handling and, in many cases, signifi-
cant enhancement in total field hydro-carbon production. By combining
the correct diagnosis withthe application of proven
solutions, water control can be aneffective reservoir management tool.
It is possible to apply individual wellwater-control strategies to a number of wells
within a field; however, in large fields, this canbecome time-consuming and inefficient. The firstobjective in a field-wide water-control program isto screen wells with the following characteristics:• The well is accessible for intervention.• The completion is robust enough to tolerate
intervention.• There is economic value to reducing water pro-
duction from that well.• The well has a water-control problem that can
be treated economically with acceptable risk.Field-wide water-control strategies often are
different from those applied on a well-by-wellbasis. For example, completion designs that haveworked effectively on single wells may need to bemodified for field-wide improvements. In one case,a South American operator was producing from alayered reservoir with distinct flow units separated
20. Elphick J, Fletcher P and Crabtree M: “Techniques forZonal Isolation in Horizontal Wells,” presented at theProduction Engineering Association Meeting, Reading,England, November 4-5, 1998.
21. Hill et al, reference 5. 22. Injectivity is a measure of how much liquid can be pumped
in a well (or zone) with a given difference between theinjection fluid pressure and formation pressure.
by shales. The operator perforated all layers andignored the variable pressures across the differentlayers. Eventually, water appeared at several lay-ers in different wells, and the subsequent pressuredepletion caused decreased oil production in theremaining layers. Originally, the operator simplyshut off water in the offending layers where thelocal geology was favorable, but field productioncontinued to decline because of increased occur-rence of water breakthrough and possible cross-flow through discontinuities in the shale barriers.Using a field-wide water-control strategy, the oper-ator moved away from commingled to single-layerproduction in each well, so that the crossflow couldnot occur and full effective drawdown on the lowoil-pressure layers was achieved. This meansfewer wells were draining each layer, but the fieldwas being swept more efficiently.
Field-wide considerations also include thecollective influence of inflow performance ofmany wells. Local and regional geology—interms of structure and heterogeneity—influencefluid movement. For example, the hydraulic rela-tionships between producers and aquifers orinjector wells should be considered (left). Currentand future completion strategies also are impor-tant factors in the analysis. Clearly, a lengthyscoping, or screening, study is not required everytime a field-wide water-control project is under-taken. Nor should a scoping study simply be asifting mechanism for finding treatable wells.The study must fit the problem, and the operator’sextensive knowledge can often help augmentand expedite the study.
Every water-control scoping study uses engi-neering diagnostic tools to identify which wellshave high value and can be effectively treated atlow risk. The scoping study consists of twophases, the diagnostic phase and the solutionsphase. The diagnostic phase uses the operator’sregional expert knowledge and experience cou-pled with Schlumberger engineering and soft-ware to profile the nature and cause of theproblem. Wells are initially screened to select afocus area within the field, then again to identifywells that might benefit from some type of inter-vention, and finally to choose wells that are ofsufficient value to justify treatment.
WaterCASE software-based methodologyscreens candidate wells on the basis of existingdata such as production histories, existing pro-duction logs, reservoir characterization from bothnumerical and analytical models and offset treat-ment data and experience (next page). One recentstudy provided by Schlumberger in the North Seaillustrates the results of the screening process.Here a field contained nearly 100 wells with
water cuts ranging from 20% to 90%, and a fieldaverage of 60%. The scoping study made the fol-lowing determinations:• 15 wells are subsea, requiring a rig for inter-
vention, and 6 have production tree or ‘fish-in-hole’ problems, making intervention difficult.
• Of the remaining 85 wells, 20 have corrodedtubulars, increasing intervention risk.
• Of the remaining wells, 25 have significantpotential for additional productivity if thewater cut is reduced.
• Of these 25 wells, 15 have solvable problemsconsisting of casing leaks, flow behind pipe,bottom water, high-permeability layers withoutcrossflow, or fractures from injector to producer.
The results identify primary candidate wellsto take through to the second phase of the inter-vention process—developing a solutions plan.
In this phase, a spectrum of solutions includ-ing mechanical, fluid and completion options isdeveloped. The solutions spectrum is ranked byrisk, cost and benefit using Schlumberger quanti-tative risk analysis (QRA). Solutions range from‘quick hit and rapid pay’ to longer duration,‘higher cost with higher pay’ solutions.Schlumberger works jointly with the operator’sasset team to identify the most cost-effective,lowest risk and highest value treatment optionfor each well. The chosen solution for each can-didate well is fully engineered for final submis-sion and peer review prior to execution.
To maximize field-wide cost reductions, sur-face-related water-control services (page 50)should be included in the overall screening pro-cess. An integrated solution is often a combina-tion of borehole, reservoir-scale and surfacesystems. Surface facilities may contribute up to25% reduction in overall water-handling costs.
Field-Wide ProblemsEventually most oil fields are under a waterdriveeither from waterflood or a natural aquifer. Anyattempt to significantly increase the recovery fac-tor must increase at least one of the componentsof the recovery factor: displacement efficiency,areal-sweep efficiency or vertical-sweep effi-ciency. The first, displacement efficiency, can beimproved only by reducing the residual oil satu-ration with a surfactant, miscible flood or water-alternating-gas scheme. Water control improvesareal- or vertical-sweep efficiency.
Any analysis of water sweep at a field scalerequires an understanding of the geology andproper reservoir characterization. Reservoir char-acterization, particularly heterogeneity, is poorlyunderstood early in the life of the field, but grad-ually improves as dynamic production databecome available.
48 Oilfield Review
1 year
2 years
5 years
10 years
> Streamline simulation. History-matchedFrontSim water-flow streamline simulations canbe used to show well interactions and detail theexact fraction of water that flows between theinjector and producer wells. In this example with10 producers (red circles) and 5 injectors (bluecircles), the model helps visualize where injectionwater is going at 1, 2, 5 and 10 years. Unsweptregions (blue) are clearly visible near the centerof the reservoir.
>WaterCASE screen. Here a typical user interface asks spe-cific questions (left) about symptoms and diagnostic testresults that help process analysis of the water-control prob-lem. Once a sufficient set of answers is completed, problemtypes are identified and ranked by score (right) according totheir likelihood of incidence. The WaterCASE logical structureis shown superimposed above the screen display.
Spring 2000 49
In calm depositional environments such asshallow marine, continuous shales are often pre-sent, providing good vertical isolation betweenlayers, and making vertical sweep improvementpractical. Any problem with watered-out layerswithout crossflow is easily corrected at the well-bore, and in this environment, this problem dom-inates the more difficult problem of watered-outlayers with crossflow.
Eolian sands, often thick with good verticalpermeability, pose different problems for watercontrol. They can exhibit gravity fluid segre-gation, causing unwanted water entry into pro-ducing wells.
Fluvial and deltaic depositional environmentstypically create sand channels. These may varyfrom well-stacked sands with good horizontaland vertical continuity to isolated channels withpoor communication. Since various problemtypes can occur in this setting, good sand char-acterization is important.
Carbonate reservoirs have their own chal-lenges, including frequent natural fractures lead-ing to water entry from a water layer, or throughfractures connecting injectors and producingwells. Additionally, large dissolution channelsfrom underground water flow, sometimes severalmeters across, can create superhighways to flow,often with premature water breakthrough. These
may be considered subsets of fracture-inducedwater problems. Shutting off this type of channelis extremely difficult.
Many operators are reluctant to proactivelycontrol water prior to breakthrough, so mostaction is remedial. Proactive water control wouldinclude choking back zones with higher permeabil-ity to create a more uniform sweep, but this wouldmean sacrificing early cash flow for an uncertainreturn due to incomplete knowledge of hetero-geneity. However, the production (and injection)profile can be improved through selective stimula-tion of zones with lower permeability. This is a
Typical surface water facilities and relativecosts. The surface water-management facilitiesinclude primary oil, water and gas separators,water-polishing systems to remove residual oil from the water, solids-filter systems as well as chemical treatments. These ensure that thereinjected water is compatible with the receivingformation and does not cause other problemssuch as scale deposits and corrosion in the well-bore system, and reservoir damage. Also shownare typical relative water-cycle costs from theproducing well (lifting costs of 17%), chemicals13%, removal and processing costs (includingseparation 9%, de-oiling 14%, and filtering 15%),pumping 27% and finally reinjection well costs5%. Estimates of average water-handling costs of 50 cents per barrel were based on the assump-tion that the fields were onshore and the wellswere 6000 to 8000 feet [1828 to 2438 m] deep, andproducing 1000 BOPD [159 m3/d] and injecting5000 BWPD [795 m3/d].
particularly attractive option because of the capa-bility of using coiled tubing to precisely placesmall hydraulic fractures. The improvement in hor-izontal drilling techniques, including multilateralsand coiled tubing, also is allowing a greater rangeof viable solutions for complex reservoir problems.However, the predominantly reactive mode forwater control, and hence sweep improvement, islikely to continue until more precise early reservoircharacterization is achieved.
Based on knowledge—or even a rough esti-mate—of the reservoir volume and the frac-tional-flow curve, the expected recovery can beestimated assuming production continues to agiven water cut. By comparing the expectedrecovery with the ultimate recovery indicated bythe WOR semilog plots, one can use field-widediagnostics to estimate how well the reservoir is
being swept. If the WOR is less than the frac-tional-flow curve indicates, then there isbypassed oil (above).23 If the oil production isaccelerated, then it must account for its time-delayed value when calculating net presentvalue—the value of the oil as it is producedminus its value when it would have been pro-duced. If the oil is incremental, then the water-control operation can assume all the value tohelp justify the costs of operation. Incrementaloil is often more valuable than accelerated oil.
Surface Facilities Surface facilities separate water from oil and pro-cess it to an acceptable specification suitable fordisposal to the environment or for reinjection(below). Gas is sent to a gas-processing plant or
simply flared, while the oil is processed in a‘water-polishing’ stage in which water is removedfrom the oil down to the 0.5 to 1.0% level, depend-ing on delivery requirements. Water is reinjectedfor both disposal and pressure maintenance. In atypical water-treatment facility for injection pur-poses, all water streams from each stage of sepa-ration are further de-oiled to a level compatiblewith discharge to the environment or receiving for-mation, typically between 10 and 40 ppm. Thisincludes filtering through a 10- to 50-micron filterto remove solids, making the water more compat-ible with the formation prior to reinjection.
Chemical treatments including emulsionbreakers, biocides, polyelectrolytes and oxygenscavengers are added to the water to condition itfor reinjection, and corrosion inhibitors and anti-scale chemicals are added to protect tubularsand downhole equipment. When water is pro-duced at high rates, chemical additives consti-tute up to 20% of the surface water-handlingcosts. Surface equipment and facilities accountfor the remaining 80%.
In practice, surface solutions start downhole.Partial downhole oil-water separation in the well-bore can eliminate some of the costs of liftingwater. An alternative to simultaneous downholeseparation and reinjection is downhole segre-gated production whereby water and hydrocar-bons are produced separately—avoiding the needfor surface separation capability. Finally, chemicaltreatments, such as emulsion breakers, antiscaleand corrosion inhibitors injected downhole canprepare fluids for efficient surface treatment.24
50 Oilfield Review
1.0
0.75
0.5
0.25
0.00 10 20 30 40 50 60 70
Frac
tiona
l flo
w, w
ater
-cut
frac
tion
Water saturation, %
A B
Water cut 95%
Final formationwater saturation,38%
Final formationwater saturation,58%
Fractional-flow prediction.The two fractional-flow plotsshow how a multilayer reservoirmight perform under differentassumptions. The two curvesshow a large difference in thefinal formation water-saturationvalue at the same water-cutflow rate. Assuming that reser-voir layers water out accordingto their flow capacity, Curve Ashows a substantial amount ofoil still remaining in the forma-tion. Assuming layers water out from bottom to top, Curve Bshows nearly all the oil isrecovered.
>
>
Spring 2000 51
Well pad factory concept—Existing separa-tion technologies and multiphase pumping arereadily available for commercial use as a “wellpad factory.” Oil, water and gas are separatedclose to the wellhead area and the unwantedwater and gas are reinjected for pressure main-tenance or disposal with multiphase pumps.
Conventional surface facilities—Conven-tional gravity-separation facilities can bedesigned for specific production profiles. Withbest practices and technologies, surface facili-ties can provide substantial savings in the water-removal chain (right). For example, centrifugalseparation performed by Framo Engineering—technology derived from multiphase pumpingpractices—could soon provide important opera-tional and capital savings by reducing theamount and size of equipment, and chemical-injection costs. Centrifugal separation could beextended to the well pad factory. Other specificwater-conditioning technologies used to reducethe concentration of water in oil to extremely lowlevels include water polishing, which can reducethe water content down to the 40 ppm level;ultrapolishing systems that reduce the waterdown to the 5 ppm level; and fine solids removalto filter debris such as sand down to 2-micronparticle size.
As worldwide daily water productionincreases, surface facilities, which were not orig-inally designed to handle large volumes of water,are being retrofitted with equipment that canhandle higher water fractions economically.Today, some reservoirs are being produced cost-effectively with over 95% water cut. In well-known reservoirs, such improvements inwater-handling services at surface facilities areunlocking additional recoverable reserves.
The LASMO Plc Apertura project in the Daciónfield in Venezuela is an example of a water-controlstrategy used to improve the economics of field-wide oil production by reducing the bottlenecks inthe water-handling capabilities of surface facili-ties. Managed by the LASMO-Schlumbergeralliance, the project, which began in April 1998,consists of three phases:• Complete an intensive upgrading and debottle-
necking of surface facilities to increaseprocessing capacity 50%, from 20,000 B/D[3178 m3/d] at 50% water cut to 80,000 B/D[12,712 m3/d] at 60% water cut, increasing oil production from 10,000 to 30,000 BOPD[1589 to 4767 m3/d].
• Install new production facilities with process-ing capacity of 360,000 B/D [57,204 m3/d] at75% water cut, reaching a 90,000 BOPD[14,300 m3/d] oil-processing capacity.
• Retrofit the water-handling module in thefuture to boost the mature-field water-handlingcapacity to cope with up to 90% water cut,allowing an economic final production phase of up to 600,000 B/D [95,340 m3/d] and 30,000 BOPD.
In this particular field-wide redevelopmentproject, water-control services and managementhave unlocked reserves by doubling the crude-oilrecovery factor from 14% to nearly 35%.
A Look at the FutureThe goals of reducing the costs of excess pro-duced water and unlocking additional recover-able reserves from mature fields appear difficult,but some quick victories are within reach.Understanding water-flow problems and theirsolutions is now a key component of today’sreservoir engineering.
Making the best of what we have is the firststep in water control, requiring a detailed under-standing of the assets, resources, activities andcosts associated with handling produced water.Opportunities may then become apparent to
reduce the costs of traditional practices and mate-rials (chemicals) and identify where future poten-tial cost increases can be controlled. Technicalinnovation will enable larger gross volumes to behandled with existing facilities. The total produc-tion system, from reservoir to custody transferpoint for oil and final resting place for water, mustbe considered. In many operator and service com-panies, research and development programs arecurrently targeted at developing appropriate toolsto manage this wave of produced water.
Finally, an integrated approach to water con-trol in every well from reservoir to disposal (orback to reservoir for pressure maintenance) willbring immediate and long-term cost-savings.Integrated water management services is envi-sioned as the key to reservoir production opti-mization by providing the means for producingadditional recoverable reserves. While water-control services will provide the bulk of progress,a downhole factory—built on the well pad fac-tory concept—will minimize produced water-handling costs, and optimized facilitiesprocesses could turn waste into a commodity,which will further enhance the recovery factor.Nevertheless, the real money comes from thepotential increase in oil production. —RH
23. Dake LP: “The Practice of Reservoir Engineering,” inDevelopments of Petroleum Science 36. Oxford, England:Elsevier, 1994: 445-450.
24. Crabtree M, Eslinger D, Fletcher P, Miller M, Johnson Aand King G: “Fighting Scale—Removal and Prevention,”Oilfield Review 11, no. 3 (Autumn 1999): 30-45.
Oilpump
Water pump
Interface levelcontrol valve
Water meter
Degasser
Hydrocyclone
First-stageseparator Second-stage separator
Flow path for removal of oil-contaminated water
> Surface water polishing. Oil is removed from producedwater prior to disposal into ariver or sea, or injection backinto the reservoir (top). Thehydrocyclone unit (bottom) ispositioned downstream of thewater outlets on the separatorand upstream of the degasser.Its function is to remove anyentrained oil from the waterand return it to the separationprocess before water is sent to the degasser.
Hatch
Oil compartment
Dirty-watercompartment
Individualhydrocyclones
Clean water
Clean-watercompartment
Dirty water
Oil reject
Hydrocyclone cross section
52 Oilfield Review Spring 2000
Modern perforating is inseparable from otherservices that improve well productivity, such asfracturing, acidizing and sand control or preven-tion.2 In addition to being conduits for oil and gasinflow, perforations provide uniform points ofinjection for water, gas, acid, proppant-ladengels for hydraulic fracture stimulations and fluidsthat place gravel to control sand in weak orunconsolidated formations.3 In other sand-man-agement applications, perforating provides therequired number, orientation and size of stableholes to prevent sand production.
Conveyance methods have also kept pacewith perforating technology and practices. In
the late 1970s and early 1980s, perforatingstrategies were limited to smaller
through-tubing or larger casing gunsconveyed primarily by wireline.
Charges for each gun size andtype were designed for
either maximum holesize or deep pen-
etration. By
the mid-1980s, conveyance choices were expand-ing. Since that time, tubing-conveyed perforating(TCP) grew from limited use in a small niche mar-ket to an essential element of many well comple-tions and an important perforating tool.4
In addition to coiled tubing, slickline andsnubbing units, systems are now available to runlong gun strings in live wells under pressure.These perforating and conveyance systems alsoperform other functions that fulfill completionneeds of varying complexity, such as releasingand dropping guns, setting packers and openingor closing valves. In the future, charges may beincorporated in and run directly with completionequipment during well construction.
This article reviews key aspects of perforat-ing, including basic physics, new charges andmanufacturing, perforation damage mitigation,optimized perforation parameters, perforatingpractices for natural, stimulated or sand-man-agement completions, safety and conveyancemethods. We also discuss the reasons for con-sidering specific formation, well and comple-tion requirements when selecting perforatingtechniques. Examples show how perforation
designs customized for specific reservoir andperforation interactions can maximize
well performance.
Establishing communication with oil and gas zones involves more than shooting
holes in steel casing by choosing guns and conveyance methods from a service
catalog. Perforating based on average formation properties and shaped-charge
performance is being replaced by a more tailored approach. Perforation design is
now an integral, often customized, element of completion planning that addresses
reservoir conditions, formation characteristics and specific well requirements.
Larry BehrmannJames E. BrooksSimon FarrantAlfredo FayardAdi VenkitaramanRosharon, Texas, USA
Andrew BrownCharlie MichelAlwyn NoordermeerBP AmocoSunbury on Thames, England
Phil Smith BP Amoco Houston, Texas
David Underdown Chevron Production & Technology CompanyHouston, Texas
For help in preparation of this article, thanks to JimAlmaguer, Bobby Carroll, John Corben, Janet Denney,Brenden Grove, Brad Hoffman, Manish Kothari, Jason Mai,Sam Musachia, Bob Parrott, Mark Vella, Ian Walton andWenbo Yang, Rosharon, Texas, USA; and Andy Martin,Aberdeen, Scotland.Bigshot, CIRP (Completion Insertion and Removal underPressure equipment), CleanSHOT, Enerjet, FIV (FormationIsolation Valve), GunStack, HSD (High Shot Density gunsystem), HyperJet, IRIS (Intelligent Remote ImplementationSystem), NODAL, PERFPAC, Pivot Gun, PowerFlow,PowerJet, QUANTUM, S.A.F.E. (Slapper-Actuated FiringEquipment), Secure, SPAN (Schlumberger PerforatingAnalysis), UltraJet, UltraPack and X-Tools are marks ofSchlumberger.
Modern perforating. Controlleddetonation of specially designedand manufactured explosiveshaped-charges creates path-ways from well to formationthrough steel casing, cement andreservoir rock so fluids can flowor be lifted to surface.
Perforated completions play a crucial role in hydro-carbon production. From well testing for reservoirevaluation to completion and remedial interven-tion, perforating is a key to successful exploration,economic oil and gas production, long-term wellproductivity and efficient hydrocarbon recovery.The perforating process instantaneously generatesholes—perforations—in steel casing, surroundingcement and the formation (next page).
Both well productivity and injectivity dependprimarily on near-wellbore pressure drop, com-monly referred to as skin, which is a function ofcompletion type, formation damage and perfora-tion parameters. In the past, perforations oftenwere characterized simply as holes in steel casingmade by mechanical cutters (before 1932), shoot-ing bullets (since 1932), pumping abrasives (since1958) or more commonly, by detonating specialshaped-charge explosives made specifically foroilfield perforators (since 1948).1 Far from simple,perforating is a complex element of well comple-tions brought into better focus by contemporaryresearch and an understanding of basic principles.
Deviation from symmetry reduces shaped-charged performance. In terms of penetrationand hole size, optimized designs and precisionmanufacturing are improving shaped charges.Strict quality-control and aggressive quality-assurance further ensure charge reliability. As aresult, perforating test results are more consis-tent and translatable to downhole conditions forperformance projections and productivity esti-mates.
Among the many advances in perforatingtechnology are new deep-penetrating charges thatincrease well productivity by shooting beyondinvasion, and big-hole charges for gravel packing.Increased performance per unit of explosivemakes these high-performance charges moreefficient. In the past two years, improved chargeshave yielded penetration depths and flow areasthat are many times greater than those achievedusing prior technology. Other developments con-trol debris, especially in high-angle or horizontalwells, by reducing debris size or retaining debrisinside charge carriers—guns.
Perforating is the only way to establish con-ductive tunnels that link oil and gas reservoirs tosteel-cased wellbores which lead to surface.However, perforating also damages formationpermeability around perforation tunnels. Thisdamage and perforation parameters—formationpenetration, hole size, number of shots and theangle between holes—have a significant impacton pressure drop near a well and, therefore, onproduction. Optimizing these parameters andmitigating induced damage are importantaspects of perforating. Ongoing research con-firms that underbalance—a wellbore pressurebefore perforating that is less than the formationpressure—is essential to partially or, in somecases, completely remove damage and debrisfrom perforations.
53
1. Behrmann L, Huber K, McDonald B, Couët B, Dees J,Folse R, Handren P, Schmidt J and Snider P: “Quo Vadis, Extreme Overbalance?” Oilfield Review 8,no. 3 (Autumn 1996): 18-33.
2. Martin A: “Choosing The Right Gun,” Petroleum EngineerInternational 71, no. 10 (October 1998): 59-72.
3. Naturally occurring or resin-coated sand and high-strength bauxite or ceramic synthetics, sized by screen-ing according to standard U.S. mesh sieves, are used as proppants. Gravel consists of extremely clean, round and carefullysized sand that is small enough to act as a filter andprevent production of formation particles, but largeenough to be held in place across productive intervalsby a slotted-screen assembly.
4. Cosad C: “Choosing a Perforation Strategy,” Oilfield Review 4, no. 4 (October 1992): 54-69.
Perforating Practices That Optimize Productivity
>
Shaped-Charge Dynamics Perforations are created in less than a second byshaped charges that use an explosive cavityeffect, which is based on military weapons tech-nology, with a metal liner to maximize penetra-tion (below). Perforating charges consist of aprimer, outer case, high explosive and conicalmetal liner connected to a detonating cord. Eachcomponent must be made to exact tolerances. Atthe Schlumberger Reservoir Completions Center(SRC) in Rosharon, Texas, USA, these charges aredesigned, manufactured and tested to meet strictquality standards.
A detonating cord initiates the primer anddetonates the main explosive. The liner collapsesto form a high-velocity jet of fluidized metal par-ticles that is propelled along the charge axis. Thishigh-energy jet consists of a faster tip and slowertail. The tip travels at about 4.4 miles/sec [7 km/sec], but the tail moves more slowly, lessthan 0.6 miles/sec [1 km/sec]. This velocity gradi-ent stretches the jet so that it penetrates casing,cement and formation. Perforating jets erodeuntil all energy is expended at the end of a per-foration tunnel.
Perforating jets act like high-velocity, rapidly-expanding rods. Rather than by blasting, burning,drilling or abrasive wearing, penetration isachieved by extremely high impact pressures—3 million psi [20 GPa] on casing and 300,000 psi[2 GPa] on formations. These enormous jetimpact pressures cause steel, cement, rock andpore fluids to flow plastically outward. Elasticrebound leaves shock-damaged rock, pulverizedformation grains and debris in the newly createdperforation tunnels.
Charge Design and Performance Shaped charges are designed to generate opti-mal combinations of hole size and penetrationusing a minimum of explosive material.Asymmetric, or crooked, jets reduce charge per-formance, so perforating jets must form exactlyaccording to design specifications. Consequently,shaped-charge effectiveness depends on chargesymmetry and jet characteristics. Penetrationdepends on consistently achieving long jets withoptimal velocity profiles. A velocity profile mustbe established from tip to tail, and perforatingjets need to travel as fast as possible. Incorrectvelocity profiles decrease penetration.
Hole size is related to jet shape. Initially, solid-metal liners, often copper, were used to generatehigh-density jets and big holes, but this createdundesirable metal slugs, or carrots, that plug per-forations. This plugging was believed to be offsetby large-diameter holes and the high permeabilityof formations where big-hole charges are used.Technology that eliminates slugs and maximizesarea open to flow (AOF) has revised this approach.Although solid copper liners are still used in somebig-hole charges, recent designs generate jetswithout a solid-metal slug.
54 Oilfield Review
5. Klotz JA, Krueger RF and Pye DS: “Effect of PerforationDamage on Well Productivity,” Journal of PetroleumTechnology 26 (November 1974): 1303.
6. On November 25, 1998, a gun loaded with new deep-penetrating PowerJet charges averaged 54.1 in. [137 cm]of penetration when fired into an API target.
7. Smith PS, Behrmann LA and Yang W: “Improvements inPerforating Performance in High Compressive StrengthRocks,” paper SPE 38141, presented at the SPEEuropean Formation Damage Conference, The Hague,The Netherlands, June 2-3, 1997.
> A fraction of a second. In a process that lasts microseconds, millions of dollars and months, if notyears, of preparation culminate when perforating clears a tunnel for hydrocarbons to flow into a well.Shaped charges, with a capability to instantaneously release energy in an explosive, use a cavityeffect and metal liner to maximize penetration (lower left). Shaped charges consist of four basic components—primer, main explosive, conical liner and case (top left). An explosive wave travels downthe detonating cord, initiating the primer and detonating the main explosive. A detonation advancesspherically, reaching pressures of 7.5 million psi [50 Gpa] before arriving at the liner apex. The chargecase expands and the liner collapses to form a high-velocity jet of fluidized metal particles that is pro-pelled along the charge axis (right).
Case
Conical liner
Detonating cord
Shaped charge
Explosive cavity effects
Charge detonation
Primer
Main explosive
Explosive Steel targetMetallic liner
Lined cavityeffect
Flat-end
Unlinedcavity effect
5 microseconds
25 microseconds
40 microseconds
50 microseconds
70 microseconds
Spring 2000 55
Deep penetration—Drilling and completionfluid invasion can range from several inches to afew feet. When formation damage is severe andperforations do not extend beyond the invadedzone, pressure drop, or skin, is high and produc-tivity is reduced.5 Perforations that reach beyondthe damage increase effective wellbore radiusand intersect more natural fractures if these arepresent. Deeper penetration also reduces thepressure drop across perforated intervals to pre-vent or reduce sand production. Designed andmanufactured to outperform other charges by atleast 20 to 30% in high-strength sandstonecores, PowerJet charges are the latest and mostefficient perforators available (left).
New liner designs—material and geometry—provide improved penetration performance(below left). Liners for PowerJet charges aremade of high-density powdered materials whichyield maximum jet length and impact pressuresthat maximize penetration.6
It is well known that high-density liners pro-duce deeper penetration, however, workingwith these materials is difficult. Improvementsin manufacturing capabilities now allow high-density liners to be produced consistently.Manufacturing improvements include strict andconsistent procedures, precision tooling andstringent quality control (see “Charge Manufac-turing and Testing,” page 62).
Charges are also test fired in different mate-rials—high-strength sandstone cores, standardconcrete and API Section 1 concrete—so thatperformance does not become optimized just forconcrete targets.
In high-strength rock, penetration is reducedby up to 75% compared to API Section I concretedata. However, charges can be customized forspecific formations.7 During PowerJet chargedevelopment, a project was initiated to optimizewell completion efficiency in hard sandstone for-mations of South America. The objective was toincrease perforation penetration in sandstoneswith 25,000-psi [172-MPa] compressive strengths.These high-permeability reservoirs have moder-ate porosity and corresponding large pore throatsthat contribute to fluid damage. A combination ofreduced penetration and deep invasion resultedin low productivity from perforations that did notextend beyond the damage.
1.15
1.0
0.85
0.7
0.55
0.44 8 12 16 20 24
Prod
uctiv
ity ra
tio, p
erfo
rate
d co
mpl
etio
nve
rsus
und
amag
ed o
penh
ole
Damaged-zone thickness, in.
PowerJet charges
UltraJet charges
HyperJet charges
> High-performance perforating. This graph shows the productivityratio of perforated completion versus undamaged openhole for various depths of formation invasion. For a damaged zone of 16 in.,perforating with a 33⁄8-in. HSD High Shot Density gun and PowerJetcharges results in more than twice the productivity of older HyperJet and UltraJet deep-penetrating charges.
Deep penetration. To ensure performance opti-mization for targets other than concrete, shapedcharges are now tested in different materials—high-strength sandstone, standard concrete and API Section 1 concrete. However, improveddesigns and materials provide most of theincrease in perforation penetration. Comparedwith previous deep-penetrating charges (top),new PowerJet high-density powdered liners andgeometry yield optimal jet velocity and length aswell as extremely high impact pressures (bottom).
>
To improve production, a three-phase approachwas used. Drilling fluids were reformulated toreduce invasion and damage, the number of per-forations was doubled and custom charges weredesigned to increase penetration. The firstredesign changed only the liner geometry, whichincreased penetration from 12.6 to 14 in. [32 to36 cm]. However, this was short of the 16-in. [40-cm] objective. Penetration was thenincreased to 15.9 in. by optimizing the explosivepellet design. In field trials, custom chargesimproved production and injection performance.In one case, a gas-injector perforated at fourholes per foot using optimized charges outper-formed other injectors with 12 holes per footmade by conventional charges.
In Australia, production from two wells with7-in. casing that were reperforated using 21⁄8-in.through-tubing guns with PowerJet chargesincreased from 300 to 780 BOPD [48 to 124 m3/d]and 470 to 1550 BOPD [75 to 246 m3/d]. Inanother example, an operator in Europe reperfo-rated wells with PowerJet charges to improveproductivity and reduce sand production. Prior toreperforating, more than 20 liters [2.7 gal] ofsand were produced each day at a wellhead
pressure of 2000 psi [13.8 MPa] and gas ratesabove 2 million m3/day [70.6 million scf/D]. Afterreperforating, sand-free gas rates of 2.5 millionm3/day at a surface pressure of 2700 psi [18.6MPa] were achieved. Efficiency is important notonly for producing wells, but also for injectors.Gas injectivity was improved nine fold, from 17.6to 159 million scf/D [500,000 to 4.5 million m3/d]by reperforating an injection well in the NorthSea Norwegian sector with PowerJet charges.
Big holes, less debris and optimized casingstrength—Proprietary liner geometry is also thebasis of PowerFlow slug-free big-hole shapedcharges, which generate large holes without asolid-metal slug (below). A large flow areaimproves gravel placement for sand control andreduces turbulent pressure-drop restrictions inhigh-rate wells, especially gas producers. In aunique packing arrangement patented bySchlumberger, PowerFlow shaped charges providethe largest area open to flow available, highestremaining casing strength and reduced debris.8
A hazard to well integrity and production, per-forating debris should be minimized. Gun andshaped-charge debris increase the risk of stuckpipe, collect at the bottom of vertical wells, may
not fall to bottom in deviated wells or may reachthe surface and damage production equipment.Two strategies are used to control debris.
The conventional approach uses zinc casesthat break up into small particles which are acidsoluble or can be circulated out. A possible short-coming of zinc is formation damage.9 Laboratorytests indicate that chloride-rich fluids and gaspercolating into an idle well may combine to pre-cipitate a solid from zinc debris that can stickguns. Another disadvantage is additional gunshocks from energy released when zinc is par-tially consumed during charge detonation.
Because of these disadvantages, operators aremoving away from charges with zinc cases thatproduce small debris. The Schlumberger patentedpacking method, which causes steel cases to frag-ment into large pieces that remain in the carrier, isbecoming the preferred option (next page, top).
Recent guns with increased AOF, optimizedperforated casing strength and reduced debrisare examples of customized solutions for perfo-rating high flow-rate and gravel-packed wells. In1998, Conoco requested a larger AOF than wascurrently available from any commercial guns forprojects around the world that require high pro-duction rates to ensure commercial viability. To address this need, Schlumberger developed a7-in. PowerFlow gun for 95⁄8-in. casing that pro-duces a 47% greater casing AOF than previousbig-hole guns and 31% more than that of thenearest competitor.
By ensuring adequate casing strength afterperforating, the newest PowerFlow guns alsoaddress an increasingly important aspect ofcompletion design—formation compaction asreservoir pressure depletes that can collapsecasing. Finite-element calculations for 95⁄8-in.casing perforated with the above record-breaking AOF 7-in. gun indicate that casingcollapse strength is 78% of the original value forcasing that is not perforated.
56 Oilfield Review
8. Brooks JE, Lands JF, Lendermon GM, Lopez de CardenasJE and Parrott RA: “Perforating Gun Including a UniqueHigh Shot Density Packing Arrangement,” U.S. PatentNo. 5,673,760 (October 7, 1997).On October 8, 1999, a 7-in. gun loaded with PowerFlowcharges at 18 shots per foot created 1.14-in. [2.89-cm]diameter holes and a world record 18.5 in.2/ft [391.6cm2/m] of casing area open to flow.
9. Javora PH, Ali SA and Miller M: “Controlled DebrisPerforating Systems: Prevention of an UnexpectedSource of Formation Damage,” paper SPE 58758, presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 23-24, 2000.
10. Behrmann LA, Pucknell JK, Bishop SR and Hsia T-Y:“Measurement of Additional Skin Resulting FromPerforation Damage,” paper SPE 22809, presented at the66th SPE Annual Technical Conference and Exhibition,Dallas, Texas, USA, October 6-9, 1991.
Solid metal slug
Fluidized particles
> Big holes. Previously, solid liners that generated residual slugs were used to produce big holes. Perforation plugging was believed to be offset by large-diameter holes and high formation permeability. Technology thateliminates solid slugs, or carrots, and maximizes hole size, or flow area, hasrevised this approach. Proprietary liners are the basis of these PowerFlowcharges. X-ray photography shows perforating jet formation in UltraPackbig-hole shaped charges (top) and PowerFlow (bottom) charges. The solidslug from an UltraPack charge is conspicuous. The PowerFlow charge generates only a fluidized jet of metal particles.
Spring 2000 57
as was believed previously. In addition to explo-sive by-products, another possible damagemechanism is transient injection of well fluidsthat may cause relative permeability problems.
In extremely hard rocks, microfractures cre-ated during perforating may serve as pathwaysthat are actually more permeable than theformation and bypass perforation damage. With3000-psi [20.7-MPa] underbalance, negativeskins equivalent to a stimulation treatment havebeen measured in some high-strength reservoirand outcrop rock cores.14 Shock-induced damage,however, most often contributes to total skin,restricts well performance and may offset pro-duction gains related to other perforation param-eters such as number of shots, hole size, anglebetween perforations and penetration.
The crushed zone can limit both productivityand injectivity. Fines and debris restrict injectivityand increase pump pressure, which decreasesinjection volumes and impairs placement or dis-tribution of gravel and proppants for sand controlor hydraulic fracture treatments.15 Erosion of thecrushed zone as well as removal of debris fromperforations by surge flow are essential to miti-gate perforating damage and ensure well suc-cess in all but the most prolific reservoirs.
> Controlling debris. A patented packingarrangement decreases the risk of debrisexiting the gun (top). Shaped charges areplaced in the closest possible arrangementfor a particular gun size and shot density sothat they cannot expand. Tight confinementcauses cases to break into large pieces thatremain in the gun (bottom). Small carrier exitholes also minimize the amount of debris thatcan escape.
Undamaged rock
Crushed-zone damage
Casing
Formation damage
Cement
Perforation tunnel
> Perforating damage. A zone of reduced permeability is created around perforation tunnels by shaped-charge jets.Shock-wave pressures pulverize adjacent rock, fracturematrix grains, break down intergranular cementation anddebond clay particles. Shattering of the formation around perforations damages in-situ permeability primarily by reducing pore-throat size. Photomicrographs show undamaged rock (top insert) compared to microfracturing in a perforation crushed zone (bottom insert).
11. Pucknell JK and Behrmann LA: “An Investigation of theDamaged Zone Created by Perforating,” paper SPE22811, presented at the 66th SPE Annual TechnicalConference and Exhibition, Dallas, Texas, USA, October 6-9, 1991.
12. Swift RP, Behrmann LA, Halleck P and Krogh KE: “Micro-Mechanical Modeling of Perforating ShockDamage,” paper SPE 39458, presented at the SPEInternational Symposium on Formation Damage Control,Lafayette, Louisiana, USA, February 18-19, 1998.
13. Behrmann LA, Li JL, Venkitaraman A and Li H: “Borehole Dynamics During Underbalanced Perforating,”paper SPE 38139, presented at the SPE EuropeanFormation Damage Control Conference, The Hague, The Netherlands, June 2-3, 1997.
14. Blosser WR: “An Assessment of Perforating Performancefor High Compressive Strength Non-HomogeneousSandstones,” paper SPE 30082, presented at the SPEEuropean Formation Damage Conference, The Hague,The Netherlands, May 15-16, 1995.
15. Behrmann LA and McDonald B: “Underbalance orExtreme Overbalance,” paper SPE 31083, presented atthe SPE International Symposium on Formation DamageControl, Lafayette, Louisiana, USA, February 14-15, 1996;also in SPE Production & Facilities (August 1999): 187-196.
Damaged Permeability An undesirable side effect of perforating is addi-tional damage in the form of a low-permeabilityzone around perforations. Single-shot flow andradial permeameter laboratory results confirmedand quantified this induced perforation skin.10
Perforating damage can consist of three ele-ments—a crushed zone, migration of fine forma-tion particles and debris inside perforationtunnels. Shock-wave pressures from the rock faceto perforation tips shatter adjacent rock and frac-ture matrix grains, which damages in-situ perme-ability primarily by reducing pore-throat size(below). Migration of small particles from grainfragmentation, clay debonding and charge debristhat block pore throats and further reduce perme-ability also has been observed in the laboratory.
Studies show that induced damage increasesfor larger explosive charges.11 The extent of per-foration damage is a function of lithology, rockstrength, porosity, pore fluid compressibility, claycontent, formation grain size and shaped-chargedesigns.12 Research in conjunction with numeri-cal modeling is providing a better understandingof permeability damage in perforated wells thatcan be used to improve completion designs.13
Crushed-zone porosity is generally unaffectedby perforating. At least in saturated rocks, den-sity and porosity around perforations are aboutthe same as in the undamaged matrix. Althoughperforating changes rock stresses and mechani-cal properties, it does not compact the formation
Mitigating Perforation Damage At one time, perforating was performed with mudor high-density fluids in wells—balanced or over-balanced conditions. Today, underbalance is morecommon to minimize or remove perforation dam-age. Underbalanced, balanced, overbalanced andextreme overbalance (EOB) describe the pressuredifferential between a wellbore and reservoirbefore perforating. An underbalance exists whenpressure inside a well is less than the formationpressure. Balanced conditions occur when thesepressures are equal. An overbalance occurs whenwell pressure is greater than reservoir pressure.Extreme overbalance means that well pressuregreatly exceeds rock strength—fracture initia-tion, or breakdown, pressure. Both EOB and frac-turing attempt to bypass damage.16
The potential of underbalance perforatingwas recognized in the 1960s. Wells perforatedwith underbalance tended to show productionincreases. In the 1970s and early 1980s,researchers recognized that the flow efficiency ofperforated completions increased when higherunderbalance pressures were used. They con-cluded that post-shot flow was responsible forperforation cleanup and recommended generalunderbalance criteria.17 Since then, variousaspects of perforating have been investigatedusing field and laboratory data. These studiesconsistently reinforce the advantages of an initialsurge to erode perforation crushed zones andflush out perforating debris.
A 1985 Amoco study evaluated 90 wells thatwere acidized after being perforated with tubing-conveyed guns in underbalance conditions andcorrelated productivity with permeability toestablish minimum underbalance criteria.18
Results did not suggest that there was no perfo-ration damage, only that acid was not needed oras effective if underbalance was sufficient. Thisstudy was the main source of field data forcorrelating underbalance with reservoir perme-ability and perforation performance.
From these data, minimum and maximumunderbalance pressures based on potential sandproduction were calculated from sonic velocitiesfor gas wells in 1989.19 The original Amoco studyas well as new data were reanalyzed.20 Toaccount for permeability, fluid viscosity and fluiddensity, equations for minimum underbalancewere based on fluid velocity and turbulent flowthrough perforations. The disadvantage was thatthis model required knowledge of damage-zonethickness, tunnel diameter in rock and fluid vis-cosity. In addition, recent test results do not sup-port the viscosity dependence of underbalance.
These models imply that flow after early-tran-sient surge, including pseudosteady-state flow orsurging wells after perforating, is less critical forperforation cleanup. However, post-shot flow maysweep some fines into the well and further cleanup perforations.21 In some cases, this accounts forlimited sand production when wells come on line.
Magnitude and duration of an initial pressuresurge are believed to dominate cleanup of
crushed-zone damage. Instantaneous flow mini-mizes fluid invasion, loosens damaged rock andsweeps away rock debris in perforation tunnels(above). The degree to which material is loosenedis primarily a function of underbalance pressuredifferential. The high-velocity surge is followed bypseudosteady-state flow, which is less effectivebecause rates and associated drag forces are lessthan those generated during an initial transientsurge. Fluid volume and flow that occur later arebelieved to be secondary.
The underbalance pressures required to effec-tively clean perforations and reduce permeabilitydamage have been measured in single-shot perfo-rate and flow tests that provide a basic understand-ing of damage mitigation.22 Immediately afterperforating in underbalanced conditions, there isinstant decompression of reservoir fluids around aperforation. The dynamic forces—pressure differ-ential and drag—that mitigate permeability dam-age by eroding and removing fractured formationgrains from tunnel walls are highest at this time.
58 Oilfield Review
Casing Undamaged formation Balanced perforating
Formationdamage
Cement Perforation debris
Crushed and compactedlow-permeability zone
Casing Undamaged formation 3000-psi underbalance perforating
Cement
Low-permeability zone andperforation debris expelled by surge of formation fluid
Formationdamage
> Underbalanced perforating. In an overbalanced or balanced perforation without cleanup andbefore flow, the tunnel is plugged by shattered rock and debris (top). Production flow may removesome debris, but much of the low-permeability crushed zone remains. The initial surge flow gener-ated by using an adequate underbalance during perforating helps remove debris and erode thecrushed zone (bottom).
21. Hsia T-Y and Behrmann LA: “Perforating Skins as aFunction of Rock Permeability and Underbalance,” paper SPE 22810, presented at the 66th SPE AnnualTechnical Conference and Exhibition, Dallas, Texas, USA,October 6-9, 1991.
22. Behrmann et al, reference 10.Hsia and Behrmann, reference 21.Pucknell and Behrmann, reference 11.Behrmann LA, Pucknell JK and Bishop SR: “Effects of Underbalance and Effective Stress on PerforationDamage in Weak Sandstone: Initial Results,” paper SPE 24770, presented at the 67th Annual TechnicalConference and Exhibition, Washington DC, USA,October 4-7, 1992.Bartusiak R, Behrmann LA and Halleck PM: “ExperimentalInvestigation of Surge Flow Velocity and Volume Neededto Obtain Perforation Cleanup,” paper SPE 26896, presented at the SPE Eastern Regional Conference and Exhibition, Pittsburgh, Pennsylvania, USA, November 2-4, 1993. Also in Journal of Petroleum Science andEngineering 17 (1997): 19-28.
16. Behrmann et al, reference 1.17. Bell WT: “Perforating Underbalanced—Evolving
Techniques,” Journal of Petroleum Technology 36(October 1984): 1653-1652.
18. King GE, Anderson A and Bingham M: “A Field Study ofUnderbalance Pressures Necessary to Obtain CleanPerforations Using Tubing-Conveyed Perforating,” paperSPE 14321, presented at the 60th SPE Annual TechnicalConference and Exhibition, Las Vegas, Nevada, USA,September 22-25, 1985.
19. Crawford HR: “Underbalanced Perforating Design,”paper SPE 19749, presented at the 64th SPE AnnualTechnical Conference and Exhibition, San Antonio,Texas, USA, October 8-11, 1989.
20. Tariq SM: “New, Generalized Criteria for Determining theLevel of Underbalance for Obtaining Clean Perforations,”paper SPE 20636, presented at the 65th SPE AnnualTechnical Conference and Exhibition, New Orleans,Louisiana, USA, September 23-26, 1990.
23. Behrmann et al, reference 10.Mason JN, Dees JM and Kessler N: “Block Tests Modelthe Near-Wellbore in a Perforated Sandstone, paper SPE 28554, presented at the 69th SPE Annual TechnicalConference and Exhibition, New Orleans, Louisiana,USA, September 25-28, 1994.
24. Behrmann LA: “Underbalance Criteria for MinimumPerforation Damage,” paper SPE 30081, presented at the 1995 SPE European Formation Damage Conference,The Hague, The Netherlands, May 15-16, 1995; also inSPE Drilling & Completion (September 1996): 173-177.
Spring 2000 59
Transient surge-flow velocities are dependenton underbalance and formation permeability. Thepressure differential required to create clean, effec-tive perforations is a function of permeability,porosity and rock strength in addition to charge typeand size. For example, deep-penetrating chargesare less damaging than big-hole charges. Less thanoptimal underbalance results in variable perforationdamage and flow rate per perforation, and mostdata suggest that higher underbalance pressuresthan those often used in the field are needed tominimize or eliminate perforating damage.23
Although turbulent flow does occur at earlytimes with low-viscosity fluids, test results indi-cate that turbulence is not required for perfora-tion cleanup. Instead cleanup of permeabilitydamage around a perforation has now beenrelated to viscous drag.24 The key factors arepressure differential and subsequent transient,slightly compressible radial flow, either laminaror turbulent, which was the starting point forobtaining semi-empirical underbalance and skinequations with historic data sets.
The resulting combined theoretical andempirical equations provide a way to calculateoptimal underbalance for zero perforation dam-age or perforation skin if less than optimal under-balance is used. Single-perforation skin can beused in flow simulators to obtain total perfora-tion skin and evaluate or compare perforatingoptions. Now the most widely accepted criteriafor estimating underbalance to obtain zero-skinperforations, this methodology was the result ofmore than a decade of research on optimizing
10,000
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Optimum underbalance versus permeability
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Behrmann (1995)King (1985)
1000-psi underbalance
1500-psi underbalanceUnderbalance criteria. Underbalanceis widely accepted as the most efficientmethod to obtain clean perforations.Optimal underbalance pressure criteria have increased substantiallyover the past decade as a result ofhundreds of laboratory tests. Fieldobservations by King et al developedcriteria based on the efficiency ofsandstone acidizing. Behrmann correlated laboratory data with the viscous drag force to remove fine particles (left). Laboratory tests confirmthat higher underbalance is needed toclean perforations (right).
Advanced flow laboratoryfor core perforation-flow studies
Simulated reservoir core samples
Shootingleads
Wellbore-pore
Wellbore pressure
Micrometer valve
Fast quartz gauges
Confining chamber
30-gallon accumulator
Shooting plate simulatingcasing and cement
5-gallon accumulatorconnected to wellbore
Simulated wellbore
Gun with shaped charge
Core sample
Conf
inin
g fa
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ata
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pressure differential
Single-perforation flow tests. The advancedflow laboratory at SRC includes two vessels forinvestigating perforation flow under downholeoverburden, pore and wellbore pressure condi-tions (top). One vessel is for cores up to 7-in.diameter and 18 in. long; the other accommo-dates cores as large as 11.5-in. diameter and 24 in. long. This setup allows flow tests throughoutcrop or reservoir cores that can be orientedfrom horizontal to vertical (bottom).
perforation cleanup. Underbalance requirementscalculated using this method are two to fourtimes greater than previous criteria (above).
Because underbalance impacts perforationperformance and well productivity, it is essentialto understand the fluid dynamics involved.Knowledge about perforating shocks, pressuresand fluid flow is helpful in selecting an optimalunderbalance and designing downhole tools. Theadvanced flow laboratory at SRC includes twotest vessels for investigating perforation flow
and other completion operations under downholeconditions with overburden stress as well aspore and wellbore pressure (below).
This setup allows researchers to shoot andflow through a single perforation in outcrop orreservoir cores oriented from horizontal to verti-cal with any perforating system. Oil and watertwo-phase flow and dry-gas flow can be evalu-ated at constant rates with a continuous recordof absolute and differential pressure measure-ments. Perforations can be examined with a color
>>
video probe during flow through the core whileunder hydrostatic stress (above). Other opera-tions, like gravel injection and acidizing also canbe evaluated. Wellbore dynamics can be simu-lated to measure transient pressures, surge flowand perforating shocks.
Surge-flow rate and duration are controlled byinitial underbalance pressure, formation perme-ability, perforation damage, depth of near-well-bore formation damage, and the nature ofwellbore and reservoir fluids. Fast transient data,not acquired previously due to the cost anddifficulty of obtaining these measurements, arehelping researchers understand underbalancedperforating (below).25 Wellbore pressure, reser-voir-wellbore pressure differential and surge-flowdata recorded at millisecond resolutions indicate
a short period of injection into the perforationassociated with a transient overbalance due toinjection of detonation gases from the gun. Themagnitude of the pressure differential driving thisfluid injection depends on charge size and rock-sample permeability.
Underbalance perforating has evolved as theresult of research that concentrates on predictingthe pressure differential to minimize perforationskin. However, the likelihood of sand production,casing collapse, gun movement and stuck toolsmust be weighed against potential benefits.Design guidelines include minimum underbal-ance pressure for perforation cleanup, maximumunderbalance pressure to avoid sanding, andfluid cushions—a gas or liquid column—ormechanical anchors to minimize tool movement.
Optimizing Perforation ParametersDamage removal and perforation cleanup areimportant elements of perforating design and jobexecution, but consideration must also be givento tunnel diameter and length in the formation,shot density, or number of holes specified inshots per foot (spf), perforation orientation, orphasing—angle between holes—and entrance-hole size in the casing and cement (next page,bottom left). Pressure drop from perforating dam-age, or total perforation skin, is a function ofthese key perforation parameters, formation per-meability and crushed-zone thickness.
Well completions have different perforatingrequirements. Some wells produce commercialvolumes naturally after perforating and do notrequire stimulation or sand management duringcompletion. These natural completions are asso-ciated with permeable, high-porosity, high-strength sandstones and carbonates with littleformation damage and adequate matrix conduc-tivity. Perforation length and shot density are thedominant perforating parameters that dictateproductivity in these applications. Perforationsmust overcome drilling-induced damage andfluid invasion. As a rule of thumb, deep penetra-tion, at least 50% beyond damage, is needed toeffectively connect with undamaged rock.
Shot density and phasing also play importantroles. Increasing shot density reduces perforationskin, and wells produce at lower pressures. If for-mations are laminated or have high anisotropy—significantly different vertical and horizontalpermeabilities—shot density needs to be high.As skin approaches zero, shot density is impor-tant. Phased charges reduce pressure drop near awell by providing flow conduits on all sides of awell. For naturally fractured formations, multiplephasing of deep-penetrating charges helps inter-sect more fractures. If the natural fractures areparallel, oriented perforations are best.
60 Oilfield Review
> Flow lab video. Perforation flow can be examined visually with a color video probe while cores are under hydrostatic stress. A perforation filled with pulverized formation material and surrounded by fragmented quartz grains is shown on the left. A perforation without fragmentation is shown in the middle, but pulverized material remains along the bottom of the tunnel. A clean perforation with no fill is shown on the right.
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> Typical underbalance perforating pressure responses and flow rates versus time. Data wereobtained at 2000 samples/sec in single-perforation flow tests under simulated downhole conditions of effective stress, well and reservoir pressure. After detonation, well pressure (red) increases and underbalance (blue) declines, allowing some flow (green) into the perforation. As detonation gases gointo solution and the empty gun fills with fluid, wellbore pressure again falls causing transient surgeflow into a well. This initial flow is believed to mitigate damage and permeability reduction in thecrushed zone. High-velocity transient surge flow is followed by pseudosteady-state surge flow, which may sweep loose rock and charge debris into the well and clean perforations. Surge flow continues until well and reservoir pressures equalize—zero underbalance, or balance. These sameresponses occur in balanced and overbalanced pressures, except there is no surge flow in balancedperforating and flow is from well to formation in overbalanced conditions.
Spring 2000 61
Although useful for estimating well produc-tivity and assessing trade-offs between differentguns, computer analysis sometimes obscures theinteraction and relative importance of competingparameters. Grouping parameters together revealsunderlying dependencies. This type of analysishelped develop a simple method to estimate theproductivity of perforated natural completions.26
Combining perforation and formation parametersin a single dimensionless group gives quick pro-ductivity estimates over a range of variables thatagree with the established analytical estimatesof commercially available computer programs.
Applicable for perforations that extendbeyond formation damage in a spiral phasingpattern, this method assumes that perforationlength, shot density, perforation tunnel diameter,wellbore diameter, local formation damagearound a well, perforating-induced permeabilitydamage and permeability anisotropy are the pri-mary variables governing productivity. The theo-
retical maximum well productivity ratio is definedby an ideal gun with infinite shot density thatenlarges the wellbore radius by a distance equalto the perforation penetration (below, top right).This establishes the theoretical productivity thatcan be obtained for a perforated natural comple-tion and defines a maximum productivity effi-ciency for perforating systems in terms of adimensionless factor. Practical application of thismethod lies in determining trade-offs betweenperforation parameters, underbalance, productivityimprovement and economics.
Penetration and shot density clearly areimportant for natural completions. Penetrationhas an increasing proportional effect as perfora-tions extend farther beyond formation damage.Shot density has a 1.5 exponential power effect.In addition, because perforation damage isinversely proportional to the dimensionless fac-tor, it should be minimized by perforating with anappropriate underbalance pressure differential.
High shot density is particularly effective ifdeep penetration is not possible. In natural com-pletions, tunnel diameter in the formation is theleast important of the perforation parametersand increasing hole size usually occurs at theexpense of penetration. A 10% increase in diam-eter sacrifices about 20% of the penetration and reduces the dimensionless factor by 15%.Another reason not to emphasize hole size whenselecting guns for natural completions is thatperforating jets that make big holes may alsocause additional damage.
Reduced flow from high anisotropy, perforat-ing damage or formation damage can be partiallyovercome by selecting a gun with the highestdimensionless factor, whether by deep penetra-tion, high shot density, underbalance damagemitigation or a combination of these factors. Thebest perforating strategies are defined as thosethat provide productivity efficiencies close to100% (bottom right).
25. Behrmann et al, reference 13.26. Brooks JE: “A Simple Method for Estimating Well
Productivity,” paper SPE 38148, presented at the SPEEuropean Formation Damage Conference, The Hague,The Netherlands, June 2-3, 1997.
Openhole diameter
Phase angle
Perforationtunneldiameter
Perforationlength
Crushed-zonediameter
Perforationspacing
(dependent onshot density)
Damaged-zone diameter
> Perforation parameters. To be effective, perforations must overcomedrilling-induced damage and fluid invasion around a well. Shaped-charge performance is defined by casing entrance-hole size and tunnellength. Well productivity, however, is governed by formation damage,perforation length, shot density, perforation damage that remains afterunderbalance surge and the ratio of horizontal to vertical permeability—anisotropy. Shot density is the number of holes specified in shots perfoot (spf). Phasing is the angle between holes.
N=4
P
N=8 N= ∞
2P + D
Ideal perforating gun
D
> A simple method to estimate well productivity. Maximum well productivityis defined by an ideal perforator with infinite shot density, which enlargesthe effective wellbore diameter (D) by the perforation length, or depth ofpenetration (P). In natural completions, this theoretical flow limit is used todefine perforating system efficiency for perforations that extend beyond formation damage in a spiral pattern.
0
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P = penetrationN = shot densityd = perforation diameterα = anisotropy ratio
> Productivity efficiency versus dimensionless perforating factor.
(continued on page 64)
Mixtures of metal powders, corrosion inhibitorsand lubricants that help the powders flow havereplaced solid liners in most Schlumbergercharges. At the Schlumberger Reservoir Comple-tions Center (SRC) in Rosharon, Texas, linersand charges are produced in a series of pressingoperations (below). Powdered components areshaped into a cone using a mechanical punch.Copper, tungsten, tin, zinc and lead powders arecommonly used to produce required jet densityand velocity, properties critical to perforatingperformance. The main explosive is poured intoa case, levelled and pressed to optimal densityunder a high load. A liner is then pressed intothe explosive to complete the charge.
Although conceptually simple, shaped-chargemanufacturing requires great precision. Chargecomponents—case, primer, explosive and liner—
must meet strict quality standards and be fabri-cated to exact tolerances to ensure that perfo-rating jets form exactly according to designspecifications. A nonuniform liner collapse willcreate heterogeneous jet densities, shapes andvelocity profiles that adversely affect hole sizeand shape, and drastically reduce performance.To maintain proper tolerances, precision manu-facturing tools are built and maintained in-houseusing a state-of-the-art machine shop (right).Computerized pressing operations ensure highquality and minimize variations.
Charge manufacturing is computer-controlled,but there is human intervention to handle linersand check for cracks, make visual inspectionsand clean die tools. Technicians manufactureand package millions of charges each year. A team approach with functions located in
a single area facilitates efficient manufactur-ing and helps optimize charge performance.Multiple-bay work areas speed manufacturingand provide flexibility to meet changing wellcompletion requirements (next page, top).Manufacturing parameters are displayed in realtime to detect process deviations.
Quality control is maintained on all materialsused to manufacture charges, from cases andpowdered-liner metals to explosives. A databasewith serial numbers, history cards, associateddrawings and historical information tracks allcharges (next page, bottom left). These recordsallow day-to-day oversight of shaped-charge pro-duction quality and highlight manufacturingimprovements that impact charge performance.For example, procedures that were initiatedwhile developing new deep-penetrating chargeswere implemented for other charges, resultingin further performance improvement.
Perforating systems are tested according tothe American Petroleum Institute (API) RP 43,5th Edition, Section 1.1 New RP 19B proceduresare compatible with RP 43, except for a majorrevision to prevent target inconsistencies.2 The
Charge Manufacturing and Testing
62 Oilfield Review
Linerpunch
Linerdiebody
Linerpowder
Linerejector
Pressing force
2Liner pressed with
high force
1Liner powder placed
in ejector
3Completed liner ejected
from diebody
Linerdiebody Liner
Linerejector
Completedliner
Pressing force
6Form explosive powder
into conical shape
Finalform
punchExplosivepellet
5Preform explosivepowder for density
Pressing force
Preformpunch
Explosivepellet
4Explosive powder
placed in charge case
Explosivepowder
Caseejector
Loadingdiebody
Case
Pressing force
7Liner inserted and pressed
into explosive
Linerinsertion
punchLiner
8Completed charge ejected
from diebody
Completedcharge
Liner fabrication
Explosive loading
Shaped-charge manufacturing. Today, most linersare mixtures of metal powders, corrosion inhibitorsand lubricants that help the powders flow (top). In a series of pressing operations, these powdersare shaped into a cone using a mechanical punchand die (middle—steps 1-3). Assembling a shaped-charge involves placing a primer at the base of acase and pouring in the main explosive (middle—step 4). The main explosive is then levelled andpressed to optimal density under high loads (bottom—steps 5 and 6). A charge is completed by pressing a liner onto the explosive (bottom—steps 7 and 8).
> Manufacturing tools. To maintain proper tolerances, Schlumberger produces and maintainsprecision mechanical dies, punches and equipmentusing an in-house, state-of-the-art tool shop.
>
Spring 2000 63
sand used in concrete targets is specified as16/30 U.S. mesh. This change, which wasrecently approved to address discrepancies inpenetration-depth tests that result from largevariations in the sand grain sizes used to makeconcrete targets, is being implemented.3
Schlumberger API tests are performed inlarge concrete targets at SRC (right). Testsinclude certification of new charges as well asperiodic recertification to ensure that publisheddata represent charges currently being pro-duced. The API test site is also used for specialclient tests involving API Section 1-type targets.Of particular interest are custom tests involvingmultiple casing or completion geometry otherthan the standard API RP 43 configuration.
At the beginning of a new production run, a minimum of two charges is shot in targetsbuilt to Schlumberger standards using actual guncarriers in a water standoff that simulates down-hole conditions. These concrete targets have a minimum compressive strength of 5000 psi[34.5 MPa]. Expected penetration in thesequality-control targets is calculated based onAPI Section I, and a minimum penetrationrequirement for manufacturing is set. Full pro-duction begins once test results indicate thatminimum requirements have been surpassed.Repeated measurements of total target penetra-tion and minimum and maximum entrance-holesize are used to check charge quality.
During a manufacturing run, periodic testsare performed to confirm compliance with estab-lished performance specifications for penetrationand hole-size standards. Samples are tested every240 charges for large runs, and every 120 chargesfor the small runs associated with high-tempera-ture charges. Case and liner integrity are verifiedby a shock, or drop, test, and ballistic transfersensitivity is checked. For random batches ofcharges, detailed measurements are made on allcomponents. A few charges from each manufac-turing run are stored for audit purposes. Duringthis period, charges are pulled from storage
bunkers and test fired at regular intervals tocheck for aging effects. Internal audits also verifyproper charge performance.
Test facilities at SRC, while used extensivelyto evaluate new charges and qualify perforatingequipment, are also available for oil companyuse in completion planning and analysis of diffi-cult well conditions. In addition to improvingperforating performance, standardized andcustom testing helps researchers and clientsaddress confidence in perforating practices andoperations by verifying that perforating systemsperform consistently at rated temperatures andpressures for the duration of operations.
1. The American Petroleum Industry (API) consults with theoil and gas industry, considers advice and input from ser-vice companies, operators and scientific organizations,and recommends procedures that balance industryneeds, technology and service-provider opinions.
2. API RP 19R, 1st Edition is a revised version of RP 19B inwhich tests are scheduled and registered with the API,and can be witnessed by third parties. The advantages ofRP 19R are that manufacturing companies make a com-mitment to schedule and register tests, which carrygreater credibility than those under RP 43.
3. Brooks JE, Yang W and Behrmann LA: “Effect of Sand-Grain Size on Perforator Performance,” paper SPE 39457,presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 18-19, 1998.
Water
Test briquette
Steel culvert
CasingGun
28-day concrete
> Shaped-charge testing. Schlumberger API testsare performed in large concrete targets at SRC(top). Tests include certification of new charges as well as periodic charge recertification. The APItest site is used for special client tests involving APISection 1-type targets and testing that involves mul-tiple casing or well-completion configurations otherthan a standard API RP 43 configuration (bottom).Oil companies routinely use the API test site andother facilities at SRC for customized testing.
> Manufacturing functions. Teams of trained techni-cians assemble and package millions of chargeseach year. To facilitate high-quality, efficient fabri-cation and optimal charge performance, liner-press-ing operations and charge loading are located in asingle area (top). Multiple-bay work areas provideflexibility and the capability to respond quickly tochanging perforating needs. A special weighingroom is used to carefully control the explosive con-tent of shaped charges (bottom).
> Quality assurance. Control is maintained on allmaterials from steel cases and metal powders toexplosives and the mechanical tools used to fabri-cate charges. A real-time display helps techniciansidentify manufacturing deviations quickly and adatabase tracks each shaped charge. Theserecords are used to oversee daily operations andhelp quantify process improvements so that newprocedures that impact perforating performancecan be implemented across the manufacturingprocesses of other charges.
Stimulated CompletionsFracture and acid treatments, alone and in com-bination, stimulate well productivity.27 Effectivewell stimulation requires communication throughas many perforations as possible. This objectiveis achieved by perforating with optimal underbal-ance, limited-entry techniques or by using ballsealers or straddle packers that mechanicallydivert stimulation fluids to ensure that perfora-tions are open.28 Rather than create longhydraulic fractures in a formation, EOB is also an option to enhance communication betweenperforations and reservoir. Extreme overbalanceperforating can be used before a fracture stimu-lation to reduce breakdown pressure.29
Because hydraulic fracturing is often per-formed in low-permeability zones, minimumunderbalance to remove perforation damage canbe extremely high. Maximum underbalance isrequired to ensure removal of perforation damageand debris. If damage is not removed, residualdebris may form a filter cake in perforations thatlimits injectivity. Inflow is often not affected, butthe restriction may create high pressures duringinjection. An acid job may be needed when perfo-ration damage is not removed before fracturing.
Trade-offs between penetration and hole sizehave to be balanced when selecting shapedcharges for fracturing applications. While perfo-rations that penetrate more than six inches into aformation may not be necessary, adequate sizeholes are needed to avoid screenout—proppantbridging—in or near perforations. Prematurescreenout limits the fracture length and proppantvolumes that can be placed. At moderate to highproppant concentrations, perforation diametermust be at least six times the average particlediameter to prevent screenout. A perforationdiameter of 8 to 10 times the average particlediameter is preferred to allow for variations incharge performance and gun position.
Perforations are the point where pressurecontacts a formation and fractures initiate.Except for limited-entry and diversion tech-niques, it is important to design perforations thatminimize pressure drop across the perforationsduring pumping and subsequent production,including perforation friction, microannulus pinchpoints and tortuosity caused by curved fracturesand multiple competing fractures.
Fluid injection rates directly affect surfacepump and fracture initiation pressures. Highrates and pressures promote fracture initiation atsingle sites. At low rates, injection pressure isreduced and multiple fractures may initiate fromperforations and discrete points around a well.Shot density is calculated during fracture design.Minimum shot density depends on required injec-tion rate per perforation, surface pressure limita-tions, fluid properties, completion tubular sizes,acceptable perforation friction pressure andentrance-hole diameter (above).
A microannulus is often present after cement-ing, casing pressure-integrity testing, displacingdrilling or completion fluids, establishing anunderbalance, or after perforating and pumpingoperations that weaken the hydraulic bondbetween cement and formation (right). Becauseof the resulting pinch points, or flow restrictions,a microannulus should be avoided.
If a microannulus is present or might beinduced by perforating, various factors need to beconsidered.30 To minimize pinch points and reduceflow-path tortuosity, wells with inclinations lessthan 30° should be perforated with 180°-phasedcarrier guns oriented within 10° of the preferredfracture plane (PFP). The PFP direction can beinferred from local geology or well logs.31
64 Oilfield Review
27. In hydraulic fracturing, fluid is injected at pressuresabove the formation breakdown stress to create a crack,or fracture, extending in opposite directions from a well.These fracture wings propagate perpendicular to theleast rock stress in a preferred fracture plane (PFP).Held open by a proppant, usually sand, these conductivepathways increase effective well radius, allowing linearflow into a fracture and to the well. In matrix treatments,acid is injected below fracturing pressures to dissolvenatural or induced damage that plugs pore throats. Acidfracturing, most often without proppants, establishesconductivity by differentially etching uneven surfaces in carbonates that keep fractures open.
28. Limited entry involves low shot densities—1 spf or less—across one or more zones with different strengths andpermeability to ensure uniform acid or proppant place-ment by limiting the pressure differentials between per-forated intervals. The objective is to maximize stimulationresults. Rubber ball sealers can be used to seal openperforations and isolate intervals once they are stimu-lated so that the next interval can be treated. Becauseperforations must seal completely, hole diameter anduniformity are important.
29. Behrmann et al, reference 1.
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Inje
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> Injection rate versus perforation diameter for a water-based fractur-ing fluid. The minimum hole size and shot density for fracture stimula-tion designs are a function of required injection rate per perforation,surface pressure limitations, fluid properties, completion tubular sizes,acceptable perforation friction loss and entrance-hole diameter.
>30°
Preferredfracture plane
Pinch point
Microannulus
(PFP)
> Pinch points. A microannulus is caused byweakening of the hydraulic bond between cementand formation. Because of accompanying tortu-osity, flow restriction and increased pressure, amicroannulus and associated pinch point shouldbe avoided. If the angle between perforations andthe PFP is greater than 30°, a fracture initiatesfrom the sandface.
Spring 2000 65
Full-scale laboratory tests on fracture initia-tion through actual perforations show genericfracture initiation sites at the base of perfora-tions and the PFP intersection with a borehole.32
The fracture initiation site depends on perfora-tion orientation in relation to the PFP. Typically, ifthis angle is greater than 30°, fractures occurwhere no perforation exists. If a fracture does notinitiate at the perforations, fluid and proppantmust travel around the cement-sandface inter-face to communicate with a fracture, which
30. Behrmann LA and Nolte KG: “Perforating Requirementsfor Fracture Stimulations,” paper SPE 39453, presentedat the SPE International Symposium on FormationDamage Control, Lafayette, Louisiana, USA, February 18-19, 1998.
31. Brie A, Endo T, Hoyle D, Codazzi D, Esmersoy C, Hsu K,Denoo S, Mueller MC, Plona T, Shenoy R and Sinha B:“New Directions in Sonic Logging,” Oilfield Review 10,no. 1 (Spring 1998): 40-55.
32. Behrmann LA and Elbel JL: “Effect of Perforations onFracture Initiation,” paper SPE 20661, presented at the65th SPE Annual Technical Conference and Exhibition,New Orleans, Louisiana, USA, September 23-26, 1990.
33. Romero J, Mack MG and Elbel JL: “Theoretical Modeland Numerical Investigation of Near-Wellbore Effectsin Hydraulic Fracturing,” paper SPE 30506, presentedat the 70th SPE Annual Conference and Exhibition,Dallas, Texas, USA, October 22-25, 1995.
PerforationsMaximum
stress
Minimumstress
60°
Fracture
PFP
Effectiveperforations
Fracturing vertical and high-angle wells.For vertical intervals and wellbore inclina-tions less than 30°, guns with 180° phasingoriented within 10° of the preferred fractureplane (PFP) are recommended (top left). IfPFP direction is not known, 60° phasing athigher shot densities should be used (bottomleft). If well inclination is greater than 30°and the wellbore lies in or near the PFP, gunswith 180° phasing oriented to shoot up anddown should be used (top right). As well-bores turn away from the PFP, perforatedintervals should be decreased and 60° orlower phasing may be more effective than180° (bottom right). Perforations should beclustered over short intervals of a few feetwith maximum shot density and phasing tooptimize communication with one dominantfracture per interval.
When well inclination is greater than 30° anda wellbore lies in or near the PFP, the recommen-dation is to use guns with 180° phasing orientedto shoot up and down. The Wireline OrientedPerforating Tool (WOPT) may be used to orientwireline-conveyed guns in vertical and nonverti-cal wells. Several methods are also available toorient TCP guns. As wellbores turn away from thePFP, perforated intervals should be decreased,and 60° rather than 180° phasing may be moreeffective (below).
For high-angle and horizontal wells where theangle between wellbore and PFP is greater thanabout 75°, perforations should be clustered overa few feet at maximum shot density and withphasing angles that optimize communicationwith one dominant fracture per interval.
results in higher treating pressures, prematurescreenout and the possibility of multiple or asym-metric fractures.
Perforation phasing and orientation also areimportant in fracturing. Tortuosity from a curvedfracture path results from misalignment betweengun phasing and the PFP. Phased perforationstend to create multiple competing fractures. Boththese factors increase fracturing pressures.33
Vertical wells with inclinations less than 30°should be perforated with 180°-phased carrierguns oriented within 10° of the PFP to increasethe number of perforations open to a fracture,maximize fracture width near the well andreduce fracture initiation, or breakdown, pres-sure. If PFP direction is not known or orientation isnot possible, 60 or 120° phasing is recommended.
>
Sand Management: Control or Prevention?Depending on formation strength, perforationstresses, flow rate and fluid type, sand may beproduced with oil, gas and water when flow issufficiently high, and there are unconsolidated orloose formation grains in and around the perfora-tions. Changes in flow rate related to pressuredrawdown, increasing effective stress due todepletion and increasing water production withtime are the main factors in sand production.
Sand control utilizes mechanical methods toexclude sand from produced fluids. Sand pre-vention incorporates techniques to minimize oreliminate the amount of sand produced and also to reduce the impact of produced sand with-out mechanical exclusion methods. Choosingbetween these options is a function of perfora-tion and formation stability and whether per-foration failure can be predicted. The essence ofsand management is quantification of sand pro-duction risk, which helps operators decide if,how and when sand control or sand preventionshould be implemented (above).
Several methods help predict perforation tun-nel stability over the life of a well. Theoreticalborehole stability models adapted to perforationsare useful in predicting perforation stability asstress conditions change due to pressure draw-down and depletion.34 Experimental methodsinvolve testing reservoir cores or outcrop rockswith similar properties.35 Sand-prediction criteriabased on production history, by far the mostwidely used technique, rely on experience fromother wells and correlation of rock strength tocalibrate theoretical models and help choosebetween sand control and sand prevention.36
Perforating for sand control assumes that theproduction of sand is unavoidable and gravel pack-ing, fracture packs or other mechanical techniquesthat exclude sand from production flow areneeded. Perforating must address adequateunderbalance to minimize pressure drop, or skin,and remove loose sand to clean out perforationtunnels for optimal gravel placement and efficientgravel packing. In sand prevention, perforationsare designed to avoid sand production over the lifeof a well. Making the right decision impacts initialcosts, production rate and ultimate recovery.
Sand-Control RequirementsIn weak, unconsolidated formations, the conven-tional belief is that there are no open perfora-tions in the formation. The only opening forplacing gravel is the hole through casing andcement. This general theory proposes that if for-mations are incompetent and sand is producedwith hydrocarbons, there is little chance thatopen tunnels exist. Single- and multiple-shot per-forating tests have not shown this to be true inall cases. Instead, research indicates that perfo-ration definition in weak sands depends primarilyon rock strength, but also on other factors,including effective stress, underbalance, distancebetween adjacent perforations and fluids in thepore spaces and wellbore.
When perforation tunnels are not defined, theobjective of perforating for conventional gravel-pack operations is to minimize pressure dropacross the gravel-filled hole in casing and cement.This pressure drop is dictated by total AOF—thearea of individual holes multiplied by the total
66 Oilfield Review
Sand management(cased and perforated wells)
Quantification ofsand-production risk
Sand control(exclusion methods)
Increasing sand strength
Identify and minimize sources ofproductivity impairment
Sand prevention
Perforating methods to minimizesand-production risk
Increasing cost
Acceptable riskUnacceptable risk
> Sand-management decision tree.
> Perforating for sand control. Perforation tunnelsare assumed to be undefined and have little or no opening in weak formations (top). An ideal perforation cleaned out by hand in the laboratoryhas no perforating-induced rock debris and thereis little intermingling of debris and placed gravelas shown in scanning electron microscope (SEM)images (middle). In an actual single-shot test, perforation debris mixes with gravel and plugs the pack (bottom).
Spring 2000 67
number of shots—gravel permeability and flowrate per perforation. Tests on core samples showthat when tunnels are defined, perforating debrisand formation fines can impair gravel permeability(previous page, right). The objective is to minimizeinduced damage and gravel-pack impairment.
Perforation damage, formation fines andcharge debris should be removed before gravelpacking. Underbalanced perforating and flowbefore gravel packing are the best methods toachieve this objective. The maximum underbal-ance pressure must be selected to avoid perfora-tion collapse and catastrophic sand productionduring perforating. Perforating with the surfacechoke open ensures post-shot flow to transportdebris into the wellbore. Provisions need to bemade to handle transient, finite sand productionat surface until the perforations are clean. Whenpressure drop and flow rate per perforation arelow, deep-penetrating charges can be used.Deep-penetrating charges cause less localizeddamage and debris, and provide a larger effec-tive wellbore radius that reduces pressure drop.As in fracturing applications, perforation diame-ter needs be 8 to 10 times the gravel diameter.
Exposing formations to damaging completionfluids or lost circulation material (LCM) andchemicals during hydrostatic well-control opera-tions should be avoided. Damage to open perfo-rations was observed in tests on Bereasandstone blocks that were perforated, openedto flow, plugged by LCM and then reopened toflow.37 If a well must be killed, nondamagingbrines or mutual solvents are best.
For conventional gravel packing inside casing,three steps are necessary: set a bottom packer,perforate and circulate gravel behind gravel-packscreens. Disadvantages include long duration ofoperations, and potential formation damage fromfluid loss or LCM. Perforating guns and gravel-pack hardware can now be run in one step. ThePERFPAC system is a single-trip sand-controlmethod that limits fluid loss, reduces formationdamage and saves time (above right).
In addition to internal gravel packs, perforat-ing plays an important role in external sand-con-trol applications like fracture packing andscreenless gravel packs.38 Perforating require-ments for fracture packing are the same as forinternal gravel packs because it is more importantto minimize pressure drop through the pack andcontrol sand production than to create long frac-tures. However, efficient proppant placement isrequired to create an external pack. Big holeswith high shot density—12, 16, 18 or 21 spf—
and 60 or 45° phasing maximize flow area andprevent proppant screenout, or bridging, in theperforations.
In screenless gravel packs, the formation isconsolidated with resin and then fractured.Proppant injected in the fracture prevents the pro-duction of formation sand. Because proppant doesnot fill the perforations, perforating requirements
are more like conventional hydraulic fracturingstimulations. The length of perforated intervalshould be limited. Perforations that do not commu-nicate with the fracture may produce sand andneed to be eliminated or minimized. Hole diameterneeds to be 8 to 10 times greater than the proppantdiameter and perforations with 0 or 180° phasingshould be oriented to within 30° of the PFP.
36481, presented at the 71st SPE Annual TechnicalConference and Exhibition, Denver, Colorado, USA,October 6-9, 1996.
35. Behrman L, Willson SM, de Bree P and Presles C: “Field Implications from Full-Scale Sand ProductionExperiments,” paper SPE 38639, presented at the 72ndSPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, October 5-8, 1997.Presles C and Cruesot M: “A Sand Failure Test Can CutBoth Completion Costs and the Number of DevelopmentWells,” paper SPE 38186, presented at the SPE EuropeanFormation Damage Conference, The Hague, The Netherlands, June 2-3, 1997.
36. Venkitaraman A, Li H, Leonard AJ and Bowden PR:“Experimental Investigation of Sanding Propensity forthe Andrew Completion,” paper SPE 50387, presented at the SPE International Conference on Horizontal Well Technology, Calgary, Alberta, Canada, November 1-4, 1998.
37. Mason et al, reference 23.38. Behrmann and Nolte, reference 30.
34. Bruce S: “A Mechanical Stability Log,” paper SPE 19942,presented at the 1990 IADC/SPE Drilling Conference,Houston, Texas, USA, February 27-March 2, 1990. Weingarten J and Perkins T: “Prediction of SandProduction in Gas Wells: Methods and Gulf of MexicoCast Studies,” paper SPE 24797, presented at the 67thSPE Annual Technical Conference and Exhibition,Washington, DC, USA, October 4-7, 1992. van den Hoek PJ, Hertogh GMM, Kooijman AP, de Bree P,Kenter CJ and Papamichos E: “A New Concept of Sand Production Prediction: Theory and LaboratoryExperiments,” paper SPE 36418, presented at the 71stSPE Annual Technical Conference and Exhibition,Denver, Colorado, USA, October 6-9, 1996.Kooijman AP, van den Hoek PJ, de Bree P, Kenter CJ,Zheng Z and Khodaverdian M: “Horizontal WellboreStability and Sand Production in Weakly ConsolidatedSandstones,” paper SPE 36419, presented at the 71stSPE Annual Technical Conference and Exhibition,Denver, Colorado, USA, October 6-9, 1996.Blok RHJ, Welling RWF, Behrmann LA and VenkitaramanA: “Experimental Investigation of the Influence ofPerforating on Gravel-Pack Impairment,” paper SPE
> Single-trip gravel packing. A typical PERFPAC assembly includes a TCP gun with an automaticexplosive release, a bottom packer, sand-control screens, a gravel-pack packer with a flappervalve, pressure gauges and recorders, firing head and a dual-drillstring test valve. The TCP guns are positioned, fired, released and dropped (left). The assembly is then repositioned so that thescreens are across the perforated interval (right). The upper QUANTUM gravel-pack packer is setand gravel is injected behind the screen. The workstring is then disengaged, leaving the packedscreens in place. Operations take place in a controlled environment so formations are not exposedto overpressure, LCM or damaging fluids.
Preventing Sand Production Sand production in unconsolidated and some weakconsolidated formations results from tunnel col-lapse or formation failure between perforations. Toavoid subsequent problems that adversely affectproductivity and profitability, and limit well-inter-vention options, sand prevention must addresschanges in producing rates, formation stress andwater production. Once formation stability and per-foration failure thresholds are determined by mod-eling, laboratory testing or analysis of historicaldata, perforating methods are available to mini-mize sand production.39 Prevention implies anacceptably low risk of sand production.
More powerful big-hole charges, phase angleand excessive underbalance contribute to perfo-rating damage and potential interperforation fail-ure. To prevent sand production, perforationdesigns should minimize hole size in the forma-tion, pressure drawdown across perforated inter-vals and flow rate per perforation. Perforationsalso should be as far apart as possible. When alarge stress contrast exists in the formation andstress directions are known, oriented perforatingusing various systems can increase tunnel stabil-ity by taking advantage of minimum stress direc-tions.40 Selective perforating can avoid weakzones or formations altogether.
Because small-diameter perforations aremore stable than those created by big-holecharges, deep-penetrating charges are recom-mended for sand prevention. This also minimizesperforation damage, provides more stabilityduring drawdown and depletion, and increasesthe distance between perforations. Higher shotdensities keep drawdown, flow rate and dragforces through each perforation below a criticalvalue and minimize formation erosion.
Optimal underbalance perforating reducesperforation damage and avoids sanding fromcatastrophic tunnel failure that could stick guns.Perforation stability models help determineunderbalance limits that keep pressure draw-
down below the critical level of formation failure.Single-shot perforation and flow tests on corescan confirm underbalance values that preventsand transport, quantify the impact of increasingwater production and generally verify formationand perforation stability (above right).
In addition to single-perforation instability,interlinking of failure zones around adjacent per-forations, which is dictated by the distancebetween perforations, leads to formation collapseand sand production. Smaller holes and decreasedshot density increase perforation spacing, but thishas the undesirable effect of increasing flow rateand pressure drop per perforation, which exacer-
bate transport of failed formation material andmay lead to sand production.
A method for designing guns with optimalphasing and maximum distance between holeswas developed to further reduce the risk of for-mation collapse between perforations (below).41
By adjusting phase angle for a given wellboreradius and shot density, the distance betweenperforations can be increased to avoid interac-tion between adjacent perforations. Optimizedphasing minimizes interference and interlinkingof adjacent damaged zones, which reduces therisk of formation failure without compromisingflow rate per perforation.
68 Oilfield Review
39. Venkitaraman A, Behrmann LA and Noordermeer AH:“Perforating Requirements for Sand Prevention,” paper SPE 58788, presented at the SPE InternationalSymposium on Formation Damage Control, Lafayette,Louisiana, USA, February 23-24, 2000.
40. Sulbaran AL, Carbonell RS and López-de-Cárdenas JE:“Oriented Perforating for Sand Prevention,” paper SPE57954, presented at the 1999 SPE European FormationConference, The Hague, The Netherlands, May 31-June 1, 1999.
41. Behrmann LA: “Apparatus and Method for Determiningan Optimum Phase Angle for Phased Charges in aPerforating Gun to Maximize Distances BetweenPerforations in a Formation,” U.S. Patent No. 5,392,857(February 28, 1995).
4000
3000
2000
1000
0 2000Reservoir pressure, psi
Safedrawdown
1000
Wel
lbor
e pr
essu
re, p
si
400030000
Formation failure
Perforation stability. For sandprevention, stability analysiscan determine a safe operatingenvelope for pressure draw-down during production thatwill prevent perforation failureand the interlinking of failurezones around adjacent perforations.
0° 300° 360°240°180°120°60°
L1
L2
L3
> Optimal phasing for sand prevention. The actual perforation phasing in the formation depends on wellbore radius and shot density. A new methoddeveloped and patented by Schlumberger helps design guns with a phaseangle that maximizes the distances (L1, L2 and L3) between holes. The goal for a given shot density is to preserve the intervening formation as much as possible without compromising flow rate per perforation.
>
Spring 2000 69
The effectiveness of optimal phasing wasdemonstrated in the BP Amoco Magnus field inthe North Sea. The original perforating strategyused guns with 6 spf at 60˚ phasing (below left).In 1997, this was changed to 99˚ optimal phasingwhile maintaining the same shot density andcharge type. Wells perforated with the new gunshad fewer sand-related production problems. Theincrease in perforation spacing for an optimumgun phasing can be substantial compared withstandard gun phasing. For Magnus field, assum-ing a centralized gun, minimum perforation spac-ing was increased from 4.88 to 7.61 in. [12.4 to19.4 cm], a 56% increase, by changing from 60 to99˚ phasing.
Optimal underbalance and phasing inconjunction with deep-penetrating charges arepreferred in sand-prevention applications.Ultrahigh-shot density guns with deep penetra-tion also have been used to prevent sanding inweak, but consolidated rocks. However, evenwith perforating techniques for sand prevention,production flow may transport limited volumes ofdebris from perforation crushed zones and tun-nels. As in the case of sand control, transientsand production at surface needs to be dealt withuntil perforations are completely cleaned up.
An Overall Perforating Strategy Operated by Chevron and Conoco, the North SeaBritannia field is a gas reservoir (above). Beforethe wells were completed, potential sand produc-tion—perforation stability—and optimal under-balance pressure during perforating to minimize oreliminate perforation skin were major concerns.Theoretical models were used to predict optimalunderbalance conditions based on log-derived for-
mation properties. With detailed log permeabilitydata, numerous simulations were carried out toevaluate guns, charges, shot densities and perfo-rating strategies. Based on these simulations, finalcompletion designs included specific chargedesigns and shot densities for various formationsections instead of using average properties todetermine perforating parameters.42
In general, four key aspects of perforatinghave a major impact on productivity and play animportant role in determining well completionsuccess—perforation dimensions (length anddiameter), shot density, phasing angles anddegree of perforation damage. The choice of gunsystem parameters to optimize a completion wascarried out using theoretical analysis of comple-tion efficiency using inflow, or NODAL, analysisprograms. For the Britannia study, lithology varia-tions also were taken into account. Log and coredata were used to determine the productivity ofvarious individual layers based on conductivityand formation damage. For each layer, numericalproductivity simulations were carried out to deter-mine the optimal perforation parameters of shotdensity, penetration and underbalance conditions(below). An acceptable gun phasing was fixed.
Increasingstress
Formationfailure
60° phasing 99° phasing
> Optimal phasing. Optimal phasing was used successfully in the BP Amoco Magnus field in the North Sea to prevent failure of the formationbetween perforations. The original perforatingstrategy used 33⁄8-in. guns with 6 spf at 60˚ phasing (left). In 1997, this was changed to 99˚ optimal phasing while maintaining the same shot density (right). Wells perforated with the newguns had fewer sand-related production problems.
N
BraePiperClaymore
BuchanBeatrice
Montrose
Britannia
Forties
Fulmar
Aberdeen Erskine
Lomond
U K
> Britannia field location.
X300
X200
X100
X000
1000Underbalance, psi
Dept
h, ft
Permeability, mD10,000 0 300
Zone
BC
Formationthickness, ft
10.510
Permeability,mD
98.5620.3
Unconfinedstress, psi
89289346
Porosity, %
15.7713.54
Drawdown, psi (rate, MMscf/D)Rate 1 Rate 2 Rate 3 Rate 4227 (20)259 (5)
822 (40)643 (10)
1739 (60)1181 (15)
3401 (80)1935 (20)
Thickness of near-wellbore damage,
in.246810
not applicable4.914.384.033.68
not applicable4.994.403.713.12
0.7960.6460.5730.526
not applicable
0.8970.7110.6190.527
not applicable
Productivity index, MMscf/D/100psiZone B (98.56 mD)
5 spf, charge A 12 spf, charge X 5 spf, charge A 12 spf, charge XZone C (20.3 mD)
> Optimizing perforating strategies. For the Britannia field, lithology variations were taken intoaccount instead of just using average reservoir properties. Zone B had greater formation damagedepth than zone C. Charge A at 5 spf was used for zone B, resulting in about a 15% productivityincrease. Charge X at 12 spf was used for zone C, resulting in about a 10% productivity increase.
42. Underdown DR, Jenkins WH, Pitts A, Venkitaraman Aand Li H: “Optimizing Perforating Strategy in WellCompletions to Maximize Productivity,” paper SPE 58772,presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 23-24, 2000.
Current underbalance guidelines lead to largepressure differential requirements in high-strength, low-permeability zones. This issue wasaddressed during the Britannia study in single-shot perforate and flow tests on reservoir andoutcrop rocks conducted in the advanced flowlaboratory at SRC in Rosharon, Texas. Anotherconcern during underbalance perforating ispotential sand production from perforation col-lapse, which was also addressed in the single-shot studies that simulated downhole stress andflowing conditions.
Laboratory tests confirmed theoretical under-balance predictions and perforation stability.Reservoir and outcrop cores were perforatedusing simulated downhole conditions and under-balance pressures determined from simulations.The perforation strategy for this field wasselected based on results from this study. Flowperformance of perforated reservoir cores veri-fied earlier conclusions about formation sensitiv-ity to aqueous wellbore fluids—brine—andconfirmed perforation stability at high underbal-ance cleanup conditions. A 1000-psi [6.9-MPa]underbalance in outcrop sample tests resulted inlow perforation skin. Analysis of performanceafter completion indicated low to negative skin in12 wells. In addition to determining the best per-forating design for each completion application,this approach emphasized the need to study opti-mal underbalance, especially in gas formations,to optimize overall completion strategies.
Gun and Conveyance ChoicesShaped charges are placed in guns and conveyeddownhole to the correct depth by wireline, slick-line, tubing or drillpipe, and coiled tubing. Thereare two types of guns, capsule and carrier (below).Capsule guns, like the Enerjet and Pivot Gun sys-tems, are used in through-tubing electric wirelineand slickline perforating. Charges in capsule gunsare exposed to well conditions and must be encap-sulated in separate pressure-proof containers.Debris from these expendable guns is left in a wellafter firing. Carrier guns are conveyed on wirelineor slickline, tubing or drillpipe run by drilling andworkover rigs or snubbing units, and on coiled tub-ing with or without an electric line. In these guns,
charges and most of the debris are contained inhollow steel carriers that are retrieved or releasedand dropped to bottom after perforating.
Casing and through-tubing guns, both capsuleand carrier, were initially run on wireline; tubing-conveyed perforating (TCP) with HSD High ShotDensity guns became popular in the early 1980s.Through-tubing guns, including casing and HSDguns, are limited in gun size and length by wellcompletion design and surface pressure controlequipment. The use of underbalance is also lim-ited when guns are run on electric line. Gunsdeployed on tubing offer a wide variety ofchoices and allow for simultaneous underbal-ance perforating of long intervals.43
70 Oilfield Review
RetrievableEnerjet
StandardEnerjet
ExpendableEnerjet
Capsule guns
Carrier guns
111/16 -in.OD running
3.79-in.OD deployed
1.56-in. HSD gun4 spf zero phasing
2.0-in. HSD gun6 spf, 60˚ spiral
phasing
2.25-in. HSD gun6 spf, 60˚ spiral
phasing
5.85-in. Bigshot18 spf, 120˚/60˚
phasing
Patented chargepacking
6 5/8-in. Bigshot18 spf, 120˚/60˚
phasing
Pivot Gun
Tubing
Casing
Gun types. Perforating guns are classified ascapsule or carrier. A few examples are shown atright. Capsule guns are conveyed by wireline orslickline in through-tubing operations. Detonatingcords are exposed to downhole conditions, sothe charges are encapsulated in pressure-proofcontainers. Expendable through-tubing capsuleguns generate debris, which remains in a wellafter perforating. Carrier, or casing, guns areconveyed by wireline, tubing and coiled tubingand can be designed to retain debris inside thecarrier. Detonation occurs inside the carrierunder atmospheric pressure.
>
Spring 2000 71
Today, perforating often encompasses morethan traditional running and firing of guns.Perforating systems are an integral part of wellcompletion equipment and completion opera-tions that are designed to perform multiple oper-ations in permanent completions, such as settingpackers, pressure testing, perforating one ormore intervals and initiating tool functions, all ina single operation. The timing of perforatingevents, such as charge detonation, resultingshocks and gun release, are used to help ensurethat perforating TCP guns release and drop, evenin high-angle wells (right). Guns have beenreleased and dropped successfully in well pro-files up to about 84°.
Downhole operations—A family of X-Toolsperforating gun-actuated completion tools—wireline/coiled tubing explosive-type automaticrelease (WXAR), superfast explosive-type auto-matic gun release (SXAR), monobore anchor withexplosive-type release (MAXR), superfast explo-sive-type production valve (SXPV) and superfastexplosive-type vertical shock absorber (SXVA)—are designed to perform specific functions likefast release and dropping of gun strings afterperforating and opening valves. These functionsare initiated by an explosive on the same ballis-tic chain as the perforating guns. Actuation ofthese explosive devices after guns are firedgreatly increases the versatility of perforatingcompletion operations.
Gun length and perforating without killingwells—Total weight of long gun strings andrunning or retrieving guns under pressure restrictwireline, coiled tubing and tubing-conveyedperforating. However, these limitations areovercome by permanent completion perforating(PCP) systems.
The GunStack stackable perforating gun sys-tem, also known as Completions DownholeAssembly and Disconnect (CDAD), allows down-hole assembly of multiple gun sections to anylength with or without a rig. This equipment
allows underbalanced perforating of long inter-vals in one descent. The system can be deployedand retrieved by slickline, electric wireline orcoiled tubing. When necessary, gun sections canbe retrieved without killing the well. This systemcan be used to perforate wells without interrupt-ing production. In combination with techniqueslike WXAR or MAXR, the GunStack, or CDAD,system also allows guns to be run in sectionsaccording to available lubricator length andweight capacity of the conveyance method.
The first gun section is run and latched onto adownhole anchor, bridge plug or packer set bywireline for precise depth control. The gun stringalso can be landed against the bottom of a well.In this configuration, the string is not anchored.Consecutive sections are assembled and con-nected on top of each other until the required gunlength is achieved. Rather than simply stackingor latching, the connectors solidly connect eachgun section to the next. Guns can be discon-nected mechanically at any time. The connectorsdisconnect automatically after a delay that fol-lows gun detonation. This prevents gun sectionsfrom moving uphole during detonation and under-balance surge flow, and allows wells to be perfo-rated with maximum underbalance.
The CIRP Completion Insertion and Retrievalunder Pressure perforating system was designedso gun strings could be assembled at surface,inserted in wells, extracted and disassembledwithout killing the wells. The CIRP system facili-tates running long guns in and out of wells underpressure using wireline or coiled tubing. Thisallows an entire interval to be perforated at onetime with an appropriate underbalance.Retrieving and disassembling guns under pres-sure eliminate the need to drill deeper to allow
for dropping guns or the need to kill wells afterperforating. The CIRP system is used with gundiameters from 2 to 4.5 in. Gun lengths of 2000 ft[610 m] with up to 60 connectors have been run.
The completion FIV Formation Isolation Valvetool, integrated into the permanent completiondesign, allows long strings of perforating guns tobe run in and out of wells without hydrostaticoverbalance control. A fullbore completion valvethat is normally run below a permanent packer,the FIV tool acts as a downhole lubricator valveand isolates perforated intervals from the pro-duction string above. The gun length per run islimited only by weight restrictions of the con-veyance method used.
After perforating, guns are pulled above theFIV tool, which is closed by a shifting tool on theend of the gun string. Well pressure is bled offand the guns are retrieved. The FIV tool then isopened for production by applying a predeter-mined sequence of pressure cycles. The FIV toolalso can be opened and closed an indefinite num-ber of times with a mechanical shifting tool. Thisvalve system was developed for the BP AmocoAndrew field in the North Sea.44
Success of the FIV tool was the basis fordesign of a liner top isolation valve (LTIV) thatoperates on the same principles. The LTIV is afullbore ball valve that isolates formations fromcompletion fluid after a zone is completed withan uncemented liner. The LTIV tool is run directlybelow a liner-hanger packer and can be openedand closed as many times as required. Once theball is closed, the formation is isolated from com-pletion fluid until the well is ready for production.The valve holds pressure from above and below,which makes it suitable as a long-term barrier.
43. In June 1999, the longest gun to date, a special taperedHSD gun, was successfully fired in Well M-16 at the BP Amoco Wytch Farm field in southern England. Thisworld record gun string was 8583 ft [2616 m] long fromtop to bottom and shot with more than 25,000 CleanSHOTdeep-penetrating charges.
44. Patel D, Kusaka, Mason J and Gomersall S: “The Develop-ment and Application of the Formation Isolation Valve,”presented at the Offshore Mediterranean Conferenceand Exhibition, Ravenna, Italy, March 19-21, 1997.Kusaka K, Patel D, Gomersall S, Mason J and Doughty P:“Underbalance Perforation in Long Horizontal Well in theAndrew Field,” paper OTC 8532, presented at the 1997Offshore Technology Conference, Houston, Texas, USA,May 5-6, 1997. Mason J and Gomersall D: “Andrew/Cyrus HorizontalWell Completions,” paper SPE 38183, presented at the SPE European Formation Damage Conference, The Hague, The Netherlands, June 2-3, 1997.
Jet in
teract
ion w
ith w
ellbo
re flu
id
Maximum
annu
lus pr
essure
from gu
n swell
Jet ta
il exit
s gun
End o
f pen
etrati
on
Gun op
en to
well
bore
fluid
Reservo
ir rea
ction
X-Tool
valve
open
Jet ta
il form
s
Fluid column
Timing of perforating eventsafter charge detonation
10 100 1000microseconds milliseconds
Time
1 10 100 1000
response
Reservoirresponse
> The timing of perforating events. Today’s perforating systems do more than just deploy and fire gun strings. These systems often set packers, initiate pressure tests, perforate more than one interval and initiate downhole tool functions, all in a single operation. For example, the timing of charge detonation, resulting shocks, reservoir response and tool functionsare coordinated to ensure that guns drop to the bottom of wellbores.
High-angle wells—In high-angle and horizon-tal wells, wireline may not allow guns to descendunless a tractor is used. Coiled tubing is the pre-ferred conveyance method, unless a horizontalsection is so long that helical buckling occursbefore the perforating interval is reached.Tractors have also been used successfully toextend the maximum reach of coiled tubing. Inmany of today’s high-angle and extended-reachwells, there may be no alternative to TCP or PCP.
If mechanical pulling or pushing force mustbe exerted on a gun system, TCP, snubbing,coiled tubing and tractors offer more versatilitythan electric line and slickline. For long guns likethose used in horizontal wells, gun-string designmust consider tensile strength. High-strengthadapters and tapered gun strings have beenused successfully. Gun bending must also bemodeled and addressed.
Perforating-deployment technology hasevolved from early electric line and tubing-, ordrillstring-, conveyed guns, and now includescoiled tubing with or without electric line, snub-bing units, slickline and downhole tractors onwireline and coiled tubing. Each conveyancemethod has advantages and disadvantagesrelated to performing downhole operations, gunlength and pressure control, perforating withoutkilling wells, mechanical strength and wellboreangle, depth correlation, rigless intervention andgun type. To optimize perforation designs, thesepros and cons must be weighed for all gunsystems being considered for a specific comple-tion (above right). Other considerations includeunderbalanced perforating and timing or durationof operations.
Underbalance—Options for perforating withunderbalance have reached a high degree ofsophistication as a result of hardware for TCP orPCP and wireline anchoring devices. Whateverthe conveyance method, it is usually possible toperforate with sufficient underbalance. Practicalexceptions when optimal underbalance cannotbe achieved are depleted reservoirs, shallowwells or wells with existing open perforations.
For certain conditions, a high underbalance isneeded to clean out perforations and generatepost-shot flow. With wireline-conveyed guns, thisis possible only if anchoring devices are usedwhile shooting to prevent guns from being blownuphole. Anchoring devices are also recom-mended when the level of underbalance isunknown and guns are exposed to a sudden fluidinflux, as for example, when perforating newintervals in formations with differentially depletedproducing intervals.
A Wireline Perforator Anchoring Tool (WPAT)device was developed to anchor guns in slimholemonobore completions and prevent guns frommoving after detonation. The WPAT device, nowavailable in two sizes, one for 2-in. guns in 27⁄8-in. tubulars and another for 21⁄4-in. or 21⁄2-in. gunsin 31⁄2-in. completions, counteracts potentiallylarge forces generated by flowing fluids that canforce guns uphole with disastrous consequences.
The main application of the WPAT anchor is toperforate with extremely high underbalance.Another application is to protect cable weakpoints from high-tensile loads.
The tool has positive anchoring and releasingmechanisms. Mechanical slips are designed to benondamaging and can be retracted by jarringupward if guns become stuck after perforating.
A calibrated orifice that meters oil at a spe-cific rate provides the holding period, which canbe set for up to an hour. This allows sufficienttime to establish an underbalance, perforate andconduct a pressure drawdown test. The toolreleases automatically after the programmedtime elapses. The tool may be configured in twoways; one operates on well pressure and theother, for a dry hole, operates on pressure suppliedby a gas bottle that is part of the system.
Duration of operations—The timing of opera-tions varies for each well. If intervals are verticaland short—less than 40 ft [12 m]—and perfo-rated in balanced or overbalanced conditions,wireline perforating usually can be performed ina few hours and may be the most efficientmethod. If the interval is longer or has multiplesections, wireline operations require more thanone trip, which prevents use of underbalanceduring subsequent gun runs. As well deviationincreases, operating time increases, especially ifthe gun-string weight is low and surface pres-sure-control equipment is used. When well devi-ation exceeds about 65°, other conveyancemethods like TCP and PCP that require a longerrunning-in time must be used. If perforating inter-vals become significantly longer, the overall dura-tion of TCP is shorter than wireline operationsand the entire interval can be perforated withunderbalance for optimal perforation cleanup.
72 Oilfield Review
45. Huber KB and Pease JM: “Safe Perforating Unaffectedby Radio and Electric Power,” paper SPE 20635, pre-sented at the 65th Annual SPE Technical Conference and Exhibition, New Orleans, Louisiana, USA, September 23-26, 1990.Huber et al: “Method and Apparatus for Safe TransportHandling Arming and Firing of Perforating Guns Using aBubble Activated Detonator,” U.S. Patent No. 5,088,413(February 18, 1992).Lerche et al: “Firing System for a Perforating GunIncluding an Exploading Foil Initiator and an OuterHousing for Conducting Wireline Current and EFICurrent,” U.S. Patent No. 5,347,929 (September 20, 1994).
Through-tubing
SXAR
MAXR
WXAR
FIV
Wireline CIRP
Coiled Tubing CIRP
GunStack (CDAD)
Reservoir
1 Rig required for installation, but not for perforating 3
Guns are in place impeding cleanup2 Best in monobores 4
Requires suitable conveyor
TechniqueEconomics
1
3
3
3
3 44
1
1
2
4
Never s
hut in
well
High-an
gle w
ells
New w
ellBest
gun
_ size,
spf, p
enetr
ation
, hole
size
Horizon
tal w
ells
Workove
rs
No rig
requir
ed to
perfo
rate
No add
itiona
l drill
ing (ra
thole)
requ
ired
Reperf
orate
while p
roduci
ng
Reperf
orate
withou
t killin
g the
well
Shoot
pay z
one u
nderb
alance
d in o
ne ru
n
Optimum
perfo
ration
clean
up
Fast g
un re
moval to
surge
all p
erfora
tions
Remove
guns
withou
t con
trollin
g (kill
ing) w
ell
( )
Advantage
Limitations
> Conveyance choices. To optimize perforating operations, the advantages, disadvantages and limita-tions of all gun systems that are considered for a specific completion must be weighed. This table listsreservoir, economic and technical benefits of equipment that is used to perforate without killing a well.
Spring 2000 73
SafetyTwo types of detonators are used in perforatingguns: electrical detonators, or blasting caps, andpercussion detonators. Conventional electricaldetonators are susceptible to accidental applica-tion of power from electric potential differences(EPD), which constitutes a safety hazard.Percussion detonators that are used in TCP sys-tems actuate mechanically when a firing pinstrikes a pressure-sealed membrane and deto-nates a primary high explosive.
The S.A.F.E. Slapper-Actuated Firing Equip-ment system was developed to be immune frompotential differences created by radio-frequency(RF) radiation, impressed current from corrosioncathodic protection, electric welding, high-tension power lines and induction motors such astopdrives on drilling rigs. This system eliminatesthe need to shut down vital radio communicationsand equipment during perforating operations.45
The detonating mechanism in the S.A.F.E. sys-tem is an Exploding Foil Initiator (EFI) rather thana primary high explosive. To fire a gun, a capaci-tor in the downhole electronic cartridge ischarged and then allowed to discharge abruptly.The heat produced by this discharge vaporizes asection of metal foil, which slaps an adjacentexplosive pellet with sufficient energy to deto-nate it. This detonation shears a small aluminumflyer that impacts a booster that fires the gun. Amajor advantage of S.A.F.E. equipment is thatwellsite assembly is quicker than for conven-tional electrical detonators. Disadvantages of theS.A.F.E. detonator are cost and size, which takesup lubricator space.
The Secure detonator is a third-generationS.A.F.E.-type device that also uses an EFI. It doesnot contain primary high explosives or a down-hole electronic cartridge. A microcircuit performsthe same functions as the electronic cartridge andEFI together in a package that is similiar in size toa conventional electric detonator. The Secure sys-tem has all the technical advantages of S.A.F.E.detonators, but is more reliable, fully expendableand smaller so that gun strings can be shorter.
Perforation Design and AnalysisPerforated completions can be designed usingthe SPAN Schlumberger Perforating Analysissoftware, which predicts perforating efficiencyunder downhole conditions.46 The programcombines modules that estimate downhole pen-etration, calculate productivity and determineoptimal underbalance. In the first module, pene-tration depth and hole size are estimated for usein a second module, which calculates well pro-ductivity. Optimal underbalance for zero-skinperforations is determined by using algorithms inthe third module for currently accepted underbal-ance criteria.47 When calculations cannot bemade algorithmically, as in the case of correctingsurface-test penetration for in-situ environmen-tal conditions like rock strength and formationstress, an extensive database of perforatingperformance in Berea sandstone cores or slabs,API data and other test results is used.
In design mode, this software helps selectgun systems based on specific well parame-ters—completion geometry, fluids and under-balance (above). When actual underbalance isless than the minimum required for zero damage,perforation skin due to residual damage is calcu-lated to show how productivity is reduced.
The SPAN program also can be used toanalyze production after wells are completed orrecompleted. If actual production data matchSPAN program calculations, a perforated comple-tion is considered successful. When productionobjectives are not realized, the reasons—deepformation invasion, incomplete damage removalor incorrect assumptions—need to be deter-mined. Because the SPAN program incorporatesgeological aspects, it is helpful for integratingreservoir descriptions in perforation designs.48
Gun12345
Phase spfDescription4 1/2-in. HSD UltraJet4 1/2-in. HSD PowerJet1 11/16-in. Enerjet2 1/8-in. Power Enerjet4 1/2-in. HSD UltraJet
Prod
uctiv
ity ra
tio, p
erfo
rate
d co
mpe
tion
vers
us u
ndam
aged
ope
nhol
e
Crushed-zone versus formation permeability, Kc/K
Gun 2Gun 5Gun 1
Gun 4
Gun 3
00 0.2 0.4 0.6 0.8 1
0.3
0.6
0.9
1.2
1.5
Anisotropic ratio: 10Damaged-zone thickness: 4 in.
Ratio of damaged-zone versusformation permeability, Kd/K: 0.5Crushed-zone thickness: 1 in.
SPAN Version 6.0© Copyright 1999 Schlumberger
135°72°
0°0°
72°
125465
> Perforation design and analysis. The SPAN Schlumberger Perfo-rating Analysis program is used to predict completion efficiencyand select the best gun system. Underbalance calculations arebased on the most current criteria. If the actual pressure differen-tial is less than the minimum underbalance for zero damage, skindue to residual damage is calculated to show how productivity isreduced. Here well productivity is calculated for five gun types atdifferent shot densities and phase angles.
46. Carnegie A: “Application of Computer Models toOptimise Perforating Efficiency,” paper SPE 38042,presented at the SPE Asia Pacific Oil and Gas Conference, Kuala Lumpur, Malaysia, April 14-16, 1997.
47. Behrmann and Elbel, reference 32.48. de Araujo PF and Coelho de Souza Padilha TC:
“Integrating Geology and Perforating,” World Oil 218, no. 2 (February 1997): 128-131.
Smart PerforatingEvery cased well must have perforations toproduce hydrocarbons, but different reservoir and completion combinations have different per-forating requirements. Because perforating issuch a critical element of well productivity, therequirements of each well should be optimizedbased on specific formation properties. The bestway to achieve this is to understand how reser-voirs respond to natural, stimulated and sand-management completions. Factors that need tobe taken into account include formation com-pressive strength and stress, reservoir pressureand temperature, zone thickness and lithology,porosity, permeability, anisotropy, damage andfluid type—gas or oil.
Hard—high-strength—formations and reser-voirs damaged by drilling fluids benefit the mostfrom deep-penetrating perforations that extendbeyond the formation damage and increase theeffective wellbore radius. Low-permeabilityreservoirs that need hydraulic-fracture stimula-tion to produce economically require appro-priately spaced and oriented perforations.Unconsolidated formations that may producesand need big holes which reduce pressure drop
and can be packed with gravel to keep the for-mation particles out of the perforation and thewellbore. Perforations also can be designed toprevent tunnel and formation failure associatedwith sand production.
In the past, integrating formation and perfo-rating considerations, including underbalance,was an exception rather than a rule. Theory andsoftware were available to analyze perforationperformance, but completion decisions wereoften based on average formation properties orperforating limitations unrelated to productivity.Today, thinking in terms of what’s best for areservoir is the predominant approach. Operatorsconsider what a particular field developmentrequires and then select the best completiontechniques and hardware that are available.
Standard “off-the-shelf” equipment and ser-vices sometimes do not meet those needs. Newtools, procedures and services—shaped charges,completion equipment, conveyance alternativesand applications for underbalance, overbalanceor extreme overbalance—often need to be devel-oped. As a result, significant Schlumbergerresearch and engineering resources are dedi-
cated to developing customized solutions. Manyof these new developments eventually becomestandard products and services that extend the range of options available to operators. Thebest perforation designs are based on specificwell requirements to optimize production. Thistotal-systems approach—smart perforating—emphasizes practices that maximize well produc-tivity and helps operators realize the most benefitfrom the perforating solutions that are availableto overcome dilemmas associated with perfo-rated well completions (above).
By adapting perforation designs to specificreservoirs, perforating technology can be inte-grated with geology, formation evaluation andcompletion techniques to determine the rightequipment, shaped charge, carrier system, con-veyance method and pressure condition for per-forming efficient and effective perforatingoperations. Computer simulations can be used tocompare performance versus design expecta-tions. Existing tools and methods can then beimproved and used more effectively. The ultimategoal is to design custom perforating solutions foreach well to maximize productivity. —MET
74 Oilfield Review
ResearchReservoirconsiderations
StandardequipmentlimitationsSmart
perforating
Gun-activatedtools
Wirelineanchor
Formationrequirements
Hard rocks
WellrequirementsNo-kill
perforating
Sandcontrol
Capsule guns Carrier gunsTCP and
PCPconveyance
Hydraulicfracture
stimulation
Orientation Optionalphasing
Single-tripgravel
packing
UnderbalancePhaseangle
High-ratewells
High-anglewells
High shotdensity
Naturalfractures
Low-debrisguns
Formationdamage Big-hole
charges
Sandprevention
Wellproductivity
Perforating-induceddamage
Customsolutions
Deep-penetrating
charges
Shotdensity
Hole size
> Fitting together the pieces of the puzzle. The many perforating options and a myriadof well-completion factors exponentially increase the number of decisions that must bemade before perforating. A smart perforating systems approach helps operators realizemore benefit from perforating solutions that are available to overcome the technicaldilemmas associated with perforated completions.
Bill Bailey, who is a senior engineer with Schlum-berger Holditch-Reservoir Technologies (H-RT), isbased in Aberdeen, Scotland. There he has beeninvolved in various reservoir engineering and produc-tion enhancement studies in the UK, including water-control studies. He has been lead engineer and projectmanager for a number of projects in the UK, TheNetherlands and Norway and is also responsible forWellWatcher* data interpretation and support. Hejoined H-RT from Schlumberger Integrated ProjectManagement (IPM) in Aberdeen in 1999. At IPM hewas a production engineer and managed risk-analysisprojects in Norway. In conjunction with his technicalduties he has developed a number of in-house softwaretools including one to analyze possible economicexposure of gainshare-oriented well intervention campaigns. Before joining Schlumberger in 1997, heworked as project manager and postdoctoral seniorresearch engineer with the Horizontal Well Technol-ogy Unit at Heriot-Watt University, Edinburgh, Scot-land. There he helped develop simulation software forcomplex wells. He also worked for two years in a ser-vice company in Norway and as a management consul-tant with Arthur D. Little. Bill holds an MS degree inengineering (Hons) from Imperial College of Science,Technology and Medicine in London, England, and aPhD degree from Norwegian Technical University inTrondheim, both in petroleum engineering. He alsohas an MBA degree from University of Warwick inEngland. He currently serves as a technical editor for SPE Production and Facilities.
Larry Behrmann, Manager of Perforating Researchand Scientific Advisor since 1998, is also manager ofAdvanced Perforating Studies at the SchlumbergerReservoir Completions Center in Rosharon, Texas,USA. He is responsible for all perforating R&D activi-ties related to high-performance systems. His currentwork involves perforating physics under in-situ condi-tions. He began his career in 1961 as a technical staffmember of Bell Telephone Laboratories in Allentown,Pennsylvania, USA. From 1963 to 1965, he was a staffmember at Sandia Corporation in Livermore, Califor-nia, USA. In 1965 he joined Physics InternationalCompany in San Leandro, California, where his manyassignments included director of the ordnance divi-sion and manager of the shock-dynamics department.The author of numerous papers, Larry earned a BSdegree from University of California at Berkeley, andan MS degree from Lehigh University in Bethlehem,Pennsylvania.
James E. Brooks received a PhD degree in acousticsfrom Catholic University of America in WashingtonDC, USA, in 1979. Before joining Schlumberger Reser-voir Completions (SRC) in Rosharon, Texas, in 1980, he worked for the David Taylor Naval Ship R&D Center,focusing mainly on vibration and sound-radiationproblems. During the last 20 years at SRC, he hasmade contributions in the physics of shaped charges,perforating-gun design, advanced detonator designand well productivity through perforations.
Andrew Brown is a petroleum engineer involved in for-mation face completions issues (including perforating)at the BP Amoco Upstream Central Resource, in Sun-bury, England. His responsibilities include technicalsupport to BP Amoco business units, writing guidelinesand managing R&D projects. Since joining the com-pany in 1987, he has divided his time between fieldoperations (North Sea completions and well opera-tions) and central resource responsibilities at Sunbury.Andrew has a BS degree in civil engineering from theUniversity of Strathclyde in Scotland, and an MSdegree in petroleum engineering from Imperial Collegein London, England.
Mike Crabtree is water-management manager forSchlumberger Oilfield Services Marketing in Aberdeen,Scotland. He began his career with InternationalDrilling Fluids (IDF) first as an engineer and then asdevelopment manager in the Middle East and WestAfrica (1985 to 1989). He also worked for TR Oil Ser-vices as Middle East manager (1989 to 1995). Amonghis accomplishments is helping to develop low-toxicityoil-base mud and high-performance scale inhibitor and dissolver systems. He also was part of a team thatworked on design and implementation of an oil-spillrecovery system in Kuwait after the Gulf War. Mikeearned a BS degree in chemistry from University ofNewcastle in England.
Gérard Cuvillier, Drilling Team Leader at the Schlum-berger Deepwater Center of Excellence, is based inHouston, Texas. After graduation from Ecole Centraledes Arts et Manufactures in Paris, France, he began hiscareer with Total in 1974. His 10 years there includedassignments in drilling engineering and drilling andoperations management in the North Sea, Indonesia,Norway and Tunisia. He spent the next two years withForaid S.A. seconded to Total in Paris, where he wrotetwo manuals on deepwater drilling technology and handling of semisubmersible drilling rigs. From 1988 to 1990, he was marketing manager for southernEurope and Africa for Hughes Tool Company in France.In 1990 he moved to Ipedex in London, England, andwas seconded to Total as head of drilling for the Dunbardevelopment in the UK North Sea. Four years later hejoined Schlumberger as a senior well engineer with the Integrated Project Management (IPM) group.Before assuming his current position, Gérard was wellengineering manager for IPM worldwide, and projectmanager for the Yukos project in Western Siberia andfor the Alpetunnel project in France.
Glen Denyer, who is with EEX Corporation in Houston,Texas, supervises all 3D prestack depth-migration pro-jects, including velocity model-building and algorithmevaluation, as well as final depth image quality. He alsohas mapped numerous deepwater prospects in the Gulfof Mexico Garden Banks and Mississippi Canyon areasand was team leader of a partners’ group assembled to design and implement the first 3D vertical seismicprofile in the deepwater Gulf of Mexico. He began hiscareer with Western Geophysical in Houston in 1980.He spent the next 20 years in various positions withSeiscom Delta United, Tenneco Oil Exploration andProduction, Berrong Enterprises and the HoustonAdvanced Research Center. Before joining EEX in 1998,he worked at Swift Energy Company in Houston, wherehe was responsible for all company seismic data acqui-sition and processing. Glen obtained a BS degree inphysics from Sam Houston State University inHuntsville, Texas.
Geoff Downton, Engineering Manager at Schlum-berger Stonehouse Product Center, is based in Stone-house, England. In 1973 he joined British Aerospaceand became chief engineer and project manager forthe development of a wide range of military naviga-tion, guidance and tracking systems. From 1989 to1998, he worked in the nuclear industry (for NationalPower and Magnox among others) as technical andprogram manager for the development and fieldimplementation of remotely controlled and roboticsystems for inspection and repair of nuclear reactorsand waste-containment systems. He joined Schlum-berger in 1998. Geoff earned a BS degree (Hons) inmechanical engineering from University of Birming-ham, an MS degree in control systems engineeringfrom City University in London, and a PhD degree incybernetics and design from Brunel University, all inEngland. His special interests are control engineering,mathematical modeling and remote control.
Stephen Edwards is a geomechanics engineer withSchlumberger Holditch-Reservoir Technologies inHouston, Texas. There he works on application of geomechanics to wellbore construction and oilfielddevelopment issues. He joined the company in 1997.Stephen received a BA degree in earth sciences fromUniversity of Oxford and a PhD degree in geomechanicsfrom University of London, both in England.
Jon Elphick, who is based in Cambridge, England,has been a water-control specialist for Schlumbergersince 1994. He provides field technical support andtraining and develops new technology such as Water-CASE software. Before specializing in water control,he held various stimulation specialist jobs for Dowell,including managing the North Sea stimulation vesselBIGORANGE* 18. Previously, Jon was active in soft-ware development for Dowell in Paris and St. Etienne,France. Jon has a degree in mathematics from Univer-sity of Bath, England, as well as postgraduate diplo-mas in education and reservoir management.
Contributors
75Oilfield Review
An asterisk (*) is used to denote a mark of Schlumberger.
Simon Farrant, Wireline Perforating Manager atSchlumberger Reservoir Completions (SRC) inRosharon, Texas, is in charge of development of newwireline-conveyed perforating systems and perforat-ing InTouch field support. He has held this positionsince 1998. He joined Schlumberger in 1987 as awireline field engineer in Oman and subsequentlyworked in many countries in the Middle East. Afterholding various field operations management posi-tions in both the Middle East and the Far East, hemost recently served as location manager, offshoreThailand. Simon earned a BS degree (Hons) in geo-physics and planetary physics from the University ofNewcastle Upon Tyne in England, and also holds anMS degree in petroleum engineering from Heriot-WattUniversity, Edinburgh, Scotland.
Alfredo Fayard joined Schlumberger as a field engi-neer in 1979 after earning an engineering degree inelectronics and control systems from Universidad Tec-nologica Nacional in Buenos Aires, Argentina. In 1982,after assignments in Argentina, Peru and Mexico, hebecame engineer-in-charge of rig operations offshoreMexico. From 1983 to 1985, he was location managerof land operations in several areas of Mexico. Follow-ing a stint as a lecturer at the Schlumberger TrainingCentre in Livingston, Scotland in 1986, he becametraining manager for southern Europe and Africa, and for the next two years was stationed at the LatinTraining Centre in Parma, Italy. There he was respon-sible for implementing the training program for newlyrecruited Schlumberger engineers. In 1989 he becamemanager of Wireline & Testing for Northern Italy.From 1992 to 1996, he was technical manager fornorthern Africa and oversaw standards, safety andpersonnel training and development for his group. In1996 he transferred to the Schlumberger Perforating& Testing Center in Rosharon, Texas to manage designand implementation of short-term engineering pro-jects and to support all perforating products. In 1998Alfredo assumed his current position, Manager, Perfo-rating Gun Systems, responsible for engineering and manufacturing of all perforating products.
Andy Hendricks received his BS degree in petroleumengineering from Texas A&M University in CollegeStation in 1987. For the past twelve years he hasworked in various capacities for Anadrill, includingfield engineer, directional driller and manager in theGulf of Mexico, Venezuela, and Western and EasternCanada. Currently, as business development managerfor Schlumberger Oilfield Services in Atlantic andEastern Canada, based in Mount Pearl, Newfound-land, he oversees Schlumberger contracts for specificclients and works to establish GeoQuest and Camcobusiness units in the region. Before this (1996 to1999), he was based in St. John’s, Newfoundland, asAnadrill district manager and downhole drilling teamleader for the Schlumberger alliance with Hibernia.
Greg Johnson earned a BA degree in environmentalscience from the University of Colorado in Boulder,USA, in 1978 and then joined Western Geophysical.For the past 17 years he has held various positionswith Schlumberger, both in the United States andEurope. Greg was previously manager of Seismic Data Processing for Geco-Prakla in Calgary, Alberta,Canada, and senior geophysicist with the GeophysicalSupport group in Houston, Texas. Greg’s current position is structural imaging supervisor, within theInversion Services group of Reservoir Evaluation Seismic, in Houston. His areas of interest include 2Dand 3D seismic structural inversion and computer science technologies.
Trond Skei Klausen is a drilling engineer with NorskHydro, responsible for well planning for the Njord Project in Kristiansund, Norway. He began working forNorsk Hydro in 1997, as an engineer-trainee in opera-tional support in Bergen and then worked on the Oseberg B Project. He assumed his current position in 1999. Trond received an MS degree in engineeringfrom Norwegian University of Science and Technologyin Trondheim, with a major in drilling technology.
Fikri Kuchuk is chief reservoir engineer for Schlum-berger Oilfield Services in the Middle East, Pakistanand India. Previously, he was senior scientist and program manager at Schlumberger-Doll Research,Ridgefield, Connecticut, USA. From 1988 to 1994, hewas a consulting professor in the Petroleum Engineer-ing department of Stanford University in California,where he taught advanced well testing. Before joiningSchlumberger in 1982, he worked on reservoir perfor-mance and management for BP/Sohio PetroleumCompany. He has an MS degree from the TechnicalUniversity of Istanbul, Turkey, and MS and PhDdegrees from Stanford University, all in petroleumengineering. Among his honors and awards are the1994 SPE Reservoir Engineering Award, the NobelLaureate Physicist Kapitsa Gold Medal, the Henri G.Doll Award, and membership in the Russian Academyof Natural Sciences. His activity in the SPE hasincluded chairing many committees, programs andforums. Author of many technical papers and patents,Fikri also is the editor of Middle East ReservoirReview (formerly Well Evaluation Review).
José Eduardo Mendonça, Project Manager of thePROCAP project to develop gas-lift technology forultradeep water for Petrobras, is based in Rio deJaneiro, Brazil. Previously (1993 to 1998), he was project manager responsible for installing the firstsubsea electrical submersible pump in deep water(1109-m depth). He began in 1984 as a completionengineer for Petrobras, working offshore in the Campos basin. Two years later he joined the PetrobrasR&D Center, where he helped initiate the R&D CenterSubsea Engineering group. Since then he has beeninvolved in many projects including project managerof the Albacora Phase II diverless template-manifold,and project manager of the MEDUSA manifold fordeep water and development of the vertical connec-tion method. Holder of eight patents, José has adegree in mechanical engineering from Federal University, and an MBA degree in management fromGetúlio Vargas Foundation, both in Rio de Janeiro.
Charlie Michel is a senior petroleum engineer withthe BP Amoco Upstream Technology group. He beganhis career in 1982 with Sohio Petroleum Company inSan Francisco, California. From 1985 to 1987, he wasa petroleum engineer involved in the testing anddevelopment of the Lisburne Field, Alaska, USA. Hisnext assignment (1987 to 1995) involved well inter-vention design and job supervision in electric line,stimulation, coiled tubing, cementing, hydraulic frac-turing and exploration well testing in the PrudhoeBay field, Alaska. Before taking his current post in2000, he was a senior petroleum engineer responsiblefor well interventions and maintenance for the Mag-nus field. Charlie obtained a BS degree in chemicalengineering and an MBA degree, both from OregonState University in Corvallis, USA.
Alwyn Noordermeer is a petroleum engineer with theBP Amoco Shah Deniz project in Azerbaijan, where heworks on high-pressure well testing and openhole log-ging. He joined the company in 1998, and spent a yearworking as a petroleum engineer within the WellIntervention team in Dyce, Aberdeen, Scotland. Healso was involved in several projects, including Well-bay Design Guidelines, Inflatable Reliability Projectand Gas Injection System Guidelines. His next assign-ment was with the Magnus Delivery team, where heworked on 99 phasing perforation guns, planning andexecution of a wide variety of intervention programsand a study on water injector integrity issues. Alwynhas a BS degree in drilling and production engineer-ing from the University of Amsterdam, The Nether-lands, and an MS degree in petroleum engineeringfrom Heriot-Watt University in Edinburgh, Scotland.
Demos Pafitis is Steerable Systems product championin the Drilling and Measurements marketing grouplocated in Sugar Land, Texas. He has responsibility formarketing and new product introduction of steerablesystems, covering both new rotary steerable and tradi-tional steerable tools. Previously, Demos was sectionmanager for Power Systems, located in the SugarLand Product Center. He joined Schlumberger in 1991as a research scientist in the rock and fluid physicsdepartment at Schlumberger Cambridge Research inEngland. There he worked on projects related to zonalisolation, well cementing and novel completion tech-niques for horizontal wells. Demos received a BEdegree in materials science and engineering from theUniversity of London, and a PhD degree in materialsscience and metallurgy from the University of Cambridge, both in England.
Dick Plumb, Principal Consultant and Manager ofGeomechanics at Schlumberger Holditch-ReservoirTechnologies, is based in Houston, Texas. Previously,he was team leader of geomechanics Integrated Project Management (IPM) engineering, and geo-sciences coordinator for the IPM Support Center inHouston. Prior to joining IPM, he was responsible forcase studies in the interpretation and geomechanicsdepartment at Schlumberger Cambridge Research in England. He also worked at Schlumberger-DollResearch, Ridgefield, Connecticut, where he devel-oped log interpretation techniques for fracture characterization, in-situ stress measurements andhydraulic fracture containment. Dick earned a BAdegree in physics and geology from Wesleyan University,Middletown, Connecticut; an MA degree in geologyfrom Dartmouth College, Hanover, New Hampshire,USA; and a PhD degree in geophysics from ColumbiaUniversity in New York, New York, USA.
76 Oilfield Review
Christian Romano, Business Development Manager,Schlumberger Water Management Services in Caracas,Venezuela, is responsible for the Compression and Production Systems Water Management Services initiative. He began his career with Comex Services in Marseilles, France, involved in surface supports for subsea works. He joined Schlumberger in 1977 asearly production facility supervisor, and after threeyears as Venezuela operations manager was named fieldproduction and testing services manager. He then trans-ferred to Aberdeen as Production System group market-ing and technique manager for Wireline & Testing.Before taking his current assignment in 1997, he wasseconded to the asset management team of the LASMO-Schlumberger Dación Alliance as production and sur-face-facilities operation manager in Caracas. Christianis a graduate of Academy of Aix-en-Provence, France,where he majored in mechanical fabrication; he laterattended the MS degree program at the University ofMarseilles, St. Jérôme, majoring in metallurgy.
Leo Roodhart has 20 years of petroleum industryexperience with Shell International in the areas ofproduction technology, completions, smart wells, fracturing and stimulation, subsurface waste disposal,field development planning and produced water man-agement. Since 1996 he has been technology managerof Shell Water and Gas Management, and Well Stimula-tion. He is also a member of the extended leadershipteam of the Shell Technology Organization (SEPTAR).Previously he was production technology advisor andproduction engineering advisor and champion forShell’s Water and Gas Management Business Align-ment area. Author of numerous technical reports andconference papers, Leo holds an MS degree in physicalchemistry and a PhD degree in molecular physics,both from the University of Amsterdam in The Netherlands. He has served on many SPE committees;he currently chairs the SPE Netherlands section andthe SPE Forum Series Implementation Committee,and is a member of the Offshore Europe ConferenceCommittee.
Colin Sayers obtained a BA degree in theoreticalphysics from the University of Lancaster, a postgradu-ate degree (DIC) in mathematical physics and a PhDdegree in theoretical solid-state physics from ImperialCollege, University of London, England. After a post-doctorate fellowship at Imperial College, he joined the Materials Physics and Metallurgy division of theAtomic Energy Research Establishment at Harwell,England. From 1986 to 1991, he worked for Shellresearch in The Netherlands. In 1991 he joinedSchlumberger Cambridge Research in England, wherehe was program leader for seismic reservoir character-ization and monitoring. He has been a principal geo-physicist with Schlumberger Reservoir EvaluationSeismic in Houston, Texas, since 1998. His technicalinterests include single-sensor seismology, seismicpore pressure and drilling hazard prediction, multi-component seismology, seismic reservoir characteriza-tion, time-lapse seismic study, borehole-seismic integration, wave propagation in inhomogeneous and anisotropic materials, seismic velocity analysis,seismic anisotropy and fluid flow in fractured media.
Phil Smith, who is based at BP Amoco in Houston,Texas, provides well performance technical support forLatin American operations, with specific responsibilityfor formation damage, perforating and downholechemical treatments. He began his career at Interna-tional Drilling Fluids (IDF) Ltd. in 1982 as a researchchemist. His subsequent assignments with IDF inAberdeen, Scotland, included laboratory manager,technical services representative and senior opera-tions engineer. He joined BP Amoco in 1988 as a petro-leum engineer in Sunbury, England. From 1992 to1995, he served as senior production chemist inAberdeen. Before taking his current position in 1998,he was well productivity team leader, based in Bogota,Colombia. Phil earned a BS degree (Hons) in chem-istry from Loughborough University of Technology,Leicestershire, England.
Bertrand Theuveny has been Schlumberger supportmanager for 3-Phase Measurements AS in Sandsli,Norway, since 1997. He supervises support activitiesand after-sales support for hardware and metrology,and also oversees training on multiphase flowmeteringtechniques. He began in 1980 as an engineer in train-ing for Aerospatiale, Tactical Weapon division inFrance. In 1982 he became a mechanical engineer inCherbourg, France, assisting in construction manage-ment of an offshore platform. After working as aresearch assistant at the Geophysics Institute in Fair-banks, Alaska, he joined Flopetrol Johnston in 1985and worked in Tunisia, Mexico and France. In 1987 he moved to Wireline & Testing in Macae, Brazil, as atesting engineer and later as training center supervi-sor. After serving as field service manager in Brazil, he became W&T country manager for Algeria in 1992.Before his current assignment, he was W&T testingmanager for Tripoli and Libya. Bertrand received adegree in ocean engineering from Ecole Centrale deParis, France; and MS degrees in geophysics and inpetroleum engineering, both from the University ofAlaska in Fairbanks.
Jeb Tyrie is UK and Scandinavia operations managerfor Holditch-Reservoir Technologies in Aberdeen, Scot-land. There he is responsible for subsurface studies toassess all risks regarding Schlumberger involvement inrisk-reward contracts, and also for subsurface supportto the application of advanced Schlumberger servicesand tools for independent third-party subsurface studies.He began with BP in 1982 as a petroleum, reservoirand production engineer on various BP North Seafields. From 1991 to 1998, he was an independentreservoir engineering consultant in Norway and UK.During that period he formed a joint venture with TSCof Norway to promote and sell the FrontSim* stream-line simulator. He introduced streamline simulationtechniques to BP Amoco who adopted the methodworldwide. He joined Schlumberger in 1998. A char-tered engineer, Jeb holds a BS degree in natural philos-ophy, mathematics and chemistry from the Universityof Aberdeen and an MS degree in petroleum engineer-ing from University of Strathclyde, both in Scotland.
David Underdown, Technical Advisor for Chevron Production & Technology Company, is based at theHouston Drilling & Technical Center, Texas. There he is responsible for completion engineering, focusingon sand control and perforating. From 1984 to 1993, he worked for ARCO in Plano, Texas, as a completionengineer dealing with sand control and formationdamage issues. He spent the next two years as Presi-dent of UNITEC Consulting Company in Plano. From1995 to 1996, he worked as technical director for thePall Well Technology Division of the Pall Corporationin Port Washington, New York, responsible for pro-viding technical support to the division. He joinedChevron in 1996. David earned a PhD degree in phys-ical chemistry from the University of Houston. He was editor of SPE Monographs on Sand Control andCompletion Fluids. David is also a member of the SPE Awards Committee and a technical editor for the SPE Drilling & Completions journal.
Adi Venkitaraman is a completions development engi-neer who heads the Special Projects section of thePerforating Research group at Schlumberger ReservoirCompletions (SRC) in Rosharon, Texas. He joined SRCin 1993. From 1993 to 1997, he was in charge of variousprojects in the Advanced Flow Laboratory (both inter-nal projects and joint-industry projects with clients).Since 1997, his work focus has been on defining andimplementing best perforating practices in the fieldbased on laboratory experience. His current projectsinvolve optimization of soft rock completions forclients (sand control and prevention), and validationof in-house analytical perforation stability modelsthrough field application and data observation. Adiobtained an undergraduate degree in mechanical engineering from the University of Kerala, India, andan MS degree in petroleum engineering from the University of Texas at Austin.
Charlie Vise is team leader of Production & Interven-tion Services at the Schlumberger Deepwater Center of Excellence in New Orleans, Louisiana, USA. Therehe provides marketing and technical support to alldeepwater areas of the world. He began in 1982 as afield engineer in Houma, Louisiana. The next year hebecame a general field engineer for well testing andperforating services with Flopetrol Johnston inHouma, and later became a reservoir and productionengineer for the company in New Orleans. From 1987to 1994, he was technical sales engineer and thensenior technical sales engineer for completions andwell testing-cased hole services for Schlumberger Oilfield Services in New Orleans. He spent the nextthree years as business development manager for Well Testing Services in Louisiana, Scotland and France,responsible for developing new technical business lines(permanent downhole gauges, multiphase flowmeters,subsea well interventions, early production facilitiesand subsea services). Before assuming his current posi-tion in 1998, he was emerging technology coordinatorfor Schlumberger Oilfield Services in New Orleans.Charlie has a BS degree in petroleum engineering fromLouisiana State University in Baton Rouge.
Spring 2000 77
Time Machines: Scientific Explorations in Deep TimePeter D. WardSpringer-Verlag175 Fifth AvenueNew York, New York 10010 USA1998. 241 pages. $25.00 ISBN 0-387-98416-X
The book discusses changes that tookplace on earth from 80 to 65 millionyears ago, with a special interest in the Upper Cretaceous Nanaimo Groupstrata of Vancouver Islands. Conveyingthe scientific facts, it explains newaspects of geology in a clear and original fashion.
Contents:
• Finding Time: Fossils and the Birth of the Geological Time Scale; Radio-metric Clocks; Magnetic Clocks
• Place: Baja British Columbia;Ancient Environments and theLevel of the Sea
• Inhabitants: The Bite of a Mosasaur;Virtual Ammonites; The Ancestry of the Nautilus; Of Inoceramidsand Isotopes
• The Time Machine: Cretaceous Park
• Afterword, References, Index
The author has written his book inan interesting, entertaining, and educa-tional way that provides the readerwith accurate scientific conclusionswhile re-engineering the standardpresentation of standard geology orpaleontology books.
Teachers…will greatly enjoy andbenefit from this well-written book.
Michael F: AAPG Bulletin 83, no. 11 (November
1999): 1876.
Cenozoic Foreland Basins of Western Europe, Geological Society SpecialPublication No. 134A. Mascle, C. Puigdefàbregas, H. P.Luterbacher and M. Fernàndez (eds) Geological Society of LondonUnit 7, Brassmill Enterprise CentreBrassmill LaneBath BA1 3JN England1998. 400 pages. $117.00ISBN 1-86239-015-0
A collection of 18 papers primarily fromthe European Commission’s IntegratedBasin Studies project, this volume dealswith diverse aspects of the architectureand evolution of synorogenic flexuralbasins of the Alpine-Mediterranean system resulting from the Europe-Africa collision.
Contents:
• Tectonics and Sedimentation inForeland Basins: Results from theIntegrated Basins Studies Project
• Geophysical and Geological Con-straints on the Evolution of theGuadalquivir Foreland Basin, Spain
• Lateral Diapiric Emplacement of Triassic Evaporites at the SouthernMargin of the Guadalquivir Basin, Spain
• Alluvial Gravel Sedimentation in aContractional Growth Fold Setting,Sant Llorenç de Morunys, Southeast-ern Pyrenees
• Quantified Vertical Motions and Tec-tonic Evolution of the SE PyreneanForeland Basin
• Cyclicity and Basin Axis Shift in a Piggyback Basin: Towards Modelling of the Eocene Tremp-Ager Basin,South Pyrenees, Spain
• Fluid Migration During Eocene ThrustEmplacement in the South PyreneanForeland Basin (Spain): An IntegratedStructural, Mineralogical and Geo-chemical Approach
• Sequential Restoration of the ExternalAlpine Digne Thrust System, SEFrance, Constrained by KinematicData and Synorogenic Sediments
• History and Deformation Rates of aThrust Sheet Top Basin: The BarrêmeBasin, Western Alps, SE France
• Thin-Skinned Inversion Tectonics atOblique Basin Margins: Example of theWestern Vercors and Chartreuse Sub-alpine Massifs (SE France)
• Horizontal Shortening Control of Middle Miocene Marine SiliciclasticAccumulation (Upper Marine Molassein the Southern Termination of theSavoy Molasse Basin (NorthwesternAlps/Southern Jura)
• Evolution of the Western SwissMolasse Basin: Structural Relation-ships with the Alps and the Jura Belt
• Eustatic Versus Tectonic Controls onAlpine Foreland Basin Fill: SequenceStratigraphy and Subsidence Analysisin the SE German Molasse
• Reservoir Analogue Modelling of Sandy Tidal Sediments, Upper Marine Molasse, SW Germany, Alpine Foreland Basin
• Tectono-Stratigraphy and Hydrocar-bons in the Molasse Foredeep ofSalzburg, Upper and Lower Austria
• Automation of Stratigraphic Simula-tions: Quasi-Backward Modelling UsingGenetic Algorithms
• Numerical Modelling of Growth Strataand Grain-Size Distributions Associ-ated with Fault-Bend Folding
• Flexure and ‘Unflexure’ of the NorthAlpine German-Austrian MolasseBasin: Constraints from Forward Tectonic Modelling
• Index
…it will appeal to academicresearchers and petroleum explora-tionists seeking case studies of foreland thrust belts, and in general tothose interested in European geology.
The price is on the high side and this may limit its acquisition by individual geologists.
Teixell A: Journal of Petroleum Geology 22, no. 4
(October 1999): 458-459.
78 Oilfield Review
Coming in Oilfield Review
Seismicity in the Oil Field. Insome regions, hydrocarbon fielddevelopment has been seen toinduce earthquakes. To understandthe effects of oil and gas productionon seismicity, a recording networkwas installed in a producing field inRussia. Scientists analyze the datathat are recorded to help understandreservoir properties, monitor waterinjection and forecast seismic events.
Cementing Operations. Increasingefficiency and safety while reducingrig time are constant goals for anyoilfield operation. When it comes toequipment, however, bigger is notalways better, cheaper or easier touse. This article discusses the manyadvantages of a new, smallercement pumper that offers bettermaneuverability, lighter weight andimproved reliability while decreasingidle rig time during cementing jobs.
NMR Update. The latest generationof nuclear magnetic resonance(NMR) logging tools provide reliableinformation about formation porosityand pore fluids. New tool designsand improved processing haveincreased data acquisition speedand reduced logging costs. Wereview new applications that useNMR measurements along with datafrom other logs to provide robustgeologic characterization, formationevaluation, completion engineeringand reservoir optimization solutions.
Drill-Bit Design and Selection.Operators and contractors are happywhen well-drilling cost per foot—rigtime plus bit price divided by footagedrilled—is at a minimum. In this article, we review roller-cone, diamond and polycrystalline diamondcompact (PDC) bits. We also discussnew metallurgy that allows bits to be tailored to specific formations, whichgreatly improves performance. Withbetter seals, alignment and vibrationmonitoring, a single bit can often drillan entire section of hole.
NEW BOOKS
SCHLUMBERGER OILFIELD REVIEW
SPRING 2000
VOLUME 12 N
UMBER 1
Spring 2000
Oilfield Review
Deepwater Solutions
Rotary Steerable Drilling
Controlling Produced Water
Perforating Design Practices
