Autumn 2001

Characterizing Permeability

Improving Fluid Sampling

Global Warming

Selective Stimulation

Oilfield Review

SCHLUMBERGER OILFIELD REVIEW

AUTUMN

2001VOLUM

E 13 NUM

BER 3

50387schD4R7 12/10/01 9:43 PM Page 1

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With commercial production dating back to the 1870s, thehydrocarbon-producing industry has been in businesslonger than nearly any other. The fact that we are a matureindustry does not mean we are stagnating. As articles inthis issue of Oilfield Review show, we have continuallyadvanced in technology, practice and understanding.

One thing remains the same, however. The goal is still toproduce hydrocarbon as fast as possible, as long as possi-ble, and with minimal long-term consequences to environ-ment and people. The collection of technologies amassedto do this is impressive, but their success depends on howwell we understand the character of the reservoir that con-tains the hydrocarbons.

The maturity of the industry, wherein many reservoirsworldwide have become depleted, has drawn attention tothe importance of the variability and distribution of theproperties within reservoirs. We have, in fact, been in a so-called reservoir-characterization phase of industry maturi-ty for more than 10 years. And no reservoir property seemsto benefit more from good characterization than permeability.

Permeability is the property of a reservoir that describeshow fluid flows through it, and we know quite a bit aboutit. We know that permeability is determined by the numberand size of the pores within the reservoir. The pore size, inturn, depends on the size of the particles forming themedium, the amount of loading on the medium, and theamount of cements added after deposition. These complexdependences can defy efforts to correlate permeabilitywith other properties such as porosity. We also know thatwhile permeability can be measured in the laboratory,ways to measure it in the field are not as reliable.Pressure-transient analysis, a mature and often successfultechnology, can lead to measurements that are easily con-founded by other effects, one of which is uncertainty aboutthe volume of investigation. Permeability also seems to bethe most variable of petrophysical properties within areservoir. Ranges of 1000 or more from minimum to maxi-mum are common. All reservoirs appear to show signifi-cant permeability heterogeneity, although regions within areservoir can be fairly homogeneous.

We have learned a great deal about the distribution ofpermeability during this reservoir-characterization period,much of it from cores and outcrop study. We know thatsandstone heterogeneity appears to be set by the deposi-tion of the solid material; carbonate heterogeneity, by whathappened to it after deposition. Sandstone heterogeneityappears to be strongly correlated locally. This degree ofcorrelation is directionally dependent; permeability ismuch more correlated horizontally (lateral or parallel togeologic beds) than vertically (perpendicular to beds).

Advancing Our Understanding of Permeability

Heterogeneity in carbonate media is substantially greaterthan in sandstones. It is far less correlated locally than insandstones, and the differences in correlation direction(vertical versus horizontal) are less than in sandstones.Both carbonates and sandstones lend themselves to layer-like descriptions. Sandstones are layer-like because of thestrong horizontal correlation in their original deposition.Though post-deposition alterations tend to wipe out muchof the local correlation in carbonates, the low-frequencyportion that remains is strongly correlated and continuesto bear the imprint of the deposition.

These comments apply mainly to horizontal permeabili-ties. Much less is known about vertical permeabilities.These decrease with averaging scale but beyond that, welack knowledge, primarily because of the difficulty of mea-suring this quantity at a scale that is meaningful for subse-quent use. It is fairly obvious that the success of a horizon-tal well depends directly on having a large vertical perme-ability. What is less obvious is that vertical permeabilityseems to play a significant role in all recovery predictions.The article “Characterizing Permeability with FormationTesters,” page 2, looks into some of the issues associatedwith measuring vertical permeability.

Several questions about permeability heterogeneityremain. For example, we do not understand why post-depo-sition effects should randomize permeability in carbonatereservoirs. Nor do we understand the distinction betweenfracture-dominated and stratigraphic-dominated produc-tion behavior. Work needs to be done to understand theaveraging of horizontal and vertical permeability at pro-gressively larger scales of measurement. Horizontal aver-ages tend to increase with scale; vertical averages tend todecrease with scale. This issue is undoubtedly linked tothe subject of permeability distribution, which stillrequires more understanding.

Larry W. LakeDepartment of Petroleum and Geosystems EngineeringThe University of TexasAustin, Texas, USA

Larry W. Lake is a professor in the Department of Petroleum and GeosystemsEngineering at The University of Texas (UT) at Austin. He holds BSE and PhDdegrees in chemical engineering from Arizona State University in Tempe, andRice University in Houston, Texas, respectively. A prolific author, he has beenteaching at UT for 22 years. Before this, he worked for the Shell DevelopmentCompany in Houston. He has served on the Board of Directors for the Societyof Petroleum Engineers (SPE) as well as on several of its committees, and hasalso been an SPE distinguished lecturer.

50387schD05R2 12/10/01 3:14 PM Page 1

Advisory PanelTerry AdamsAzerbaijan International Operating Co., Baku

Antongiulio AlborghettiAgip S.p.AMilan, Italy

Abdulla I. Al-DaaloujSaudi AramcoUdhailiyah, Saudi Arabia

Syed A. AliChevron Petroleum Technology Co.Houston, Texas, USA

Svend Aage AndersenMaersk Oil Kazakhstan GmBHAlmaty, Republic of Kazakhstan

George KingBPHouston, Texas

David Patrick MurphyShell E&P CompanyHouston, Texas

Richard WoodhouseIndependent consultantSurrey, England

Executive EditorDenny O’BrienAdvisory EditorLisa StewartSenior EditorMark E. Teel EditorsGretchen M. GillisMark A. AndersenMatt GarberContributing EditorsRana RottenbergMalcolm BrownJulian Singer

DistributionDavid E. BergtDesign/ProductionHerring DesignMike MessingerSteve FreemanIllustrationTom McNeffMike MessingerGeorge StewartPrintingWetmore Printing CompanyCurtis Weeks

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. Oilfield Review is printed in the USA.

Contributors listed with only geographic location are employees ofSchlumberger or its affiliates.

© 2001 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.

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Oilfield Review subscriptions are available from:

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Oilfield Review is pleasedto announce the addition of Abdulla I. Al-Daalouj toits editorial advisory panel.Mr. Al-Daalouj graduatedfrom King Fahd Universityfor Petroleum and Mineralsin Dhahran, Saudi Arabia,with a degree in PetroleumEngineering. He joinedSaudi Aramco in 1982 andhas spent his career work-ing in the upstream sector,predominately in petro-leum engineering, produc-ing and oil operations. He is currently Manager-Southern Area ProducingEngineering Department.

50387schD06R1 12/05/2001 03:06 AM Page 1

Autumn 2001Volume 13Number 3

Schlumberger

2 Characterizing Permeability with Formation Testers

Permeability controls reservoir performance but is difficult to determine,often changing dramatically with scale and direction. Modern wireline forma-tion testers, equipped with packers and multiple probes, provide cost-effec-tive permeability data not reliably available with other techniques. Case stud-ies show how wireline-tester data, interpreted with new models, can nowquantify the effects of small but crucial baffles and super-permeabilitystreaks, as well as determine vertical and horizontal permeability at a lengthscale between those of cores and drillstem tests.

78 Contributors

82 New Books and Coming in Oilfield Review

Oilfield Review

1

60 Isolate and Stimulate Individual Pay Zones

With coiled tubing as a conduit for proppant-laden fracturing fluids, single ormultiple zones can be stimulated consecutively during a single mobilization.New tools selectively isolate target pay zones without conventional rigs orwireline intervention to set mechanical plugs. Individual zones are treatedseparately to achieve optimal fracture length and conductivity. Case studiesdemonstrate the expanding scope and economic benefits of this technique.

24 Quantifying Contamination Using Color of Crude and Condensate

Oil-base and synthetic-base mud filtrates contaminate openhole reservoir-fluid samples, distorting fluid properties measured in a laboratory. Thesefluid properties influence development and production decisions with significant economic consequences. Now, monitoring hydrocarbon colorallows a quantitative measure of contamination, improving the probability of collecting a valid fluid sample. In addition, a new, direct detection ofmethane downhole makes contamination measurement possible in gas-condensate zones.

44 Global Warming and the E&P Industry

The controversy surrounding global warming continues without a clear-cutconsensus as to its extent or implications. We examine the evidence and thearguments, both pro and con, the advances being made in computer simula-tion of global climate systems and the proactive steps being taken by oil andgas companies and service suppliers to reduce the impact of oilfield opera-tions on climate change.

Update and refine model

Comparison and

validation

Climate-system model

Computersimulation

Predictedbehavior

Observedbehavior

50387schD07R1 12/05/2001 03:10 AM Page 1

2 Oilfield Review

Characterizing Permeability with Formation Testers

Cosan AyanAberdeen, Scotland

Hafez HafezAbu Dhabi Company for OnshoreOperations (ADCO)Abu Dhabi, United Arab Emirates (UAE)

Sharon HurstPhillips PetroleumBeijing, China

Fikri KuchukDubai, UAE

Aubrey O’CallaghanPuerto La Cruz, Venezuela

John PefferAnadarkoHassi Messaoud, Algeria

Julian PopSugar Land, Texas, USA

Murat ZeybekAl-Khobar, Saudi Arabia

For help in preparation of this article, thanks to Mahmood Akbar, Abu Dhabi, UAE.AIT (Array Induction Imager Tool), CQG (Crystal QuartzGauge), FMI (Fullbore Formation MicroImager), MDT(Modular Formation Dynamics Tester), OFA (Optical Fluid Analyzer) and RFT (Repeat Formation Tester) aremarks of Schlumberger. RDT (Reservoir Description Tool) is a mark of Halliburton.

We never seem to know enough about permeability. We measure it at small scales

through laboratory tests on cores. We infer it at large scales from well tests and pro-

duction data. But to manage the development of a reservoir, we also need to quantify

features at intermediate scales. This is where the versatility of wireline formation

testers comes into play.

1. In direct measurements of fluid flow in rocks, the quan-tity measured is the mobility (permeability/viscosity).According to Darcy’s law, all fluid effects are accountedfor by the viscosity term, and permeability is independentof fluid. In practice, this is not exactly true, even withoutchemical interactions between rock and fluid. Absolutepermeability is also known as intrinsic permeability.

2. The term radial permeability, kr, describes radial flowinto a wellbore. In vertical wells, radial permeability isthe same as horizontal permeability. Vertical permeabilityis written both as kv and kz. Spherical permeability iswritten as ks.

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Autumn 2001 3

Modern wireline formation testers bring specialknowledge about reservoir dynamics that noother tool can acquire. Through multiple pres-sure-transient tests, they can evaluate vertical aswell as horizontal permeability. By measuring ata length scale between cores and well tests, theycan quantify the effect of thin layers that are notseen by other techniques. These layers play avital role in reservoir drainage, controlling gas-and waterflood performance, and leading tounwanted gas and water entries. Modern wire-line formation testers can also be a cost-effec-tive, environmentally friendly alternative toregular drillstem and pressure-transient tests.This article shows how permeability measure-ments derived from wireline formation testersare contributing to reservoir understanding andmaking an impact on reservoir development.

Which Permeability?Permeability determines reservoir and well per-formance, but the term can refer to many types ofmeasurements. For example, permeability can beabsolute or effective, horizontal or vertical.Permeability is defined as a formation property,independent of the fluid. When a single fluidflows through the formation, we can measure anabsolute permeability that is more or less inde-pendent of the fluid.1 However, when two or morefluids are present, each reduces the ability of theother to flow. The effective permeability is thepermeability of each fluid in the presence of theothers, and the relative permeability is the ratio ofeffective to absolute permeability. In a producingreservoir, we are most interested in effective per-meability, initially of oil or gas in the presence ofirreducible water, and later of oil, gas and waterat different saturations. To further complicatematters, effective and absolute permeabilitiescan be significantly different (see “ConventionalPermeability Measurements,” page 6).

Formations are usually anisotropic, meaningtheir properties depend on the direction in whichthey are measured. For fluid-flow properties, weusually consider transversely isotropic forma-tions, meaning formations in which the two hori-zontal permeabilities are the same and equal tokh, while the vertical permeability, kv, is different.Although more complicated formations exist,there are typically not enough measurements to quantify more than these two quantities.Permeability anisotropy can be defined as kv/kh,kh/kv, or the ratio of the highest to the lowest per-meability. In this article we will use kh/kv, a quan-tity that is most often greater than 1.2

The next complication is related to spatial dis-tribution. Reservoir management would be muchsimpler if permeability were distributed uniformly,but, in practice, formations are complex and het-erogeneous—that is, they have a range of valuesabout two or more local averages. The number ofmeasurements needed for a full description of aheterogeneous rock is impossibly high; moreover,the result of each measurement depends on itsscale. For example, for an idealized reservoir com-prising isotropic sand with randomly distributedisotropic shales, there are three scales to con-sider—megascopic (the overall reservoir), macro-scopic (the grid squares used in reservoirsimulation), and mesoscopic (individual facies)(above). The megascopic anisotropy is veryhigh—between 103 and 105. However, areas Aand B are isotropic, while the grid squares are intermediate, showing that the large-scaleanisotropy is in fact caused by local heterogene-ity. Measurements at different scales and in different locations will find different values forboth kh and kv and hence different anisotropy.

Which permeability to choose? In a single-phase, homogeneous reservoir, the question isirrelevant—but such reservoirs do not exist.Almost all reservoirs, and particularly carbon-ates, are highly stratified. For some formations,flow properties also vary laterally. For instance,in deltaic sandstone deposits, the world’s mostprolific reservoirs, flow properties vary laterallybecause of the sorting of sediments according tosize and weight during transport and deposition.Whether in sandstone or carbonate, as hetero-geneity increases, the distribution of permeabil-ity becomes as important as its average value.

Early in the life of a reservoir, the main concernis the average horizontal effective permeability tooil or gas, since this controls the productivity andcompletion design of individual wells. Later on,vertical permeability becomes important becauseof its effect on gas and water coning, as well asthe productivity of horizontal and multilateralwells. The distribution of both horizontal and ver-tical permeability strongly affects reservoir perfor-mance and the amount of hydrocarbon recovery,while also determining the viability of secondary-and tertiary-recovery processes.

A B

100

Dept

h, ft

Horizontal distance, ft200 300 400 500 600 700 800 900 1000

100

200

300

400

500

0

0

Grid square

> A cross section of an idealized reservoir that exhibits large-scale anisotropy caused by localheterogeneity. A sandstone reservoir (yellow) contains randomly distributed shales (gray). Thevertical permeability for the whole reservoir is about 104 times less than the horizontal perme-ability—a very large anisotropy. However, the small areas A and B are in isotropic sand andshale, respectively. The grid square, which might represent a reservoir-simulation block, hasintermediate permeability anisotropy. Vertical permeability is close to the harmonic average ofsand and shale permeabilities, while the horizontal permeability is the arithmetic average.[Adapted from Lake LW: “The Origins of Anisotropy,” Journal of Petroleum Technology 40, no. 4(April 1988): 395–396.]

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The magnitude of permeability contrastbecomes increasingly important with prolongedproduction. Thin layers, faults and fractures canhave a dramatic effect on the movement of a gascap, aquifer, and injected gas and water. Forexample, a low-permeability layer, or baffle, willimpede the movement of gas downwards. Ahigh-permeability layer, or conduit, will quicklybring unwanted water to a production well. Bothcan significantly affect the sweep efficiency andrequire a change in completion practices. Soundreservoir management depends on knowing notonly the average horizontal permeability but alsothe permeability distribution laterally and verti-cally, and the conductivity of baffles and conduits(left). As has been known for a long time, reser-voir heterogeneity is one of the major reasonswhy enhanced oil recovery is so difficult.Permeability heterogeneity, unexpected bafflesand insufficiently detailed reservoir evaluationare often the reasons that these projects fail tobe economical.3

In normal reservoir-engineering practice, themain sources of average effective permeabilityare pressure-transient well testing and produc-tion tests. These are usually good indicators ofoverall well performance. Cores and logs areused, but often after some matching, or scalingup, to well-test results. Once a reservoir has beenon production, conventional history matchinggives information on average permeability, butcannot resolve its distribution. The presence ofhigh- or low-permeability streaks and their distri-butions are inferred from cores and logs, but thisinformation is qualitative rather than quantitative.Wireline formation testers (WFTs) have steppedinto this gap, providing various measurements ofpermeability from simple drawdowns with a sin-gle probe to multilayer analyses with multipleprobes. The latter were originally used mainly todetermine anisotropy.4 With recently developedanalytical techniques and further experience,multilayer analyses now provide quantitativeinformation about permeability distribution.

Wireline Formation TestersEarly wireline formation testers were designedprimarily to collect fluid samples. Pressures wererecorded, so that the pressure buildups at the endof sampling could be analyzed to determine per-meability and formation pressure. In spite of thelimited gauge resolution and the few data pointsavailable, the results were often an importantinput to formation evaluation. Now, buildupsacquired after sampling are still analyzed to obtainan estimate of permeability at little extra cost.

The Schlumberger RFT Repeat FormationTester tool introduced the pretest, a short test

4 Oilfield Review

3. Weber AG and Simpson RE: “Gasfield Development—Reservoir and Production Operations Planning,” Journalof Petroleum Technology 38, no. 2 (February 1986): 217-226.

4. Ayan C, Colley N, Cowan G, Ezekwe E, Wannel M, Goode P,Halford F, Joseph J, Mongini A, Obondoko G andPop J: “Measuring Permeability Anisotropy: The LatestApproach,” Oilfield Review 6, no. 4 (October 1994): 24-35.

5. The so-called drawdown permeability is calculated as kd = C qµ /∆pss in units of mD, where q is the flow rate incm3/s, µ is the fluid viscocity in cp, and ∆pss is the mea-sured drawdown pressure in psi (and therefore includesany pressure drop due to mechanical skin). C, the flow-shape factor, depends on the effective radius of theprobe, and equals 5660 for the standard RFT and MDTModular Formation Dynamics Tester probes and theunits given.

Baffles Conduits

Sealing fault Nonsealing fault

Gig

a

Healed fractures Open fractures

Low-permeability genetic units High-permeability genetic units

Meg

a an

d M

acro

Low-permeability stylolite High-permeability stylolite

Tight laminations Small fractures

Shale lenses Vugs

Mes

o

Low-permeability recrystallizationfeature

High-permeability solution channel

> Permeability baffles and conduits at different length scales. In each case, reser-voir management can be improved by quantifying the effects of these features.

6. Dussan EB and Sharma Y: “Analysis of the PressureResponse of a Single-Probe Formation Tester,” SPEFormation Evaluation 7, no. 2 (June 1992): 151-156.

7. Jensen CL and Mayson HJ: “Evaluation of PermeabilitiesDetermined from Repeat Formation TesterMeasurements Made in the Prudhoe Bay Field,” paperSPE 14400, presented at the SPE Annual TechnicalConference and Exhibition, Las Vegas, Nevada, USA,September 22-25, 1985.

8. Goode PA and Thambynayagam RKM: “Influence of anInvaded Zone on a Multiple Probe Formation Tester,”paper SPE 23030, presented at the SPE Asia PacificConference, Perth, Western Australia, Australia,November 4-7, 1991. We might expect the buildup permeability to be higherthan kd since, by reading farther into the formation, itshould read closer to the effective permeability of theformation to oil or gas. However, in general experience,the buildup permeability reads lower.

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Autumn 2001 5

initially designed to determine whether a pointwas worth sampling. To the surprise of many,pretest pressure turned out to be representativeof reservoir pressure. As a result, pressure mea-surements became the main WFT application.Permeability could be estimated from both thedrawdown and the buildup during a pretest.Since a reliable pressure gradient requiredpretests at several depths, much more perme-ability data became available. With tens of testpoints in a single well, it became easier to estab-lish a permeability profile and compare resultswith core and other sources.

Pretests continue to be an important featureof modern tools, although the reliability of thepermeability estimate varies. Since pretestssample a small volume, typically 5 to 20 cm3

[0.3 to 1.2 in.3], the drawdown permeability, kd,can be overly influenced by formation damageand other near-wellbore features.5 Detailed anal-ysis shows that kd is closest to kh, although it isinfluenced by kv.6 The volume of investigation issignificantly larger than that of a core plug, but ofthe same order of magnitude. However, kd is typ-ically the effective permeability to mud filtrate inthe invaded zone rather than the absolute per-meability as obtained from core. Although somegood correlations between the two have beenfound, kd is generally considered to be the minimum likely permeability.7 Nevertheless, itcan be computed automatically at the wellsite,and is still used regularly as a qualitative indi-cator of productivity.

Pretest buildups investigate farther into theformation than drawdowns, several feet if the

gauge resolution is sufficiently high and thebuildup is recorded long enough. Except in low-permeability formations, buildup time is short, sothat the tool may be measuring the permeabilityof either the invaded zone, the noninvaded zone,or some combination of the two.8 As in the inter-pretation of any pressure-transient data, flowregimes are identified by looking for characteris-tic gradients in the rate of change of pressurewith time. For pretest buildups in which the flowregimes are spherical and occasionally radial,consistent gradients often prove hard to find, andeven then may be affected by small changes in

the pretest sampling volume. For reliable results,each pretest must be analyzed—a time-consum-ing process. Today, the analysis of short pretestbuildups for permeability is rare, mainly becausethere are much better ways to obtain permeabil-ity with modern tools.

Modular Wireline Formation TestersThe third-generation WFT is the modular tester.This tool can be configured with different mod-ules to satisfy different applications, or to handlevarying conditions of well and formation (below).

8 ft

2.3 ft~3 ft

6.6 ft

ks

A B C D E F G H

Inputport

Usually

Sometimes kh

kh,kv kh,kv kh,kv,φCt kh,kv,φCt ks and/or kh kh,kv kh,kv

φCt φCt

> Typical MDT tool configurations for permeability measurements: single probe with sample chamber and flow-controlmodule (A); a sink, normally the bottom probe, with one (B) or two (C) vertical observation probes; dual-probe modulewith one (D) or two (E) vertical probes; mini-DST configuration with dual-packer and pumpout module (F); dual-packermodule with one (G) or two (H) vertical probes. The flow-control module, sample chamber and pumpout module can beadded to any configuration. When only one pressure transient is recorded, as in (A) and (F), permeability determinationdepends on identifying particular flow regimes, type-curve matching or parameter estimation using a forward model.With one or more vertical probes, as in the other configurations, it is possible to perform a local interference test, alsoknown as an interval pressure-transient test (IPTT). With these tests, interpreters can determine kv and kh for a limitednumber of layers near the tool. Storativity, øCt, can be determined with the dual-probe module, and sometimes whenthree vertical transients are available, as in (C) and (H). With other configurations, it must be determined from otherdata. Pretest drawdown and buildup permeabilities can be determined with the dual-packer module and each probe in all configurations.

50387schD02R1.p5.ps 12/10/01 4:43 PM Page 5

6 Oilfield Review

Pressure-transient analysis, production tests, his-tory data, cores and logs are all used to estimatepermeability. Each measurement has differentcharacteristics, advantages and disadvantages.

Core data—Routine core measurements giveabsolute, or intrinsic, permeability. In shalyreservoirs with high water saturation or in oil-wet reservoirs, the effective permeability can besignificantly lower than the absolute permeabil-ity (right). Core data are taken on samples thathave been moved to surface and cleaned, so thatmeasurement conditions are not the same asthose made in situ. Some of these conditions,such as downhole stress, can be simulated onsurface. Others, such as clay alteration andstress-relief cracks, may not be reversible.

To be useful for reservoir characterization,there should be enough core samples to capturesufficiently the reservoir heterogeneity—variousstatistical rules exist to determine how manysamples are required. But it is not always possi-ble to capture a statistically valid range of sam-ples even in one well. Highly porous samplesmay fall out of the core barrel, while cuttingplugs from very tight intervals is difficult. Someanalysts prefer permeameter measurementsbecause more samples can be taken.1 Averaging,or scaling up, is another tricky issue. For lay-ered flow, the arithmetic average, kav =[∑ki hi/∑hi], is the most appropriate for the horizontalpermeability. For random two-dimensional flow,it is the geometric average, kav =[∏ki

hi / ∑hi],while for the vertical permeability, the harmonicaverage, kav =[∑ki

-1 hi/ ∑hi]-1, is important.2

Log data—Logs measure porosity and otherquantities that are related to pore size, forexample irreducible water saturation andnuclear magnetic resonance parameters.3

Permeability can be estimated from these mea-surements using a suitable empirical relation-ship. This relationship normally must becalibrated for each reservoir or area to moredirect measurements, usually cores, but some-times, after scaling up, to pressure-transientresults. The main use of log-derived permeabilityis to provide continuous estimates in all wells.On the economic side, cores and logs have manyapplications, so that the extra cost of obtainingpermeability from them is relatively small.

Well tests—Pressure-transient analysis of welltests measures the average in-situ, effective permeability of the reservoir. However, theresults have to be interpreted from the changeof pressure with time. Interpreters use severaltechniques, including the analysis of specificflow regimes, and matching the transient totype curves or a formation model. In conven-tional tests, the well is produced long enough tosample up to the reservoir boundaries. Impulsetests produce for a short time and are useful forwells that do not flow to surface. In both cases,but especially for impulse tests, there is notnecessarily any unique solution for permeability.

In most conventional tests, the goal is to mea-sure the transmissivity (khh/µ) during radialflow. The reservoir thickness, h, can be esti-mated at the borehole, but is it the same tensand hundreds of feet into the reservoir wherethe pressure changes are taking place? In prac-tice, other information—geological models andseismic data—helps improve results. With con-ventional well tests, the degree of heterogeneitycan be detected, but the permeability distribu-tion cannot be determined and there is no vertical resolution.

Conventional Permeability Measurements

> Typical relative-permeability curves for oil and water in a water-wetreservoir (top) and an oil-wet reservoir (bottom). Effective permeabilitiesare relative permeabilities multiplied by the absolute permeability. PointsA and A’ represent the typical situation for a wireline formation testerdrawdown measurement in water-base mud. In a water-wet reservoir, thefiltrate flows in the presence of 20% residual oil and has a relative perme-ability of 0.3. Points B and B’ represent the typical situation for pressure-transient analysis in an oil reservoir. In a water-wet reservoir, the oil flowsin the presence of 20% irreducible water and has a relative permeability of0.9. Points A, A’, B and B’ are also known as endpoint permeabilities. Someengineers refer relative permeabilities to the effective permeability to oilrather than the absolute permeability, as shown here.

0

0.2

0.4

0.6

0.8

1.0

0.20 0.4 0.6 0.8 1.0Sw

Rela

tive

perm

eabi

lity

0

0.2

0.4

0.6

0.8

1.0

0.20 0.4 0.6 0.8 1.0Sw

B ARe

lativ

e pe

rmea

bilit

y

Water-wet

B’ A’

Oil-wet

krw

kro

krw

kro

50387schD02R1.p6.ps 11/17/01 6:01 PM Page 6

7

Some of these modules are particularly relevantfor permeability measurements. The descriptionsof the modules below refer to the SchlumbergerMDT Modular Formation Dynamics Tester tool,unless otherwise specified.

The single-probe module—This module pro-vides communication between the reservoir andthe tool. It consists of the probe assembly,pretest chamber, strain and quartz pressuregauges, and resistivity and temperature sensors.The probe assembly has a small packer, whichcontains the actual probe. When a tool is set,telescoping backup pistons press the packerassembly against the borehole wall. The probe ispressed farther through the mudcake into contactwith the formation. Special probe-assemblydesigns are available for difficult conditions.9

Communication is established with the formationby a short pretest, after which the module canwithdraw fluids for sampling or act as a passivemonitor of pressure changes.

The dual-probe module—This module con-sists of two probe assemblies mounted in fixedpositions on the same mandrel. In the HalliburtonRDT Reservoir Description Tool, the probes aremounted above one another, separated by a fewinches and facing the same way.10 One probe,known as the sink probe, withdraws fluids, whilethe other monitors the pressure transient. In theMDT tool, the two probe assemblies aremounted diametrically opposite each other onthe mandrel.11 One probe is a sink while the other,known as the horizontal probe, is solely a moni-tor with no sampling capability. The main pur-pose of the dual-probe module is to combine witha vertical probe to determine kh, kv and storativ-ity (øCt) through a local interference test or, touse a more specific name, the interval pressure-transient test (IPTT).12 By withdrawing fluidthrough the sink, three pressure transients canbe recorded at three different locations along thewellbore, two of which are from monitor probesand are not contaminated by the effects of toolstorage, skin and cleanup.13

The dual-packer module—This module hastwo packer elements that are inflated to isolate aborehole interval of about 1 m [3.3 ft]. Once theseare inflated, fluid is withdrawn, first from the iso-lated interval, and then from the formation. Sincea large section of the borehole wall is now opento the formation, the fluid-flow area is severalthousand times larger than that of conventionalprobes. This offers important advantages in bothlow- and high-permeability formations, and inother situations.

• Probes are sometimes ineffective when set inlaminated, shaly, fractured, vuggy, unconsoli-dated or low-permeability formations. The dualpacker allows pressure measurements andsampling in these conditions.

• Used alone, the dual packer makes a small ver-sion of a standard drillstem test (DST) that isknown as a mini-drillstem test, or mini-DST.Since the mini-DST opens up only 1 meter offormation, it acts as a limited-entry test fromwhich both kv and kh may be determined underfavorable conditions. Used in combination withone or more vertical probes, the dual packercan record an IPTT.

• The pressure drop during drawdown is typi-cally much smaller than that obtained with aprobe. Thus, it is easier to ensure that oil isproduced above its bubblepoint, and thatunconsolidated sands do not collapse. Also,with a smaller pressure drop, fluids can bepumped at a higher rate, so that for the sametime period, a larger volume of formation fluidcan be withdrawn and a deeper-reading pres-sure pulse created.

Economically, well tests are expensive fromthe point of view of both equipment and rigtime. Well tests are also undertaken to obtain afluid sample so that the incremental cost ofdetermining permeability may be small.However, obtaining high-quality permeabilitydata often requires long shut-in times and extraequipment such as downhole valves, gauges and flowmeters.4

Production tests and production history—An average effective permeability can beobtained from the flow rate and pressure duringsteady-state production, preferably from specifictests at different flow rates. Skin and othernear-wellbore effects have to be known orassumed. An average permeability can also bedetermined from production-history data byadjusting the permeability until the correct his-tory of production is obtained. However, in bothcases, the permeability distribution cannot beobtained reliably. In the presence of layering orheterogeneity, this is a highly nonlinear inverseproblem, for which there can be more thanone solution.

In the absence of other data, permeability isoften related to porosity. In theory, the relationis weak—there are porous media that havebeen leached to give high porosity with zeropermeability, and others that have been frac-tured to give the opposite. However, in practice,there do exist well-sorted sandstone reservoirswith a consistent porosity-permeability relation.Other reservoirs are less simple. For carbonaterocks in particular, microporosity and fracturesmake it almost impossible to relate porosity andlithofacies to permeability.

1. Zheng S-Y, Corbett PWM, Ryseth A and Stewart G:“Uncertainty in Well Test and Core Permeabilty Analysis:A Case Study in Fluvial Channel Reservoirs, NorthernNorth Sea, Norway,” AAPG Bulletin 84, no. 12 (December2000): 1929–1954.

2. Pickup GE, Ringrose PS, Corbett PWM, Jensen JL andSorbie KS: “Geology, Geometry, and Effective Flow,”paper SPE 28374, presented at the SPE Annual TechnicalConference and Exhibition, New Orleans, Louisiana, USA,September 25-28, 1994.

3. Herron MM, Johnson DL and Schwartz LM: “A RobustPermeability Estimator for Siliclastics,” paper SPE 49301,presented at the SPE Annual Technical Conference andExhibition, New Orleans, Louisiana, USA, September 27-30, 1998.

4. Modern Reservoir Testing. SMP-7055, Houston, Texas,USA: Schlumberger Wireline & Testing, 1994.

9. For the MDT tool these include: large-area packers fortight formations; large-diameter probes for unconsoli-dated as well as tight formations; long-nosed probes forunconsolidated formations and thick mudcakes; andgravel-pack probes and a large-area filter similar to anautomobile oil filter for extremely unconsolidated sands(the Martineau probe).

10. Proett MA, Wilson CC and Batakrishna M: “AdvancedPermeability and Anisotropy Measurements WhileTesting and Sampling in Real-Time Using a Dual ProbeFormation Tester,” paper SPE 62919, presented at theSPE Annual Technical Conference and Exhibition, Dallas,Texas, USA, October 1-4, 2000.

11. Zimmerman T, MacInnes J, Hoppe J, Pop J and Long T:“Applications of Emerging Wireline Formation TestingTechnologies,” paper OSEA 90105, presented at the 8th Offshore Southeast Asia Conference, Singapore,December 4-7, 1990.

12. The term vertical interference test (VIT) is also used forvertical wells. The terms local interference test andinterval pressure-transient test are appropriate for devi-ated or horizontal wells.Storativity is the product of porosity, ø, and total rockcompressibility, Ct, which is the sum of the solid com-pressibility, Cr, and the fluid compressibility, Cf . When notmeasured by an IPTT, Cf must be estimated from fluidproperties and Cr from knowledge of the solid frameworkbased on acoustic logs, porosity and other data. If thereis more than one fluid, the saturation of each fluid is esti-mated from logs or sample volumes.

13. Skin is defined as the extra pressure drop caused bynear-wellbore damage (mechanical skin), flow conver-gence in a partially penetrated bed, and viscoinertialflow effects (usually ignored). The flow-convergencefactor can be calculated from knowledge of bed thick-ness and test interval. Tool storage is due to the compressibility of the fluid inthe tool, and causes the measured flow rate to be differ-ent from the actual flow rate at the formation surface, or sandface. Cleanup refers to the increase in flow rateas the flow of fluids removes formation damage near the borehole.

Autumn 2001

50387schD02R1.p7.ps 12/10/01 4:43 PM Page 7

The pumpout module—This module pumpsfluid from the formation into the mud column, andfrom one part of the tool to another. Pumping intothe mud column allows much larger volumes offluid to be withdrawn than when sampling intofixed-volume sample chambers. The module canalso pump fluid from one part of the tool toanother; from the mud column into the tool, forexample to inflate the packer elements; or intothe interval between the packers to initiate asmall hydraulic fracture. For permeability mea-surements, the pumpout module is capable ofsustaining a constant, measured flow rate duringdrawdown, thereby simplifying considerably theinterpretation of pressure transients. The flowrate though the pump depends on the pressuredifferential, increasing at low differential to amaximum of 45 cm3/s [0.7 gal/min]. At very highdifferential, such as in a tight rock, the pump maynot be able to maintain a constant rate.

The flow-control module—This module with-draws up to 1000 cm3 [0.26 gal] of fluid from theformation while controlling and measuring theflow rate. The fluid withdrawn is either sent to asample chamber or pumped into the borehole.The module works in various modes such as constant flow rate, constant pressure andramped pressure, and can also draw repeatedpulses of fluid from the formation. The time forpulses to arrive at a vertical probe is an impor-tant input in the determination of kv. Since theflow-control module can control flow rate pre-cisely, it can regulate the withdrawal of sensitiveformation fluids into small-volume pressure-vol-ume-temperature (PVT) sample bottles. This isimportant for the sampling of condensate reser-voirs. (For more on sampling, see “QuantifyingContamination Using Color of Crude andCondensate,” page 24).

All these features provide many ways to mea-sure permeability, ranging from simple pretestdrawdown to multiple probes and dual packers(right). For the most reliable in-situ determinationof permeability and anisotropy, experience hasshown that interference tests should be per-formed with multiple pressure transients. Resultsfrom other methods will always be more ambigu-ous, but can still be useful, and even good, esti-mates in the right conditions. One such techniqueis the mini-DST.

8 Oilfield Review

Three probe(sink, horizontaland vertical)

• Analysis can be done without sink drawdown

Second verticalprobe

• Best configuration for layered reservoirs, faults and fractures

• Gives kh and kvDual packer+ probe ortandem probes

• Smaller vertical investigation than other IPTT configurations (sometimes an advantage)

• Longer tool

• Need to have a good idea of φCt

Probe • Simplest method of establishing communication with formation• Multiple probes can be added in one tool string

Dual packer • Easier to test fractured, vuggy and tight formations

• Difficult to get good tests in fractured, vuggy and tight formations (difficult to withdraw fluids, seal failures)• High drawdowns in low k/µ formations may release gas, complicating analysis

Drawdown • Automatic computation, available during acquisition

Buildup • Deeper radius of investigation than drawdown

• Fear (usually unjustified) of sticking or of releasing gas slug into borehole

• Data available while samplingDual-packermini-DSTor extendeddrawdown andbuildup withprobe

• Need a particular combination of formation properties and thickness to get both kv and kh

• At same flow rate as probe, less drawdown helps avoid gas and sanding• For same time period as probe, more fluid is withdrawn, creating deeper pulse

• Low drawdown may give insignificant signals at vertical probes in high k/µ formations

Flow Source

• Many (tens) of pretests often recorded for pressure, allowing qualitative comparisons

Probe Pretest

• Small volume of investigation (inches)• Measures effective permeabiliby to mud filtrate

• Many (tens) of pretests often recorded for pressure, allowing qualitative comparisons

• Small sampling volume, cleanup and tool storage can make analysis difficult• Measures effective permeability to mud filtrate, formation fluid or a mixture of the two

Single-Transient Analysis

• Gives ks and/or kh and can avoid costly DST

• Need to know φCt to get ks, and need to know h to get kh• Tool storage, skin, free gas and continuous cleanup can complicate analysis (especially with probe)

Dual-Transient IPTT

• The simplest configuration for an IPTT • Sink drawdown and early buildup affected by tool storage, skin, free gas and cleanup

Multiple-Transient IPTT

• Gives φCt as well as kh and kv

• Analysis can be done without sink drawdown

Advantages Limitations

> Features of the flow sources and methods used to derive permeability from the MDT tool.

50387schD02R1.p8.ps 01/10/2002 03:52 PM Page 8

14. In one recent job, the pumpout module was run continu-ously for 36 hours. In another job, the dual-packer mod-ule was in the hole for 11 days.

15. Ayan C and Nicolle G: “Reservoir Fluid Identification andTesting with a Modular Formation Tester in an AgingField,” paper SPE 49528, presented at the 8th Abu DhabiInternational Petroleum Exhibition and Conference, AbuDhabi, UAE, October 11-14, 1998.

16. Tool storage includes the compressibility of the fluidbetween the packers. A common model is to relate thesandface flow rate, qsf, to the measured flow rate, q, andthe rate of change of pressure by a constant, C: qsf =q+24Cdp/dt. The very early part of a buildup is dominatedby wellbore storage, also called afterflow. C can be esti-mated from the rate of change of pressure at this time.

Autumn 2001 9

Mini-DSTsIn a standard DST, drillers isolate an interval ofthe borehole and induce formation fluids to flowto surface, where they measure flow volumesbefore burning or sending the fluids to a disposaltank. For safety reasons, many DSTs require thewell to be cased, cemented and perforatedbeforehand. The MDT tool, in particular the dual-packer module, provides similar functions to aDST but on wireline and at a smaller scale.

The advantages of the mini-DST are less costand no fluids to surface. Cost benefits come fromcheaper downhole equipment, shorter operatingtime and the avoidance of any surface-handlingequipment. On offshore appraisal wells, cost sav-ings can be more than $5 million. With no fluidsflowing to surface, there are no problems of fluiddisposal, no surface safety issues and no prob-lems with local environmental regulations. Mini-DSTs are much easier to plan and can test multiplestations on the same trip—usually a sufficientnumber to sample the entire reservoir interval.

The mini-DST has disadvantages: it investi-gates a smaller volume of formation due to thesmaller packed-off interval (3 ft versus tens offeet), and withdraws a smaller amount of fluid ata lower flow rate. In theory, we may be able toextend the tests and withdraw large amounts offluid, but in practice, there may be a limit to howlong the tool can safely be left in the hole.14 Theactual depth of investigation of a wireline testerdepends on formation permeability and other fac-tors, but is of the order of tens of feet, rather thanthe hundreds of feet seen by a normal DST.

The smaller volume of investigation is notnecessarily a disadvantage. A full DST reveals theaverage reservoir characteristics and assessesthe initial producibility of a well. Permeabilityvariations will be averaged, and although theycontribute to the average, they are neitherlocated nor quantified. With the help of logs, thesmaller volume mini-DST can evaluate key inter-vals. The procedure for interpreting pressure tran-sients from mini-DSTs is the same as for full DSTsand the same software can be used for both.

TotalFinaElf used mini-DSTs in the Arab reser-voir of an aging Middle East field to look for zoneswith moveable oil and to calibrate the permeabil-ity anisotropy used in a simulation model.15 Sincethe packed-off interval rarely covers the wholereservoir, a mini-DST is a limited-entry, or partiallypenetrating, well test. To determine formationparameters, interpreters need to identify flowregimes in the buildup. In a homogeneous layer,there are three flow regimes: early radial flowaround the packed-off interval, pseudosphericalflow until the pressure pulse reaches a boundary,

and finally total radial flow between upper andlower no-flow boundaries. Rarely are all threeseen because tool storage effects can mask theearly radial flow, while the distance to the near-est barrier determines whether or not the otherregimes are developed during the test period.16

However, it has been common to observe a pseu-dospherical flow regime, and occasionally totalradial flow in buildup tests (below). On a log-logplot of the pressure derivative versus a particularfunction of time, spherical flow is identified by a slope of –0.5, and radial flow by a stabilized horizontal line.

Spherical permeability, ks=3√(k2hkv) can be

estimated from a pressure-derivative plot duringspherical flow or from a separate specialized

plot.17 Horizontal permeability, kh, can be esti-mated from a pressure-derivative plot duringradial flow, or from a specialized plot of pressureversus Horner time, provided the thickness of theinterval is known.18 In this case, the thicknesswas obtained from openhole logs, particularlyimages from the Schlumberger FMI FullboreFormation MicroImager tool. When both spheri-cal- and radial-flow regimes occurred, the inter-preters could estimate vertical permeability, kv,from kh and ks. These initial estimates were com-bined with the geological data to build a model offormation properties. Different analytical tech-niques, such as type-curve matching, were thenused to match the full pressure transient andimprove the permeability estimates.

0.1 1 10 100 1000Time since end of drawdown, sec

0.01

0.1

1

10

100

1000

Pres

sure

diff

eren

ce, p

sia,

and

der

ivat

ive

Sphericalflow

Radialflow

Type-curve parameters:kh = 39 mDkv = 24 mDµ = 1 cpThickness of zone = 8 mMechanical skin = 1.3

Measured pressure differenceMeasured derivativeModel pressure differenceModel derivative

> Pressure difference and the derivative of pressure withrespect to a function of time for the buildup at the end of a typi-cal mini-DST. The pressure difference is between the measuredpressure and a reference taken near the end of the drawdownperiod. The derivative is calculated from d∆p/dln[(tp+∆t)/∆t]where tp is the producing time and ∆t is the time since the end of the drawdown. We identify spherical flow by the slope of –0.5 on the log-log derivative, and radial flow by the slope of 0 (horizontal). The solid lines are the results of a type curve, ormodel, computed with the parameters in the table.

17. On a specialized spherical plot, the slope, msp duringspherical flow is given by: msp = 2453qµ(√µøCt)/ks

3/2 inoilfield units, where ø is usually taken from logs, and q,the flow rate, is measured or estimated. The viscocity, µ,is determined from the PVT properties of the mobile flu-ids. If there is more than one mobile fluid, their satura-tions are estimated from logs or sample volumes.

18. Horner time is [(tp+∆t)/∆t] where tp is the drawdowntime, and ∆t is the time since the end of the drawdown.The slope, mr , during radial flow is given by mr =162qµ/khh, where h is the thickness of the formationinterval, and the other terms are defined in reference 17.

50387schD02R1 11/29/01 4:24 AM Page 9

TotalFinaElf recorded ten tests in two wells,one of which was cored. Both kv and kh were sub-sequently measured on core plugs sampled every0.25 or 0.5 m [9.8 or 19.6 in.], and compared withthe mini-DST results (below). Care was taken toscale up the core data to the mini-DST intervaland to convert from absolute to effective perme-ability. For some of the tests, pressure-transientdata were also available from two probes in theMDT tool string, making it possible to comparemini-DST results with results from a full IPTT as

well as from core samples. The IPTTs measurelarger volumes of formation, yet the results gen-erally agree with the mini-DST, especially for thenear probe. The fact that the different measure-ments agree suggests that the formations may berelatively homogeneous, or that the scaling up ofthe core data was appropriate. While this goodagreement validates the use of a mini-DST inthese conditions, it is inadvisable to assume thesame degree of homogeneity in other formations.

Cased-Hole Mini-DSTsPhillips Petroleum, operating in the Peng Lai fieldoffshore China, found that cased-hole mini-DSTswere a valuable complement to full DSTs andopenhole WFTs in evaluating their reservoir.19

Like many operators, they initially ran mini-DSTsto obtain high-quality PVT samples, but thenfound that the pressure-transient data containedvaluable information. Peng Lai field consists of aseries of stacked, unconsolidated sandstonereservoirs with heavy oil—11° to 21° API—oflow gas/oil ratio (GOR), whose properties varywidely with depth. Testing each reservoir in eachwell with full DSTs was proving expensive, andwas not always successful. Among other factors,the handling of the heavy oil at surface causedeach DST to last between five and seven days.Large drawdowns, which were sometimesneeded to lift the oil to surface, caused the for-mation to collapse and the near-wellbore pres-sure to drop below the bubblepoint. As a result,mini-DSTs were an attractive alternative for allbut the largest zones.

With a probe, the drawdowns were too high,while unstable boreholes and high pressure dif-ferentials made openhole wireline testing with adual-packer module risky. Phillips’ answer was torun the dual packer in cased holes. By the end of2000, they had performed 27 cased-hole mini-DSTs in seven wells. In one typical test, theyidentified a 3-ft low-resistivity zone that was iso-lated from the main reservoir at the well by thinshales above and below (next page, left). Aftercement isolation was checked, a 1-ft [30-cm]interval was perforated, and the MDT dual pack-ers were set across it. Communication wasestablished, and the formation fluid was pumpedinto the borehole until the oil fraction stabilized(next page, top right). Two oil samples weretaken, and after an additional drawdown, a pres-sure buildup was recorded over 2 hours. The totaltesting time of 16 hours would normally be con-sidered excessive and risky in openhole condi-tions, but presented no problem in cased hole.

The pressure derivative during buildup showsa short period of probable spherical flow fol-lowed by a period of radial flow (next page, bottom right). With initial values of ks and kh fromflow-regime identification, the buildup data werematched with a limited-entry model, assuming aformation thickness of 3 ft with no outer bound-aries. The match is excellent. The high horizontalpermeability (2390 mD) and the low vertical per-meability (6 mD) were not surprising for thiszone. Overall, a zone that looked doubtful on logsproved not only to be oil-bearing but also to haveexcellent producibility.

10 Oilfield Review

0

0

400

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eabi

lity,

mD

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1 2 3 4 5

1 2 3 4 5

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IPTT (V2)

Mini-DSTCoreIPTT (V1)

IPTT (V2)

Mini-DSTCoreIPTT (V1)

> Comparison of the horizontal (top) and vertical (bottom) permeabili-ties measured by mini-DSTs, cores and IPTTs. The core data wereaveraged over each mini-DST test interval and converted to effectivepermeability using relative-permeability curves. Arithmetic averagingwas used for horizontal permeabilities, and harmonic averaging forvertical permeabilities. The IPTT data are from the same tests as themini-DSTs, but using two probes: V1 at 2 m [6.6 ft] and V2 at 4.45 m[14.6 ft] above the packer interval. The intervals tested are thereforedifferent. In this case, the agreement between the different measure-ments is generally good.

50387schD02R1.p10.ps 11/17/01 6:02 PM Page 10

Autumn 2001 11

Mini-DST LimitationsIn spite of these good results, the permeabilitymeasurements have some limitations. The lack ofan observation probe means that the only pres-sure transient comes from the pressure sink,which is affected by skin and tool storage. Bothskin and storage influence the early part of thebuildup and make identification of flow regimesand interpretation more difficult. Later in thebuildup there needs to be the right combinationof formation properties and bed thickness for sig-nificant periods of both spherical and radial flowto be observed. The radial-flow interpretationdepends directly on identifying bed boundaries,while spherical-flow interpretation depends onknowing the storativity. Thus, it is difficult todetermine both kv and kh simultaneously.

Finally, several factors can make a singletransient hard to interpret. These include gasevolution near the wellbore, pressure and flow-rate variations due to continuous cleanup, andnoisy drawdown pressures from pump strokes.Pressure measurements at observation probesare not usually affected by these phenomena.Since these probes are higher up the string, they also increase the volume investigated.

19. Hurst SM, McCoy TF and Hows MP: “Using the CasedHole Formation Tester for Pressure Transient Analysis,”paper SPE 63078, presented at the SPE Annual TechnicalConference and Exhibition, Dallas, Texas, USA, October1-4, 2000.

Gamma Ray Resistivity Porosityohm-mAPI0 150

SP-100 0mV

1 1000 45 0p.u.

Dept

h, ft

X00

X10

X20

X30

X40

X50

X60

Perforations

> Gamma ray, resistivity and porosity logs acrossa low-resistivity reservoir in the Peng Lai field,offshore China. The mini-DST was performed in athin 3-ft zone that is isolated above and below bythin shale beds (gray) within a larger reservoir.Any oil found in this zone was expected to beabout 13º API with high viscosity.

Initial buildup

Pres

sure

, psi

a

1700

1600

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

300-rpm constant pump rate

Time, hr

Oilbreakthrough

SamplingBuildup

0

300

600

1800

Pum

p ra

te, r

pm

> Pressure and pump rate during the cased-hole mini-DST from PengLai field. After communication was established with the formation,the pump withdrew invasion fluids until oil broke through. Once theoil fraction had stabilized (as measured by the OFA Optical Fluid Analyzer tool, not shown), two samples were taken. After one additionaldrawdown, a 2-hr buildup was recorded. Minimum drawdown pressurewas 164 psi [1130 kPa], at or above the expected bubblepoint pressure,thereby avoiding free gas. The solid pressure line is the result predictedby the limited-entry model.

Pressuredifference

Radialflow

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Pressurederivative

Pres

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diff

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ce, p

sia,

and

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0.0001Time since end of drawdown, hr

0.001 0.01 0.1 1 10

Model parameters:kh = 2390 mDkv = 6 mDµ = 300 cpThickness of zone = 3 ftSkin = + 5.5Depth of investigation = 80 ft

> Pressure difference and derivative for the buildup at the end of thePeng Lai test. Spherical flow is identified by the slope of –0.5 on thederivative and radial flow by the slope of zero. The solid lines are thepredictions of a limited-entry model using the parameters in the table.

50387schD02R1.p11.ps 11/17/01 6:02 PM Page 11

IPTTs have proved to be an effective means fordetermining permeability distribution near thewellbore; in fact, they are the preferred methodfor layered systems. Mini-DSTs are usually runwhen the main objective is to recover a fluidsample, or to measure reservoir pressure, partic-ularly in tight or heterogeneous formations.Permeability is an additional parameter withwhich to judge the producibility of the interval.

Interval Pressure-Transient TestAn IPTT run in a carbonate reservoir in the UnitedArab Emirates (UAE) illustrates the sequence ofoperations and methods employed in a full anal-ysis.20 This reservoir has distinct, contrasting lay-ers that appear to extend over large areas.Reservoir management and the design of sec-ondary-recovery schemes depend strongly onknowing the vertical and horizontal permeabili-ties and the communication between layers. Inparticular, the implementation of an injectionscheme depends on the permeability of severallow-porosity, stylolitic intervals. Will the stylo-lites act as baffles to injected fluid and severelyaffect sweep efficiency?

The stylolitic intervals may be thinner than1 ft, but can be observed on logs and cores (left).However, their effectiveness as barriers is notclear. They can be correlated between wells, buttheir lateral continuity and permeability areuncertain. Cores could not be recovered from

12 Oilfield Review

0

Porosity, p.u.05 10 15 20 25 30 35

X180

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UAE Carbonate Permeability

kh (Core)mD

kh (Layered Model)

kv (Layered Model)

0.1 1000

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mD

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< Log porosity in a layered carbonate (left). Thelow-porosity streaks are stylolites. The positionsof the packer and the probes at each test loca-tion were chosen to straddle the stylolites. Theright track shows the layered model used tointerpret the IPTTs, with kv and kh from the modeland kh from core. Core permeability is generallytoo high and is either absent from the stylolites or fails to reflect the large contrasts seen by theIPTT. The FMI image (left) shows two low-poros-ity streaks (white) separated by a dark interval.The top streak is particularly patchy. The layeredmodel used to match the IPTT showed that thetop streak had higher kv than kh, while the centerinterval had very high permeability.

20. Kuchuk FJ, Halford F, Hafez H and Zeybek M: "The Use ofVertical Interference Testing to Improve ReservoirCharacterization," paper ADIPEC 0903, presented at the9th Abu Dhabi International Petroleum Conference andExhibition, Abu Dhabi, UAE, October 15-18, 2000.

50387schD02R1.p12.ps 11/17/01 6:25 PM Page 12

Autumn 2001 13

many of these intervals, and, in any case, give avery local value of the permeability. The operatordecided to investigate the stylolites with a seriesof IPTTs in a new well. These could be recordedon a single trip in the hole, allowing the completereservoir section to be tested efficiently.

An IPTT needs a minimum of one verticalobservation probe and a sink, either a dual-probeor a dual-packer module. In this case, in order tosample more layers, the MDT tool was equippedwith two vertical observation probes at 6.4 ft and14.4 ft [1.95 and 4.4 m] above the center of the

packer interval. The dual-packer module waschosen so as to generate a sufficiently largepressure change at the far probe. The pumpoutmodule was used to withdraw formation fluidsfrom each tested interval. Pressures were mea-sured by quartz-crystal and strain gauges at bothprobes and packer.

Sequence of operations—Using openholelogs, the operator selected six test locations,with the depths chosen so that the stylolites laybetween the dual packer and near probe. At eachtest location, the operator followed the samesequence of events: set the packers and probes,

pretest probes and packer interval, drawdown,buildup, and retract packers and probes (above).The pretests measured formation pressure andestablished communication with the formation.Once communication was established, formationfluids were withdrawn through the packer inter-val at an almost constant rate for between 30and 60 minutes. The rate was slightly differentfor each test, but remained between 15 and 21B/D [2.4 and 3.3 m3/d]. After each drawdown, theinterval was shut in for another 30 to 60 minutes.

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er p

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3890

3900

3910

Prob

e pr

essu

re, p

si

4000

4200

3920

3930

Packer

Probe 1

Probe 2

> The sequence of events in a typical IPTT, as shown by the pressureand the flow rate recorded in the dual-packer interval (top). After toolsetting, the pretest establishes communication with the reservoir bywithdrawing up to 1000 cm3 [60 in.3] through the packer and 20 cm3

[1.2 in.3] through each probe. During drawdown, the flow rate is con-stant since it is controlled by the pumpout module. During the buildupperiod, the pressure is recorded for a sufficiently long time, approxi-mately the same as the drawdown period, to ensure good pressure-transient data. At the end of the buildup period, the probes and packerare retracted. Packer and probe pressures were recorded with CQGCrystal Quartz Gauge pressure gauges during the IPTT (bottom). Notethe much more sensitive scale for the probe pressures. Their finalbuildup pressure is lower because they are higher in the well. Notealso the distinct delay in the start of the buildup on Probe 2, due to thelow vertical permeability. The delay on Probe 1 cannot be seen at thistime scale. The packer pressure is slightly noisy due to pump movement.

50387schD02R1 12/21/2001 02:57 PM Page 13

In this test, packer pressure dropped sharplyby approximately 300 psi [2070 kPa], while near-probe pressure dropped more slowly by 10 psi [69 kPa] and far probe by 2 psi [14 kPa]. Theseresponses give a first idea of permeability. Thefact that there is a response at the verticalprobes showed that there was communicationacross the stylolite.

Analysis—Interpretation starts with a look ateach test independently. As with mini-DSTs, thefirst step is to analyze flow regimes. Buildups arepreferred to drawdowns because they are less

affected by near-wellbore factors, such ascleanup and pressure fluctuations caused by thepumpout piston. The interpreter examined eachof the three pressure transients from the sixtests, and established some initial estimates ofpermeability. Because of the highly stratifiednature of this carbonate formation, these esti-mates were rough averages of the permeabilitynear each station.

The heart of the interpretation is a realisticmodel, layered in this case, with permeabilities,porosities and thicknesses for 31 layers (above).Initial layer boundaries and thicknesses aredetermined from the logs, actually from high-res-

olution images since layers as thin as 0.5 ft [15 cm] may play an important role. Porosity androck-framework compressibility are based on logdata; fluid compressibility and viscosity comefrom fluid saturations and PVT analysis. Initialhorizontal and vertical permeabilities are takenfrom the flow-regime analyses and other avail-able sources—cores, logs and pretests. Initialestimates are also needed for tool storage andskin around the packer.21 Finally, the flow rateduring drawdown is an important input; in thiscase, it was measured and was taken to beessentially constant during most tests.

14 Oilfield Review

mDmDmDftNumberConfidence CommentsPorosity

kvkhCore khThicknessLayer

low0.2165989771

moderate dense zone0.150.0210.1_22

high high permeability0.27610610_63

moderate0.2635687874

low0.28162633105

low0.2848676186

low0.1839534627

low0.152832190.58

moderate patchy stylolite0.1411.10.9_0.59

high superpermeability0.277251350_410

moderate0.283175811211

low0.26142430812

low patchy stylolite0.233.89.92.7214

high0.295.415.616515

high0.312.911.318716

high dense zone0.111.31.49.3217

high0.292.36.713718

high0.283.569.4619

high0.37.87.412.3820

high0.253.53.312.1321

high dense zone0.191.11.3_222

high0.23.23.2_823

high0.286.47.98.6424

high patchy stylolite0.23.819.819.1125

high0.282.35.416626

high0.294.611.410527

high0.283.16.811728

high dense zone0.190.890.1_129

high0.2814.211.32230

high dense zone0.10.450.91.41431

26 low0.26468-60913

31-Layer Model

> Model with 31 layers used for interpreting pressure transients. Each layer is assigned a thickness,vertical and horizontal permeability, porosity, and level of confidence.

50387schD02R1.p14.ps 11/17/01 6:02 PM Page 14

Autumn 2001 15

With these initial estimates, the expectedpressure transients at the packer and the twoprobes are computed and compared with themeasured transients during drawdown andbuildup (above). An automatic optimization proce-dure adjusts the model parameters to minimizethe differences over all transients. The main goalis to obtain the best kv and kh for the layers nearthe station. Bed boundaries are changed manu-ally if necessary, while, in this case, øCt was

known well enough to be fixed. Permeabilities oflayers away from the station may affect results tosome extent but are not allowed to change signif-icantly. Flow rate is held closely to the measuredrate, but is still computed so as to allow for toolstorage and the effect of small flow-rate changeson the transients.

When the results are not satisfactory, the geo-logical model is reexamined with the geologist,redefining some layers and changing some initialestimates. Different weights can be applied to

different time periods and different transients. Forexample, the packer drawdown period mightreceive less weight because, unlike observation-probe pressures, it is affected by the noise asso-ciated with production and variable cleanup.

The interpreter applied the model to each testin turn. However, this was not the end, sincesome tests were conducted close enough to eachother that changing the parameters in the vicinityof one may have altered the results from another.

21. Since the flow rate into the probe is negligible, the skinand tool storage at the probe can be ignored.

Probe

Packer

P

Probe

Packer

t

P

t

Flow-regimeidentificationand analysis

Modeldefinition

Skin, storage constants,formation pressures,flow rates

Single-layermodel

Multilayermodel

Other data

MDT-measured data

Probe

Packer

Probe

Packer

Computetransientsfrom model

Measured data

Adjust model tominimize differencebetween computedand measured data

Probe

Packer

Probe

Packer

Probe

Packer

Computed data

khkvφCt

khkvφCt

khkvφCt

khkvφCt

Pretestanalysis

PressuretransientFlow rate

• Formation pressures• Drawdown permeabilities

Initial average• ks, if spherical flow• kh, if radial flow• kv,kh, if both

log∆t

∆P,∆P’

∆P,∆P’

log∆t

Fluid analysis: µ,Cf

Openholelogs: φ,Sw,Cr

Openhole logs,images: layers

> A typical workflow for the interpretation of an IPTT, with dual packer and one vertical probe. Each job is different, and the actual path taken depends on a trade-off between speed, complexity of problem and accuracy of results. Quickest, but least accurate results come from analyzing individual transients.Next may be analysis of all transients from one test with a single-layer model, then with a multilayer model. Adjusting the model to best match all the available data may require several iterations.

50387schD02R1.p15.ps 11/17/01 6:25 PM Page 15

Therefore, the optimized model was reapplied toeach test so as to achieve a good match betweenall measured and computed transients (left).Some layers were better defined than othersbecause there were more pressure transients intheir vicinity. For this reason, the confidence fac-tor for the bottom 15 layers, for which there werefour tests, was higher than for the top 15, inwhich there were only two tests.

Results—Overall, the interpreter performed atype of history matching in which the reservoirmodel was iteratively adjusted to match 18 pres-sure transients distributed along the wellbore.The estimated permeabilities differed consider-ably from core permeability, being generallylower and varying by several orders of magnitude,from almost 0.02 mD to 1350 mD. No core-derivedpermeability measurements were available fromintervals having these extreme values. On theother hand, the porosity varied little, exceptwithin stylolitic zones. As for most carbonate for-mations throughout the Middle East, porosity isnot a good indicator of permeability. Of the sixlow-porosity intervals on the logs, only two hadpermeabilities below 1 mD. Two others werepatchy with significant permeability, one with kv > kh at X151 ft. In this particular test, the smallpressure response at the probes (less than 0.5 psi[3.5 kPa]) could be explained only by a superper-meability layer between packer and probe. Thissurprising result was supported by an FMI imageof the stylolite, which showed a conductive layerbetween two dense streaks, one of which hadgaps in it (figure, page 12). None of this wasapparent from the core data.

16 Oilfield Review

Time, sec0 500 1000 1500 2000 2500

Time, sec0 500 1000 1500 2000 2500

Time, sec0 500 1000 1500 2000 2500

400

350

300

250

200

150

100

50

0

Pres

sure

diff

eren

ce, p

si

4

0

Pres

sure

diff

eren

ce, p

si

12

10

8

6

4

2

0

Pres

sure

diff

eren

ce, p

si

1

2

3

Probe 2

Probe 1

Packer

ComputedMeasured

ComputedMeasured

ComputedMeasured

Probe 2 (for reference)

> A comparison between the measured pressure-transient responseat the packer (bottom) and the two probes (top and middle), and theresponse computed from the layered model after nonlinear optimiza-tion of the parameters. The good agreement validates the parametersin the model. Other solutions may be possible, but were ruled out onthe basis of other data.

50387schD02R1.p16.ps 11/17/01 6:03 PM Page 16

Autumn 2001 17

The final model suggested that the layersshould communicate over time. Pressure commu-nication was confirmed by the formation pressuregradient from MDT pretests (left). The relativelyuniform gradient showed that the stylolites didnot act as pressure barriers. However, good pres-sure communication does not necessarily meanthat fluids will flow uniformly through the reser-voir. As the model showed, at least two high-permeability layers can act as conduits forinjected water. This information has been used in the full-field reservoir simulator, and to examine unexpected water breakthroughs in production wells.

Mapping StylolitesCarbonate rocks typically form in shallow, tropi-cal marine environments. In some cases, a for-mation can extend for hundreds of miles.Carbonate sediments contain significantamounts of the metastable minerals aragoniteand magnesium calcite; calcite itself is readilydissolved and reprecipitated by percolating porefluids. Carbonate rocks are, therefore, likely to

undergo dissolution, mineralogical replacementand recrystallization. These effects vary accord-ing to temperature, pore-fluid chemistry andpressure. Carbonate diagenesis commonlybegins with marine cementation and boring byorganisms at the sediment-water interface priorto burial. It continues through shallow burial withcementation, dissolution and recrystallization,and then deeper burial where dissolution pro-cesses, known as pressure solution, may formsuch features as stylolites and vugs (below).

The resulting diagenetically altered zones,whether of lower or higher permeability than thesurrounding formation, are frequently extensiveand affect large sections of a potential reservoir.For this reason, such features detected by bore-hole measurements often can be extrapolatedsome distance from the well.

The first IPTT example showed how the per-meability of stylolites could be determined in asingle well. The next question is how far the lay-ers extend across the field. The depth of investi-gation of an IPTT depends on transmissivity(khh/µ) and storativity, and varies with each test.

8300

Dept

h, ft

8250

8200

8150

8100

3840 3860 3880 3900 3920Pressure, psi

0.34 psi/ft

> Pressure profile from MDT pretestsacross the reservoir. The pretests weretaken at the packer and probes as part ofeach IPTT. The reservoir has been on pro-duction for nearly 20 years. After thismuch production, any barriers to pressurecommunication should cause the pres-sure gradient to be much less uniform.However, the lack of pressure barriersdoes not necessarily mean that fluids willflow vertically with ease.

> Large dissolution cavity. Although carbonates can have large dissolution cavities, they arenot always as large as this.

50387schD02R1 11/29/01 4:43 AM Page 17

In the previous example, the depth of investiga-tion ranged from about 20 to 30 feet [6 to 9 m].The next example, from another field in the UAE,examines the lateral extent of barriers by runningIPTTs in several adjacent wells (right).22 The low-porosity, dense stylolites can be correlated easilybetween wells, but their actual density varies, soit is quite possible that their permeability alsovaries. The size and number of stylolites areobserved to increase towards the flanks andtoward one side of the field.

A total of 23 IPTTs was recorded in sevenwells in two areas in which pilot gas-injectionschemes were to be implemented. The mainobjective was to determine the vertical perme-ability of four stylolites—Y2, Y2A, Y3 and Y4.

In this case, the MDT tool was configuredwith four probes (next page, top). A sink probe Screates the transient, which is measured by ahorizontal observation probe H at the same depthbut diametrically opposite the sink, and twoobservation probes V1 and V2 vertically displacedfrom the sink by 2.3 ft and 14.3 ft, [0.7 and 4.4 m].With this configuration, the storativity, øCt, neednot be assumed in the permeability analysis,since it can be determined directly from the tran-sients. An FMI image, recorded after the tests,clearly showed the imprint left by the probeassemblies on the borehole wall. The tool can beseen straddling two stylolites. In some tests, theflow-control module was used to give a constantflow rate. In others, formation fluids were with-drawn using the pumpout module for a longertest. Thus, as in the last example, a measuredflow rate was generally available for each test.

In some tests, the sink probe could not with-draw fluids as it was set against a highly local-ized tight spot. In these cases, the operation waschanged to withdraw fluids from the V1 probe,using S and V2 as the observation probes. Morerecently, interval tests in carbonates have beenperformed with the dual packer because its pro-duction interval is several thousand times that ofa sink probe. Fluid withdrawal is then possibleeven with a high degree of heterogeneity and inrelatively low permeabilities.

18 Oilfield Review

22. Badaam H, Al-Matroushi S, Young N, Ayan C, Mihcakan Mand Kuchuk FJ: “Estimation of Formation PropertiesUsing Multiprobe Formation Tester in LayeredReservoirs,” paper SPE 49141, presented at the SPEAnnual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 27-30, 1998.

A

B

C

D

EF

G

North pattern

South pattern

XI

XII

XIIIA

XIIIB

XIV

XV

XVI

Y2

Y2A

Y3

Y4

Y5

Y1

Stylolites analyzed

> Field with two pilot gas-injection schemes planned, one in the north, andthe other in the south. The design depended heavily on the properties of thestylolites, Y1 through Y5. These zones could be easily identified on densitylogs and could also be correlated fairly easily across the reservoir. However,their properties varied, and it was not clear how effective they were as barri-ers to flow. IPTTs were recorded in seven wells (A through G) to quantify andmap their properties correctly.

A GB C D E F

Y2

Y2A

Y3

Y4

0 0 - 0.3 0.3 -1 1-3 3 -10 >10 Nottested

Permeability, mD

Styl

olite

Well

> Vertical permeability of the four main stylolitic intervals as found by 23 IPTTs run in seven wells.

50387schD02R1.p18.ps 11/17/01 6:03 PM Page 18

Autumn 2001 19

The interpretation began, as before, by flow-regime identification and analysis. Because of thelarge volume of data, each test was initially inter-preted assuming a single homogeneous butanisotropic layer. This interpretation is quickerand gives an average kh and kh/kv over some inter-val of reservoir rock containing the stylolite. Later,a more complete study was undertaken using amultilayer model as in the previous example.

The results showed considerable variationbetween the wells (previous page, bottom). In general, the stylolites were not absolute barri-ers to flow. For example, the Y2 stylolite wasfound to be a barrier in the south of the area, inWells F and G, but very conductive in Well E. TheY2A stylolite was also very conductive in Well E.FMI images showed that the stylolite and its adja-cent layers had a significant number of vugs, afeature not captured by the cores. Cores generallyfound a higher kh than did the IPTT but missed the vuggy intervals entirely (below). The IPTTquantified the degree of hydraulic communi-cation and allowed better planning of the pilot gasflood scheme.

Stylolite

Stylolite

X125

X150

X175

X200

Discontinuousstylolite

Dept

h, ft

Porouslimestone

Volume, %100 0p. u.

Unmoved Oil

Limestone

Anhydrite

Dolomite

Moved Oil

Clay

Water

V2

V1

SH

< Volumetric analysis (left) and the four-probeMDT tool (middle) set across the Y3 styloliticinterval in Well F. The FMI image (right) was runafter the tests and shows clearly the imprint (cir-cled in green) of the four probe assemblies attwo different tool locations.

MDT

laye

r per

mea

bilit

y, m

D

0.1

1

100

0 10 1001

10

Core-plug permeability, mD

Well E - Y4Well G - Y2AWell E - Y2AWell D - Y2Well E - Y2 Layers with

vugs in Well E

> Comparison of kh from core plugs with kh from thecorresponding layers of the IPTT interpretation. Thecore values were obtained by arithmetic averagingof the samples within the IPTT interval and by con-verting from absolute to effective permeability. In aperfect match, points would lie on the dotted line.Core-derived kh is generally higher. The core data donot capture effectively the vuggy layers of Well E.

50387schD02R1 11/29/01 4:43 AM Page 19

Anisotropy in SandstonesSandstones also pose questions about verticalpermeability and barriers to flow. AnadarkoAlgeria’s plans for the development of HassiBerkine South field called for injection of bothmiscible gas/water and possibly water-alternat-ing-gas (WAG) in the future (left). They needed toknow the permeability anisotropy in the field toimprove confidence in the vertical sweep effi-ciency, and in the recovery values being pre-dicted from numerical models. This informationwas required early in the appraisal-drilling pro-gram as it affected decisions on facilities andinfrastructure. The reservoir is in the TriassicArgilo-Gréseux Inferior (TAGI) sandstone.23 TheTAGI is fluvial in origin, with sands that are 5 to15 m [15 to 50 ft] thick. The area of interest hastwo major rock types: a fine- to very fine-grainedsand with interspersed shale laminae, and a fine-to medium-grained braided-stream deposit withdiscrete claystone layers (next page).

Upon reinjection, gas and water will be takenmainly by the high-permeability layers. It wasimportant to determine the degree of gravity seg-regation expected in the TAGI, and the corre-sponding influence on vertical sweep, oilrecovery and future production performance.

20 Oilfield Review

km 500

miles 300

ALGERIA

TUNISIA

LIBYA

HassiBerkineSouth

ALGERIA

> The Hassi Berkine South field in Algeria operated by Anadarko.

2200.00

2198.95

2200.00

2199.852193

2200

2200

2184

2200

2198

2200

2040

Probe Probe Probe

Packer Packer Packer

Time, sec0 500 1000

Time, sec0 500 1000

Time, sec0 500 1000

Time, sec0 500 1000

Time, sec0 500 1000

Time, sec0 500 1000

kh = 10

kh = 10

kh = 100

kh = 100

kh = 1000

kh = 1000

Pres

sure

, psi

Pres

sure

, psi

Pres

sure

, psi

Pres

sure

, psi

Pres

sure

, psi

Pres

sure

, psi

kh/kv = 100kh/kv = 10kh/kv = 1

kh/kv = 100kh/kv = 10kh/kv = 1

> The pressure response at a dual packer and a vertical probe 6.6 ft [2 m] higher during a drawdown followed by a buildupmodeled for different horizontal permeabilities and anisotropies, but the same flow rate. Note the expanding pressure scale foreach plot from low kh on the left to high kh on the right. Higher kh reduces the signal (causes a smaller pressure drop) at bothpacker and probe. Higher kh/kv reduces the signal at the probe but increases it at the packer. The response is complex andsometimes paradoxical. For example, at the end of a very long flow period, the pressure drop at the vertical probe depends onlyon kh, while the drop at the dual packer depends on both kh and anisotropy. Also, no signal at the vertical probe can mean thatthere is a layer of either zero or infinite permeability between it and the dual packer. These paradoxes partly explain why simpleanalytical solutions are not reliable.

50387schD02R1.p20.ps 11/17/01 6:03 PM Page 20

Autumn 2001 21

For the reservoir engineers simulating the gasinjection, the most critical parameter was theanisotropy, kh/kv. They were not confident in theanisotropy from cores, around 10, as this valuewas unexpectedly low for such a depositionalenvironment. The claystone layers were a partic-ular worry since they seemed to extend acrossthe field. An IPTT offered an attractive solution. Itwould test the anisotropy on a much larger scalethan cores, and would provide permeability val-ues at nearly the same vertical scale as the gridblocks used in the numerical simulation.

Four stations were planned—two in the fine-grained, lower resistivity layer; two in themedium-grained layer, one of which wasdesigned to straddle a thin claystone.

Permeabilities are high, so as part of the pretestplanning it was important to check that sufficientpressure changes would be seen at the monitorprobe. Using expected values for permeabilityand other parameters, simulations showed that ifthe flow-control and pumpout modules wereused as flow-rate sources, the resulting pressurepulse at the monitor probe would be barely mea-surable (previous page, bottom). A higher flowrate, and hence a larger pressure response, couldbe obtained by flowing directly to a samplechamber. This is clearly desirable unless it drawsgas out of solution or causes sanding. After fur-ther modeling and checking experience else-where, the operator ran tests with the dualpacker connected directly to the sample chamber.

The interpreters analyzed each test with asingle-layer model, treating the entire 15-msandstone as one layer. With no flow-rate mea-surement available, a special approach to theanalysis had to be taken. In this approach, theprobe pressure transient is used to estimate kv

and kh, while the packer transient is used to esti-mate the flow rate and packer-interval skin. Sincethe estimates are interdependent, it is necessaryto iterate between the formation parameters atthe probe and the flow rate and skin at the packeruntil the results converge.

23. Peffer J, O’Callaghan A and Pop J: “In-Situ Determinationof Permeability Anisotropy and its Vertical Distribution—A Case Study,” paper SPE 38942, presented at the SPEAnnual Technical Conference and Exhibition, SanAntonio, Texas, USA, October 5-8, 1997.

Dept

h, m

XX30

XX40

XX50

MDT

Core

1 100

1 100

Gamma Ray

Caliper

in.4 20

API0 140

Probe Pressure (Quartz)psi 51505110

Drawdown Mobility

1 3000mD/cp

AIT Resistivityohm-m1 3000

Anisotropykh/kv

Volumetric Analysis0 1vol/vol

Water

Oil

Sandstone

Bound Water

Clay

Layer 1

Layer 2

0.1 mm

0.1 mm

1 3000

Horizontal Mobilityfrom IPTT, mD/cp

> The two layers of the15-m TAGI sandstone. Layer 1 is fine-grained with shale laminations; Layer 2 is a medium-grained massive sandstone withthin claystone beds. The two IPTTs in Layer 1 both give horizontal mobilities below 100 mD/cp and moderate anisotropy. In Layer 2, both tests showhigh horizontal mobility, but the top test has low anisotropy, while the bottom test has high anisotropy, most likely due to the thin clay (green highlightin Track 4) at XX40.2 m between packer and probe. The average core anisotropy is similar, but slightly higher.

50387schD02R1 11/29/01 4:43 AM Page 21

The resulting permeabilities reflected the aver-age properties of the formation near each station.The results near the top two stations were similar,with horizontal mobility (permeability/viscosity)near 50 mD/cp and anisotropy near 10. The bot-tom two stations lay in the medium-grained layer.They both showed high horizontal mobility, butwhile the third station was nearly isotropic, thefourth station showed a much higher kh/kv.Assuming that the third station defines the prop-erties of the clean sandstone, it seems likely thatthe fourth station is affected by the thin clay atXX40.2 m, which lies between probe and packer.Assuming also that the clay acts as an imperme-able disk lying around the wellbore, we can esti-mate its radius as 2 m [6.6 ft].24 By this estimate, itis quite limited in extent.

The entire TAGI interval in this well wascored, with horizontal permeability measure-ments made on plugs every 15 to 30 cm [6 to12 in.], and vertical permeabilities about everymeter. When the core permeabilities were aver-aged over the 2-m interval of each MDT station,they compared well with MDT results, both indi-cating anisotropy less than 100.25 When shalelaminae or claystone beds are absent, theanisotropy is less than 10. These results were

further supported by five whole-core samplesfrom other wells in the field.

The MDT data were analyzed further with atwo-layer model, the only multilayer model avail-able at the time. The results were similar. Ideally,a model with at least five layers is needed to sim-ulate the whole formation. However, in this caseof relatively homogeneous formations, the opera-tor obtained answers that were sufficiently fit forthe purpose with the simpler single-layer model.

The MDT results increased confidence in theanisotropy values that reservoir engineers wereusing for numerical modeling, and thus also inthe predicted performance of the planned injec-tion scheme. In fact, the MDT-measured valueswere used directly in the simulator. The field hasbeen on production since early 1998, producingin excess of 70,000,000 barrels [11,123,000 m3].The MDT-derived anisotropy values continue tobe used in the simulator, since the history matchbetween actual field performance and predic-tions from the simulator have been excellent.Although in this case the core anisotropy dataproved to be broadly correct, the confirmation ona much larger scale was a key piece of informa-tion gathered during the appraisal of the field.

Horizontal WellsOperators rarely acquire permeability data in hor-izontal wells for reservoir description. However,horizontal wells often fail to live up to expecta-tion. Some of the many causes are related toreservoir heterogeneities. In one horizontal well,6 IPTTs and 19 pretests were run to investigatewhy neighboring wells had performed below par(above).26 Two major features were observed thatcould cause poor production—the variation inreservoir pressure, dropping by as much as100 psi [689 kPa] in the middle of the well; andthe variation in permeability from 5 to 50 mD forfairly constant porosity. Clearly, the middle inter-val has been more depleted and received lesssupport from water injection into the reservoir.Upon completion, the middle interval is predictedto clean up less easily, while injection water willprobably break through first at the toe, or end, ofthe well. For these reasons, it was recommendedto complete the well with a casing.

IPTTs are particularly useful for evaluating theconductivity of faults and fractures in horizontalwells. Interpreting conventional well tests is dif-ficult due to strong crossflow from pressure andpermeability variations. Borehole images candetermine the location of faults and fractures,

22 Oilfield Review

Horizontal displacement, ft0 2000 4000 6000 7000

6800

TVD,

ft

6900

Rese

rvoi

r pre

ssur

e, p

si

4200

4150

4100

4050

4000

6820

6840

6860

6880Pe

rmea

bilit

y, m

D

10

1

1000 3000 5000

0.4

Poro

sity

0.3

0.2

0.1

0

Frac

ture

test

Well trajectoryPorosityPretest (khkv)1/2

Interval test (khkv)1/2

Pressure

> Reservoir pressure and permeability from the MDT tool in a horizon-tal well. Permeability is measured by both pretest drawdowns andinterval pressure-transient tests, the latter being generally an order of magnitude higher. The pretest permeability may be low due to for-mation damage or because it is measuring the effective permeabilityto filtrate in a water-wet reservoir. Porosity is from openhole logs.Between 1765 and 5266 ft horizontal displacement, the pressure is significantly lower than elsewhere, indicating higher depletion andpoorer pressure support from water injection in the reservoir.

50387schD02R1.p22.ps 11/17/01 6:03 PM Page 22

Autumn 2001 23

and whether or not they are mineralized. In thiswell in a carbonate reservoir, images showedmany vertical fractures but could not determinetheir hydraulic conductivities. Pressure differ-ences indicated that while some were closed,others may have been open. Open fractures couldharm production by quickly drawing water upinto the well.

To test the fractures, the MDT tool was setwith a dual-packer module straddling a set offractures seen at 2983 ft (below). The logarithmicderivative with respect to Horner time for thebuildup test at the packer location indicates atool storage-dominated period that ends with ashort slope of –1.0 at 0.015 hr. Following thestorage period, the derivative exhibits a –0.5slope spherical-flow regime until 0.15 hr, afterwhich the derivative goes downward, indicatinga higher permeability region. The probe buildupderivative also exhibits a short spherical-flowregime, though its value is lower than that of thepacker test. The fact that the probe derivative islower but ends at the same time at both packer

and probe indicates a conductive fracture to theleft of the probe. The fracture or fractures musteither be short or have a finite conductivitybecause the derivative decreases only gradually.In addition, the best match to the transients wasachieved with a positive skin—another indica-tion that the fractures opposite the packer werenot open.

All the major fracture intervals were analyzedin this manner. The combination of fracture analy-sis, permeability and pressure data is of great usenot just for predicting the performance of a partic-ular well, but also for analyzing how the reservoiris responding to water injection and decidingwhether to drill horizontal or vertical wells.

ConclusionOperators are expanding their use of modernwireline formation testers to determine perme-ability and help make important well-completionand reservoir-management decisions. Comparedwith conventional cores and well tests, thesetesters provide cost-effective information at a

scale intermediate between the two. This infor-mation is critical for evaluating the effect ofreservoir heterogeneities, baffles and conduits.

Wireline formation testers measure perme-ability in different ways, depending on the hard-ware configuration. The mini-DST is particularlyuseful for evaluating small intervals at a fractionof the cost of a full well test. The interval pres-sure-transient test provides the most reliable andextensive permeability information from thesetools. With recent developments in software andinterpretation techniques, interval tests can nowevaluate highly layered formations, horizontalwells, and even gas reservoirs.27 The latter haveoften been considered too challenging becauseof the high compressibility and mobility of thefluid. In addition, the risk of sticking the tool—the fear of many operators—has been reducedthrough the use of risk-assessment software.28

Currently, engineers are seeking to improveresults in formations with high mobilities, heavyoil or unconcolidated sands—all difficult but notimpossible cases. Work continues on the peren-nial problem of scaling up from cores to tests,and of integrating interval-test results with otherdata. Attempts are being made to measure in situthe variation of effective permeability with watersaturation, using the fluid fractions measuredwhile sampling in combination with openholelogs and interval-test data. As long as reservoirscontinue to be heterogeneous and permeabilitydistribution remains an issue—both virtual cer-tainties—wireline formation testers will beneeded to evaluate them, and improvements willcontinue to be made. —JS/LS

24. Goode PA, Pop JJ and Murphy WF III: “Multiple-ProbeFormation Testing and Vertical Reservoir Continuity,”paper SPE 22738, presented at the SPE Annual TechnicalConference and Exhibition, Dallas, Texas, USA, October6-9, 1991.

25. A thickness-weighted arithmetic average was used forthe horizontal permeability, and a thickness-weightedharmonic average for the vertical permeability.

26. Kuchuk FJ: “Interval Pressure Transient Testing withMDT Packer-Probe Module in Horizontal Wells,” paperSPE 39523, presented at the SPE India Oil and GasConference and Exhibition, New Delhi, India, February17-19, 1998.

27. Ayan C, Donovan M and Pitts AS: “Permeability andAnisotropy Determination in a Retrograde Gas Field toAssess Horizontal Well Performance,” paper SPE 71811,presented at the Offshore Europe Conference,Aberdeen, Scotland, September 4-7, 2001.

28. Underhill WB, Moore L and Meeten GH: “Model-BasedSticking Risk Assessment for Wireline Formation TestingTools in the U.S. Gulf Coast,” paper SPE 48963, presentedat the SPE Annual Technical Conference and Exhibition,New Orleans, Louisiana, USA, September 27-30, 1998.

Packer

Probe

Pres

sure

der

ivat

ive

0.1

1

10

100

0.001 0.01 0.1 1Time since end of drawdown, hr

ProbeDual-packer

module

Slope = 1

Slope = 1/2 Slope = 1/2

> Pressure derivatives from probe and packer transients (bottom) for the analysis of fractures in a horizontal well. Theengineer set the dual-packer (top) astride a set of fracturesthat had been interpreted on FMI images (at 2983 ft, see figureprevious page), and performed an IPTT. The probe derivativeis less than the packer derivative, but spherical flow ends atthe same time on both transients. These observations alongwith the positive skin are best explained if the fracturesbetween the packers are not hydraulically conductive, and if there is a conductive fracture to the left of the probe.

50387schD02R1.p23.ps 11/17/01 6:26 PM Page 23

24 Oilfield Review

Quantifying Contamination Using Color ofCrude and Condensate

R. John AndrewsHibernia Management and Development Company Ltd.St. John’s, Newfoundland, Canada

Gary BeckBPHouston, Texas, USA

Kees CastelijnsLondon, England

Andy ChenCalgary, Alberta, Canada

Myrt E. CribbsChevronTexacoBellaire, Texas

Finn H. FadnesJamie Irvine-FortescueStephen WilliamsNorsk Hydro, ASABergen, Norway

Mohamed HashemShellNew Orleans, Louisiana, USA

Establishing the level of oil-base and synthetic mud-filtrate contamination in fluid

samples is critical for obtaining meaningful data on fluid properties. New tools and

techniques now allow real-time, quantitative measurement of contamination in gas-

condensate and oil reservoirs.

In deepwater areas, an oil or gas company mayspend tens of millions of dollars drilling a well toprove the presence of hydrocarbons, and thenplug and abandon the well almost immediately.The operator may take years designing and build-ing facilities before drilling another well in thefield. Exploration wells provide a narrow windowof opportunity for collecting hydrocarbon sam-ples to make development decisions; therefore,obtaining high-quality samples is imperativewhether the prospect is in deep water or on thecontinental shelf, in China, Canada, the Caspian,or elsewhere.

Testing well production is a good way toobtain fluid samples, but that is not always fea-sible for economic or environmental reasons.Downhole samples define fluid properties thatare used throughout field development.Estimates of hydrocarbon volume, bubblepointpressure and gas/oil ratio (GOR), simulation ofreservoir flow and placement of wells all dependon formation-fluid properties. Hydrate, asphal-tene and wax formation must be controlled ortreated. Presence of corrosive gases affects thechoice of materials for flowlines and surfacefacilities. These examples illustrate the wideimpact that hydrocarbon composition and behav-ior have on planning a new field.1

A. (Jamal) JamaluddinHouston, Texas

Andrew KurkjianBill SassSugar Land, Texas

Oliver C. MullinsRidgefield, Connecticut, USA

Erik RylanderBelle Chase, Louisiana

Alexandra Van DusenHarvard UniversityCambridge, Massachusetts, USA

For help in preparation of this article, thanks to VictorBolze, Reinhart Ciglenec, Hani Elshahawi, Troy Fields, GusMelbourne, Julian Pop and Rod Siebert, Sugar Land, Texas;Peter Kelley, ChevronTexaco, Houston, Texas; and ToruTerabayashi, Fuchinobe, Japan.AIT (Array Induction Imager Tool), CHDT (Cased HoleDynamics Tester), CMR (Combinable Magnetic Resonance),FFA (Field Fingerprint Analyser), LFA (Live Fluid Analyzer),MDT (Modular Formation Dynamics Tester), OCM (Oil-BaseContamination Monitor), OFA (Optical Fluid Analyzer),Platform Express and TLC (Tough Logging Conditions) aremarks of Schlumberger. RCI (Reservoir CharacterizationInstrument) is a mark of Baker Atlas. RDT (ReservoirDescription Tool) is a mark of Halliburton.1. Joshi NB, Mullins OC, Jamaluddin A, Creek J and

McFadden J: “Asphaltene Precipitation from Live CrudeOil,” Energy and Fuels 15, no. 4 (2001): 979-986.

50387schD03R1.p24.ps 11/17/01 8:30 PM Page 24

Autumn 2001 25

Openhole-wireline or drillstring-conveyed for-mation testers analyze selected fluid propertiesdownhole and acquire small volumes of reservoirfluid for later testing in a laboratory. However,mud filtrate invades the formation during drilling,so these fluid samples usually are contaminated.

During the past few years, real-time methodshave been developed as part of the openhole-logging suite of services to analyze sample contamination. These methods ensure that repre-sentative fluid samples are collected and minimize tool-sticking risks by introducing effi-ciencies in sample collection. Until recently,these sampling methods were unreliable in holesdrilled with oil-base and synthetic muds or in for-mations with high GOR.

This article reviews the requirements andchallenges in sampling reservoirs and reports onadvances in evaluating sample contamination.Except where explicitly stated to be contamina-tion from water-base mud, this article discussesoil-base or synthetic-base mud-filtrate contami-nation. We describe a technique for determining

the time required to collect an acceptable fluidsample at a given sampling station and showhow proven sample-contamination measure-ments can be extended to high-GOR fluids andcondensates. Quantitative contamination mea-surement is illustrated with case histories fromoffshore Newfoundland, Canada, the Gulf ofMexico and the Norwegian North Sea.

Obtaining Downhole Fluid SamplesFormation fluid samples provide important datato optimize operator investment in both upstreamand downstream facilities. Laboratory measure-ments establish standard fluid properties such aspressure-volume-temperature (PVT) behavior, vis-cosity, composition and GOR. In fields destinedfor subsea development, flow assurance is amajor concern, so tests are performed to evalu-ate gas and solids content. Hydrogen sulfide[H2S] and carbon dioxide [CO2] in oil require spe-cial handling and materials. Temperature andpressure changes in pipelines can lead to asphal-tene and wax precipitation and deposition, andlow seafloor temperatures can induce hydrate

Pumpout module

Sample-chambermodules

Multisamplemodules

LFA Live FluidAnalyzer module

Hydraulic-powermodule

Single-probe module

> The MDT Modular Formation Dynamics Testertool configured for fluid-sample collection.

50387schD03R1 11/29/01 3:28 AM Page 25

formation. Commingling different crude oilsthrough satellite tiebacks can dramatically alterfluid properties (above).

The data-acquisition process must includefluid characterization to get the most out of everyprospect. Taking fluid samples early in the life ofa well ensures that fluid composition and proper-ties are available for timely input to field plan-ning decisions. If fluid properties will affectfacilities or transport, accurate fluid analysisgives an operator the opportunity to mitigate oreliminate problems through changes in produc-tion design, or to manage them through ongoingtreatments such as heating pipelines—a choicebetween upfront capital expenditures and on-going operating expenses.

In some fields, fluid samples can be obtainedduring a drillstem test (DST) or, after a well isflowing, a production test. In some cases, a wellmust be completed before a flow test, which can cost tens of millions of dollars in deep-water Gulf of Mexico wells. In areas such as theGrand Banks, offshore Newfoundland, Canada,operators want to minimize operation times toavoid risks such as harsh seas and iceberg haz-ards. Environmental concerns restricting flaringand removing fluids from the rig also restrict use

of DSTs and production tests. The cost and risk ofDSTs lead operators to use wireline tools forfluid-sample acquisition.

A major problem in downhole fluid-samplecollection is contamination from drilling-mud fil-trate entering a tool with reservoir fluids.Contamination from water-base mud (WBM) canbe discriminated easily from reservoir oil. Inmany of today’s high-risk wells, oil-base muds(OBMs) and synthetic oil-base muds (SBMs) areused to ensure compatibility with shales,improve wellbore stability and increase drillingspeed. OBM and SBM filtrates mix with reservoircrude, making quantification of contaminationmuch more difficult than when using WBM. Fluidproperties are often extrapolated to an uncon-taminated condition by mathematically removingthe contaminant from the distribution of con-stituents. However, extrapolation from high lev-els of contamination is risky—most companiesavoid liquid-phase contamination greater than10% on a volume-to-volume basis.

Several commercially available tools havefluid-sampling capabilities, including theSchlumberger MDT Modular Formation DynamicsTester tool, the Baker Atlas RCI ReservoirCharacterization Instrument tool, and theHalliburton RDT Reservoir Description Tool

sonde. Most wireline formation testers press aprobe against the borehole wall at a specifieddepth, pump down the formation and draw influid for evaluation, and then collect sampleswhen desired fluid characteristics are reached.2

With a probe securely pressed against theborehole wall, a short, rapid pressure dropbreaks the mudcake seal. Normally, the first fluiddrawn into the tool will be highly contaminatedwith mud filtrate (next page, top). As the toolcontinues to withdraw fluid from the formation,the area near the probe cleans up, and reservoirfluid becomes the dominant constituent. The timerequired for cleanup depends on many parame-ters, including formation permeability, fluid vis-cosity, the pressure difference between boreholeand formation, and the duration of the pressuredifference during and after drilling. Increasingpump rate can shorten the cleanup time, but therate must be controlled carefully to preserve thereservoir-fluid condition. Because many factorsaffecting cleanup time have unknown values,determining the contamination level during a log-ging job is crucial to obtaining good samples.

The versatile Schlumberger MDT system per-forms a variety of functions, depending on whichmodules are joined together. The tool’s primarypurposes are to obtain formation-fluid samples,to measure formation pressures at given pointsin the reservoir and to estimate permeability insitu. For a description of use of the tool for per-meability measurement and description of othertool modules, see “Characterizing Permeabilitywith Formation Testers,” page 2.

The OFA Optical Fluid Analyzer system in theMDT tool has provided a qualitative measure ofcontamination since its introduction in 1993.Schlumberger has developed the OCM Oil-BaseContamination Monitor technique to predict thetime needed to achieve an acceptably low levelof contamination at a given sampling station.This reliable new technique monitors samplecontamination quantitatively, adding confidenceto these crucial contamination measurements.

26 Oilfield Review

Subsea wellhead

Buildup of solidsin the wellbore

Asphaltene deposition inthe near-wellbore region

Solids in subsea flowlines

Precipitated solidsin the separator

> Transport hazards from reservoir-fluid constituents while flowing to surface.Asphaltenes, waxes and hydrates can form during fluid transport to surface.Depositing such solids clogs tubulars or blocks pores in the formation. Solidsalso precipitate in separators under certain conditions. In addition, commin-gling fluids at wellheads can generate unstable conditions leading to precipi-tation of solids.

> Components of MDT optical analysis modules.

Color channelsGas refractometerWater channelsOil channel

Contaminationmeasurement

Color channelsMethane channelGas refractometerWater channelsOil channel

Methane flagGas flagWater flagOil flag

Gas flagWater flagOil flag

OFA module

OCM module

LFA module

50387schD03R1.p26.ps 11/17/01 8:30 PM Page 26

Autumn 2001 27

The new LFA Live Fluid Analyzer module addsa methane detector that provides a more defini-tive measure of gas content in the oil phase andallows calculation of GOR. This module can beused to ensure that the fluid remains in singlephase during sampling; dropping pressure belowthe bubblepoint would make the fluid unrepre-sentative. The quantitative OCM contaminationmeasurement can be used with either an LFA orOFA module (previous page, right).

Modular reservoir sample chambers (MRSCs)are available to collect large samples (below).Multiple 6-gallon [22,712-cm3] chambers can berun at the bottom of the tool string to act as dumpchambers. Samples for PVT analysis are morecommonly collected in smaller chambers. A mul-tisample module (MRMS) allows collection of sixeasily removable sample bottles (MPSR) that arecertified for transport by the US Department ofTransportation (DOT) and by Transport Canada.The 450-cm3 [0.12-gal] MPSR bottle is reduced to 418 cm3 [0.11 gal] when an agitator is addedto improve fluid mixing in the laboratory. TheSchlumberger Oilphase single-phase multi-sample chamber (SPMC) can be used in theMRMS when keeping a reservoir fluid sample in

2. For more on use of the MDT tool for downhole fluid sam-ple analysis: Crombie A, Halford F, Hashem M, McNeil R,Thomas EC, Melbourne G and Mullins OC: “Innovations in Wireline Fluid Sampling,” Oilfield Review 10, no. 3(Autumn 1998): 26-41.Badry R, Fincher D, Mullins O, Schroeder B and Smits T:“Downhole Optical Analysis of Formation Fluids,” OilfieldReview 6, no. 1 (January 1994): 21-28.

Oil cone

Filtrate Oil cone

t1

Oil

OD

Timet1 t2 t3

t2

t3

Filtr

ate

Filtr

ate

> Drawing in filtrate. The MDT probe pressed against a borehole wall is the source of a pressuredrawdown, pulling fluids into the tool. Filtrate near the probe enters first, but as the pressure sinkexpands, a higher proportion of fluid is reservoir fluid. The optical density (OD) increases as darkercrude oil replaces the more transparent mud filtrate.

MRSC

H2S

Maximum hydrostaticpressure

Volume

Sample pressure

Transportable

Downhole temperature

Surface heatingallowed

Pressurecompensated

20- and 25-kpsi [138-and 172-MPa] options

1- and 2.75-gal [3785-and 10,410-cm3] options

20 kpsi

No

204°C [400°F]

77°C [170°F]

No

14 kpsi [97 MPa]

1- and 2.75-galoptions

14 kpsi

No

204°C

54°C [130°F]

No

10 kpsi [69 MPa]

6 gal [22,712 cm3]

10 kpsi

No

204°C

Not allowed

No

20- and 25-kpsioptions

450 cm3 [0.12 gal]

20 kpsi

Yes

204°C

100°C [212°F]

No

20- and 25-kpsioptions

250 cm3

[0.07 gal]

20 kpsi

No

204°C

204°C

Yes

Non-H2S MPSR SPMC

MRMS

The 25-kpsi limit is for special high-pressure modules, and the sampling must be done in low-shock mode—the bottle is compensated to hydrostatic pressure behind the piston.Only Schlumberger Oilphase is allowed to heat chambers above 54°C [130°F].Six-gallon bottles must be run on the bottom of the string. Several bottles can be combined in one string.Addition of an agitator reduces this volume to 418 cm3 [0.11 gal].Transportable indicates US Department of Transportation Exemption and Transport Canada Permit for Equivalent Safety.Compressed nitrogen is used to compensate the sample pressure so it does not decrease as much upon cooling when brought to surface.

3

5

6

1

2

1 1

4

1

2 3 4 5 6

> Sample bottles available for the MDT tool.

50387schD03R1.p27.ps 11/17/01 8:30 PM Page 27

single phase from the downhole collection pointto the PVT laboratory is necessary. After the MDTpumpout module fills a SPMC chamber at forma-tion pressure, a preset nitrogen charge isreleased. Acting through a piston floating on asynthetic oil buffer, the nitrogen adds sufficientoverpressure to keep the fluid in single phaseduring retrieval to surface.

Black Oil Isn’t Always BlackOils have color—black, brown, red, tan and evengreen crude oils have been seen. The hue andintensity of light transmitted or reflected fromcrude oil or gas condensate depend on the light’sinteraction with molecules and molecular bonds inthe fluid. Measurements of this interaction can beused to distinguish oils of different compositions.

The unit of light absorption or optical density(OD) is the logarithm of the ratio of incident-lightto transmitted-light intensity. Therefore, darkerfluids have higher OD, and a one-unit increase inOD represents a factor of ten decrease in trans-mittance. An OD of zero indicates all light istransmitted, while an OD of two represents 1%transmission. A fluid’s OD varies with the wave-length of incident light.

Reduction of transmitted-light intensity can becaused by one of two physical processes. Somelight is scattered by particles in the fluid; scatter-ing outside the optical path to the detectordecreases intensity. Light also can be absorbed bymolecules in the fluid. The MDT optics relies ondifferences in absorption in visible and near-infrared portions of the electromagnetic spectrumto discriminate fluids in the flowline.

Pure, light hydrocarbons such as pentane areessentially colorless; they do not absorb light inthe visible spectrum. Condensates may be clearor lightly shaded reddish-yellow to tan, becausethey absorb more from the blue end of the spec-trum than from the red end. Heavier crude oils,which contain more complex molecules, absorblight strongly throughout the visible region, mak-ing them dark brown or black.

Light with a wavelength in the visible or near-infrared spectra, referred to as the color region,interacts with a molecule’s electronic energybands. Compared to less complex molecules,larger and more complex aromatic hydrocarbonmolecules, such as asphaltenes and resins,absorb light having longer wavelengths.3 Becauseheavier oils contain more aromatic compounds,they tend to have darker coloring than less denseoils and condensates (above). Waxes are color-less, but if the molecules are long enough, theywill scatter light and appear white.

Despite the differences in optical absorptionof various reservoir oils caused by composition,there is a common behavior. Electronic absorptiongenerally decreases as wavelength increases.The OD decay in the visible and near-infraredregion can be characterized by a single parame-ter, which can be thought of as the color of the oil.

To understand how OD measurements can beused to quantify contamination, it is important todistinguish between absorption in the colorregion by two kinds of hydrocarbons: complexaromatics and saturated aliphatics. Complex aro-matics contain carbon rings with both single anddouble carbon-carbon bonds, which are excitedby visible and near-infrared light. Aliphatic com-pounds are open chains of carbon atoms. If all thecarbon-carbon connections are single bonds andother bonds are with hydrogen, the aliphaticmolecule is termed saturated. Only high-energyultraviolet light can excite saturated aliphaticmolecules, so they have a low OD in the colorregion of the spectrum.

Black oils contain many complex aromaticcompounds, whereas natural OBMs comprisemostly saturated compounds; SBMs are madeonly from saturated aliphatics. The difference inchemical composition between reservoir-crudeoil and drilling-mud filtrate makes OD a goodmeasure of filtrate contamination in crude oil.

Exciting MoleculesWater can be distinguished from oil easily,because it is highly absorbing at near-infraredwavelengths around 1445 and 1930 nano-meters (nm), where oil is relatively transparent(next page, top). Oil has a strong absorption peakaround 1725 nm, where water does not. Thesepeaks come from the interaction of light withvibrational energy bands in carbon-hydrogenbonds for oil and oxygen-hydrogen bonds forwater. Molecules containing such a bond absorbphotons of the proper wavelength, and the pho-ton energy is converted into molecular vibration.Monitoring absorption at these three wave-lengths differentiates between water and oil.

Hydrocarbon compounds comprise linkedchains, branches or rings of carbon atoms, eachhaving hydrogen atoms attached. Typically, a car-bon atom will bond with two other carbon atomsand two hydrogen atoms. Carbon atoms at theend of a molecule will have three hydrogenatoms attached, while those at a branch, con-necting with three other carbon molecules, willhave only one hydrogen bond. Methane is a single carbon molecule with four hydrogen atoms attached.

The oil peak in Channel 8 of the OFA modulemeasures molecular absorption of light by carbonatoms having two hydrogen atoms attached,which are the primary constituents of reservoir

28 Oilfield Review

Optic

al d

ensi

ty

Wavelength, nm

3.0

2.5

2.0

1.5

1.0

0.5

0500 1000 1500 25002000

Asphalts

Condensates

Black oils

> Optical density of various oils. The OD spectrum of hydrocarbons is relatedto the amount of aromatics, which also relates to API gravity. Gas conden-sates have little or no color absorption beyond about 500 nanometers (nm).The range of oils grades through increasingly dense black oils having highercolor absorption out to asphalts, which absorb strongly even into the near-infrared region. All oils and condensates absorb near 1725 nm. The hydrocarbonpeak from 2300 to 2500 nm is beyond the region covered by the MDT channels.

50387schD03R1.p28.ps 11/17/01 8:31 PM Page 28

Autumn 2001 29

oils. A high-resolution optical spectrometerreveals this oil peak in much greater detail, show-ing several absorption peaks in hydrocarbon fluids(right). Although methane has some absorption atthe oil peak, there is no absorption by hydrocar-bons with more than one carbon atom at themethane peak. This provides an ideal discrimina-tor for methane content in live crude oils—uti-lized by a new MDT tool, the LFA Live FluidAnalyzer module.4 The detection channel tuned tothat wavelength replaces the OFA module’s short-est wavelength color band in Channel 0.

3. Mullins OC: “Optical Interrogation of Aromatic Moietiesin Crude Oils and Asphaltenes,” in Mullins OC and Sheu EY:Structures and Dynamics of Asphaltenes. New York,New York, USA: Plenum Press, 1998.

4. A live crude oil evolves significant quantities of gaswhen its pressure and temperature are lowered. A deadoil does not evolve gas at atmospheric pressure androom temperature. Stock-tank oil, the liquid emergingfrom the final surface separator, contains little gas.

Optic

al d

ensi

ty

00

500 1000Wavelength, nm

1500 2000

Channelnumber

1 2 3 4 5 6 7 0' 8 9

1

2

3

4

More

complex molecules

Color or electronicabsorption region

Vibrationalabsorption region

Water peak

Oil peak

Water peak

Methane peak

C HHH

H

H-C-H vibrational peak

CH

HCH

HCH

H

> Absorption spectrum. The MDT tool monitors light absorption starting in visible wavelengths and extending into the near-infrared. The ten chan-nels of the OFA module, numbered 0 through 9, are shown. In the color region on the left, crude oils have a rapidly decaying absorption, caused byinteraction of light with electrons in the molecules. More complex aromatic molecules (green shapes) absorb at longer wavelengths. Channels 6and 9 are tuned in the middle of molecular vibrational peaks for water; Channel 8 is in the molecular vibration peak for the CH2 bond in hydrocar-bons. Channel 0’, which replaces Channel 0 in the LFA module, is tuned to the methane peak.

OD

0.8

0.7

0.6

0.5

0.4

0.3

0.2

0.1

0Wavelength, nm

Methanen-HeptaneMethane-heptane mix

Oil peak

Methane peak

> High-resolution vibrational absorption spectrum of heptane, methane and amix of the two. Heptane (green) does not absorb light at the CH4 methanepeak. Methane absorption (red) at the CH2 oil peak is low. Absorption of a mix-ture of the two (black) is the sum of the individual absorptions, according tothe Beer-Lambert law. The LFA module has a channel set at the methane peak.

50387schD03R1.p29.ps 11/17/01 8:31 PM Page 29

The Key to Quantifying ContaminationThe MDT tool includes an optical module withtwo devices designed to monitor contaminationin OBM systems. A gas refractometer uses lightfrom a diode reflected off a sapphire window toqualitatively identify the fluid phase in a flowline(left). At the selected angle of incidence, thereflection coefficient is much larger when gas isin contact with the window than when oil orwater contacts it.5

The second detector in the OFA module usestransmitted light to evaluate absorption charac-teristics of a fluid. A high-temperature tungstenhalogen lamp provides a broadband source oflight that passes along optical guides andthrough a 2-mm thick optical chamber in theflowline. The distribution of transmitted light isrecorded at 10 wavelengths in the visible andnear-infrared spectra. Two of these channelsdetect the strong water-absorption peaks, indi-cating water content in the fluid when comparedwith the strong hydrocarbon-absorption peak.

Discriminating gas and water from oil is sim-pler than distinguishing between crude oil andOBM or SBM filtrate, because crude, OBM andSBM all absorb strongly at the oil peak near1725 nm. Fortunately, oils have different coloraccording to the quantity of large, complex aro-matic compounds they contain. This affectsabsorption in the MDT spectrometer in theshorter wavelength channels constituting thecolor region. Since SBM and OBM contain simplealiphatic compounds, their absorption in thesechannels is small.

In most cases, when the MDT tool first beginsdrawing fluid from a formation, the OD is highdue to light scattering off mudcake solids in thefluid. After a few seconds, the OD falls to a lowvalue, and then increases slowly as the mud fil-trate drains from the formation near the probeand is replaced by darker crude oil.

Particles of mudcake or other solid materialgenerate noise in the absorption channels.Scattering caused by these particles is wave-length-independent, so the effect can beremoved by subtracting a nearby channel. In thecolor region, absorption decreases quicklyenough that skipping a channel and subtractingfrom the next one down removes noise due toscattering without significantly affecting the sig-nal (left). The result is a smoothly varying con-tamination curve.6

The change in OD as reservoir crude replacesmud filtrate in the flowline follows the Beer-Lambert law, which states that a mixture of two

30 Oilfield Review

Fluid flowFluid flow

Gas refractometer

Optical density detectors

LampLight-emitting diode

Water

OilOilGas

> Optical detectors. Light passes through a sapphire window and reflects off the surface in con-tact with the fluid flowline into the gas refractometer. The reflection angle is set so gas reflectsmuch more strongly than oil or water. Another light path passes through a flowline into a seriesof filters to detect absorption, or optical density, in the visible and near-infrared spectra.

0.40

0.36

0.32

0.28

0.24

200 400 600 800Pumping time, sec

1000 1200 1400

OD

Channel 4

Channel 4 minus Channel 6

> Removal of scattering. To remove scattering from the OD signal, a nearbychannel at longer wavelength, which has less color absorption but the sameamount of wavelength-independent scattering, is subtracted. In this case, the signal from Channel 6 (not shown) is subtracted from Channel 4 (yellow)resulting in a data curve (red) that is fit to the OCM prediction (black).

50387schD03R1.p30.ps 11/17/01 8:31 PM Page 30

Autumn 2001 31

oils has an OD that is a linear, volumetricallyweighted combination of the two individual ODs, evaluated at each wavelength. A change in OD is directly related to a change in com-position (right).

Because most OBMs and SBMs mainly con-tain simple aliphatic compounds, their OD iseffectively zero except in the lowest MDT chan-nels. With one endpoint determined, quantitativeevaluation of contamination through OD requiresa method for finding the other endpoint—the ODof uncontaminated crude. This comes fromunderstanding the way fluids move duringcleanup. Fluid withdrawal through the probe cre-ates an expanding pressure sink around the well-bore.7 The OCM analysis fits the cleanup datawith a curve—having a specific shape based onthe physics of the tool and wellbore—to deter-mine the remaining amount of filtrate contamina-tion. In one well, five samples were captured inthe MDT tool at different times during cleanup.The laboratory results show contaminationresults consistent with the OCM model (above).8

5. Badry et al, reference 2.6. Mullins OC, Schroer J and Beck GF: “Real-time

Quantification of OBM Filtrate Contamination DuringOpenhole Wireline Sampling by Optical Spectroscopy,”Transactions of the SPWLA 41st Annual LoggingSymposium, Dallas, Texas, USA, June 4-7, 2000, paper SS.

Wavelength Pumping time

Optic

al d

ensi

ty

100% OBM

filtrate

100% crude

oil

OD1

OD2

OD3

OD4

OD5

OD at specific

wavelength

% O

BM c

onta

min

atio

n

OD1

00 100

0

∞

OD2

OD3

OD4

OD5

> Beer-Lambert mixing. Light absorption for crude oil (brown) is greater than for OBM filtrate (yellow)(left). The Beer-Lambert law says that the optical density (OD) of mixtures of the two (shades from yellow to brown) is related to the relative proportion of the two fluids. As the fluid cleans up, the ODincreases from the OBM value OD1 asymptotically to the crude-oil value OD5 (right).

OD

3.0

2.5

2.0

1.5

1.0500 2000 25001000 1500

Pumping time, sec Pumping time, sec

Sample Pumping time OFA contamination Laboratory contamination

12345

695 sec (12 min)940 sec (16 min)1264 sec (21 min)1681 sec (28 min)2250 sec (37 min)

17%13%12%9%8%

22%17%13%11%10%

0 1.0

3.0

2.6

2.2

1.8

1.410

20

30

40

50

Cont

amin

atio

n, p

erce

nt

Data and OCM fit

Acceptable contamination level

OD

Contamination

Optical density

> Quantitative prediction of contamination. Fluid samples were taken at five times during cleanup. Color channel data from the OFA module are fit using the OCM model (left) to determine contamination cleanup (right). The OCM prediction of contamination levels agrees well with laboratory contaminationmeasurement (table).

7. Hashem MN, Thomas EC, McNeil RI and Mullins O:“Determination of Producible Hydrocarbon Type and OilQuality in Wells Drilled With Synthetic Oil-Based Muds,”SPE Reservoir Evaluation and Engineering 2, no. 2 (April 1999): 125-133.

8. Mullins OC and Schroer J: “Real-time Determination ofFiltrate Contamination During Openhole WirelineSampling by Optical Spectroscopy,” paper SPE 63071,presented at the SPE Annual Technical Conference andExhibition, Dallas, Texas, USA, October 1-4, 2000.

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Like the other optical-detection bands, themethane channel of the LFA module displays ahigh OD as mud solids pass through a tool’s flow-line after pumping begins. Since drilling muds donot contain methane naturally, the initial highconcentration of filtrate drawn into the MDT toolduring cleanup results in a substantial drop in theOD recorded in the methane channel. As reser-voir fluid replaces filtrate in the line, the signalOD increases in proportion to the oil’s methanecontent, generating the same curve shape ascleanup with the OFA tool (left).

Time for complete cleanup cannot be pre-dicted before the logging run, because there aretoo many unknown reservoir variables. For exam-ple, there is not a direct relationship betweenformation permeability and cleanup time.Although fluid can be pumped quickly from ahigh-permeability formation, which would implya short cleanup time, that high permeability mayhave allowed mud filtrate to penetrate deeplyinto the formation before the wireline run. In thatcase, cleanup time could be long. Collecting flu-ids close to a shale stringer can shorten cleanuptime, since the shale provides a flow barrier,allowing collection of less contaminated reser-voir fluid farther away from the wellbore.

The ability of the OFA and LFA modules toquantify contamination levels while pumpingallows sampling decisions to be made in realtime. The OD for all channels is transmitted tosurface at high rate, and the OCM softwareupdates its analysis every 20 seconds. Once suffi-cient data have been acquired, the softwareselects the color channel that will provide thebest fit to the expected trend and shows thedegree of contamination and the time required toachieve an acceptably low level of contamination.

In a Gulf of Mexico well, the MDT probe wasset within a massive sand, and the tool measureda mobility of 87 millidarcies per centipoise(mD/cp). After pumping for 71 minutes, the OCMsoftware predicted an additional 41⁄2 hours pump-ing time to achieve an acceptable level of 10%contamination (left). Rather than wait or waste asample bottle on highly contaminated fluid, theoperator chose to move to another level withinthe same formation.

The tool was moved 44 ft [13 m] lower in theformation. The mobility was higher, 256 mD/cp.Contamination dropped to 9% within 132 min-utes, and samples taken at this location wereacceptable for PVT analysis (next page, bottom).

32 Oilfield Review

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> Contamination prediction in a Gulf of Mexico well. After noise is removedfrom an LFA color channel (red) and the methane channel (blue), each dataset is fit to the OCM prediction (smooth curves). For this sample, the colordata predict 4.9% contamination and the methane data predict 6.2%. The 5.5%average agrees with 4.3% contamination from a GC in the laboratory.

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> Avoiding long cleanup times. After the MDT tool had pumped from the for-mation for about an hour, the OCM software indicated about 18% contamina-tion (blue curve), and an additional 41⁄2 hours to achieve less than 10% con-tamination. The inset shows the OD measurement for Channels 0 through 9(shaded green). Channel 4, which has the greatest change in OD duringcleanup, was used for the fit after subtracting Channel 6 to remove scatteringfrom large particles (red curve). The vertical dashed lines at the left and rightof the plot indicate the range over which the OCM method fit the data.

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Scattering LightScattering from particles smaller than the incident-light wavelength—several hundred nanometersdiameter—depends on the wavelength of inci-dent light. The intensity of this scatteringincreases with decreasing wavelength. Thiseffect, called Rayleigh scattering, gives the skyits blue color.

Wavelength-independent scattering is removedby channel subtraction, but this leaves some wavelength-dependent Rayleigh scattering. For the OCM-color procedure, a longer-wavelength channel is subtracted, but for the OCM-methane procedure, the sub-tracted channel is at a shorter wavelength. Sinceone procedure slightly overcorrects for wave-length-dependent scattering and the otherslightly undercorrects, averaging OCM-color and OCM-methane contamination values fromthe LFA tool tends to remove some of that scattering effect (right).

Discrepancies between the contaminationdeterminations indicate the need to look moreclosely at other channels to identify the causebefore collecting a fluid sample. Methane detec-tion has been shown to be valid for fluids withGOR as low as 700 scf/bbl [126 m3/m3].9

However, in reservoirs containing oil with lowmethane content, color channels may providebetter information on contamination than themethane channel does. For gas-condensate flu-ids, methane detection using the LFA module isessential, because even in the shortest wave-length color channels, OD remains low and theprogression of cleanup using the OCM-color pro-cedure is difficult to assess. In some cases, adrilling-mud filtrate may be darker than the con-densate, and the OCM-color procedure may notbe able to discriminate contamination from reser-voir fluid. The OCM-methane detection in thenew LFA module works well in such cases.

Comparing Contamination at SurfaceSamples are collected to determine properties ofreservoir fluids such as PVT behavior. Mud filtratemixed in the sample must be accounted for toarrive at reasonable estimates of reservoir-fluidproperties. The OFA and LFA modules measure

9. Mullins O, Beck GF, Cribbs M, Terabayashi T andKegasawa K: “Downhole Determination of GOR onSingle-Phase Fluids by Optical Spectroscopy,”Transactions of the SPWLA 42nd Annual LoggingSymposium, Houston, Texas, USA, June 17-20, 2001,paper M.

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> Obtaining acceptable samples. After about two hours of pumping, contamina-tion had dropped to about 9% (blue curve). OD for all channels is shown in the inset (shaded green). The OCM model was fit to data of Channel 4 minusChannel 6 (red curve) between the start- and end-fit lines (green dashed lines).The increases in OD past the end-fit line occurred during sample collection.

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>Wavelength-dependent scattering. The optical absorption response in the pumping period between 1000 and 1500 seconds indicates some scatter-ing remains even after subtracting a baseline channel. This wavelength-dependent response is stronger in the color channel (purple) than in themethane channel (blue). The noise in the data after 2500 seconds occurredduring sample collection. The OCM method was still able to fit the data, predicting 7% contamination based on the average of color and methane data of 7.9% and 6.0%, respectively.

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contamination in real time before collecting sam-ples. At the rig floor or in a laboratory, samplecontamination can be analyzed further using agas chromatograph (GC), a gel-permeation chro-matograph (GPC), tracer analysis or, less com-monly and not discussed here, a nuclearmagnetic resonance (NMR) spectrometer.

In a GC, a small quantity of sample fluid isinjected into a carrier gas such as high-purityhelium. Light gaseous components are separatedusing a molecular sieve and heavier componentsare separated using a packed chromatographiccolumn. A molecular sieve relies on particle sizefor separation, with smaller molecules staying inthe sieve longer. In a packed column, the gasflows past particles coated with a fluid, termedthe stationary layer in a GC because the gas does not mobilize it. The relative solubility ofcomponents in the stationary layer separatesthem as the carrier gas moves a sample throughthe column. Chromatographs are calibrated forsample components.

The process is similar for a GPC except theinert carrier is a liquid, and constituents do notseparate as well at the detector. Componentpeaks from a GC are typically distinct, but thosefrom a GPC can be smeared together. TheOilphase FFA Field Fingerprint Analyser rigsitedevice incorporates a GPC.

At the end of the column, the carrier gas or liquid containing the sample enters a detector. For hydrocarbons, this is usually a thermal-conductivity detector or a flame-ionization detector. Some detection methods respond tomass and others to the number of carbon atoms inthe molecule.

The distribution of crude-oil constituents nor-mally declines smoothly with increasing carbon

number beyond eight.10 OBM and SBM filtratecontamination causes this distribution to deviatefrom the expected shape. SBMs use a narrowrange of molecular weights, so contaminationcan be discerned with both a GC and a GPC as asharp increase in the frequency of moleculesbetween carbon numbers of C14 to C18 (above).OBMs with a mineral-oil base include a broaderrange of compounds, perhaps ranging from C8 toC20, and are difficult to distinguish using a GPC.Often, these muds can be separated from thecrude-oil signature when using a GC. Drillingmuds that include produced reservoir oil cannotbe distinguished from formation oil using eitherform of chromatography, unless a tracer is addedto the mud.

An OBM or SBM filtrate response also can beremoved from the GC result by separately measur-ing the response of the filtrate, normalizing thetwo signals and subtracting.11 Drilling-mud compo-sition must be maintained while drilling an open-hole section before sampling because variations inmud composition add error to the analysis.

Sometimes, contamination is measured usingtracers, by tagging drilling mud with an isotopeor a molecule that is not present in high concen-tration in reservoir oils. For isotopic tagging ofhydrocarbons, 13C replaces 12C, or deuteriumreplaces hydrogen. Mass spectroscopy measuresthe concentration of an isotope in a reservoir-fluid sample to determine contamination.Detected isotope concentrations must be higherthan those found naturally for this procedure towork. Chemical tagging may use linear alphaolefins, detected using a GC.

Tagging is an expensive procedure that mustbe planned in advance. The isotope or chemicaltag must be in the mud in a constant concentra-tion before drilling into the zone of interest and

must remain in the mud until samples are taken,since all drilling mud that filters into the forma-tion must be tagged to have a meaningful result.Chemical tagging has an added problem: theselected molecules may not behave like reservoircrude. For example, linear alpha olefins are lessstable at high temperature than the correspond-ing alkanes, and may not travel through porousmedia at the same rate.

Results of several contamination-measure-ment techniques have been performed at Hebronfield offshore Newfoundland, Canada, and in Gulfof Mexico wells.12,13 At Hebron field, the syntheticdrilling mud was tagged with deuterium. Fluidsamples from five different zones were collectedusing the OFA module. The OCM-color procedureevaluated contamination while fluid was pumpedfrom the formation. The Oilphase FFA devicedetermined contamination using a GPC at therigsite. Isotope tag concentration was deter-mined using mass spectroscopy, and a laboratoryGC determined the constituents of the fluid.

The LFA module including the OCM analysiswas compared with laboratory GC analysis onlive oils from several Gulf of Mexico wells. Inboth this study and the Hebron field study, thereal-time LFA or OFA measurements generallyagree with the isotope, GC and FFA results(next page, top).

Some discrepancy between methods isexpected, as all methods have potential errors.The FFA device can overestimate contamination ifthe mud is not synthetic; even with SBM, both theFFA results and GC methods assume a distribu-tion of hydrocarbon constituents to determinecontamination. Tagging is expensive and in princi-ple can be accurate, but in practice, it may notobtain reliable results. It is difficult to ensure thatall the drilling mud has a uniform concentration ofthe chemical or isotopic tag and that the taggedmolecules have the same physical and transportproperties as the rest of the filtrate. The OCM-color method has problems when the mud filtratehas significant color or the reservoir oil is color-less, because the method requires a contrastbetween the two. However, the LFA-OCM-methane method provides a solution for suchcases, since it is based on methane concentration.

Even if contamination-detection methodsalways were correct, many errors can occur incollecting samples. The fluid can go through a phase transition as it is drawn into the tool,leaving components behind in the formation, orphases can separate in the tool. Valves can fail,either not opening properly downhole and cap-turing insufficient fluid or not closing completelyand losing pressure and fluid after sample collec-tion. At surface, every time the fluid is transferred

34 Oilfield Review

Oil 1Oil 2

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> Removing contamination. GC results indicated Oil 1 (blue) and Oil 2 (red) from neighboring wells hadsimilar profiles except for the contamination of C16 and C18 from synthetic drilling mud. Contaminationcan be removed by developing the trend line for Oil 1 and decreasing the concentrations of C16 and C18to the trend level. This analysis confirms that the oils came from the same source rock.

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Autumn 2001 35

or a sample bottle is handled, there is potentialfor damaging the sample. Bottles should beheated and agitated for about five days beforeperforming laboratory analyses, but not all labo-ratories follow this recommended procedure.Collecting the right base oil of the drilling mud—used to compare with spectra of contaminatedreservoir oil—is difficult because mud composi-tion often changes during a job as componentsare added to control various drilling problems.

Collection and analysis of fluid samples areimportant; operators must control sources oferror to obtain the best possible data. The OFAand LFA procedures measure properties down-hole in real time before sample collection, a distinct advantage. The few sample bottles avail-able on the tool are not wasted storing bad samples. Since OCM measurements are madebefore any possible transport and handling problems, they provide a check for the quality oflater measurements.

When sufficient information is available fromthe reservoir, measured values of fluid propertiescan be used as an additional check on samplequality. Norsk Hydro conducted a detailed studyof oil samples taken from several North Seafields.14 In a reservoir with a gas cap, both chem-ical tags and the FFA device indicated a highlevel of sample contamination, ranging from8.9% to 25.8%. The OFA-OCM method and GCanalysis indicated lower contamination levels of2.6% to 6.8%. The difference in these tworanges of contamination measurement led NorskHydro to investigate further.

Reservoir saturation pressure, Psat, at thesampling depth was estimated from reservoirpressure and density gradients starting at the gas-oil contact (right). The reservoir satura-tion pressure of the sample, based on PVT

10. Gozalpour F, Danesh A, Tehrani DH, Todd AC and Tohidi B:“Predicting Reservoir Fluid Phase and VolumetricBehaviour from Samples Contaminated with Oil-BasedMud,” paper SPE 56747, presented at the SPE AnnualTechnical Conference and Exhibition, Houston, Texas,USA, October 3-6, 1999.

11. MacMillan DJ, Ginley GM and Dembicki H: “How toObtain Reservoir Fluid Properties from an Oil SampleContaminated with Synthetic Drilling Mud,” paper SPE38852, presented at the SPE Annual TechnicalConference and Exhibition, San Antonio, Texas, USA,October 5-8, 1997.Gozalpour et al, reference 10.

12. Connon D: “Chevron et al. Hebron M-04 ContaminationPrediction Method Comparison,” Released ProjectReport available at Canada-Newfoundland OffshorePetroleum Board, St. John’s, Newfoundland, Canada,May 1, 2001.

13. Mullins et al, reference 9.14. Fadnes FH, Irvine-Fortescue J, Williams S, Mullins OC

and Van Dusen A: “Optimization of Wireline SampleQuality by Real-Time Analysis of Oil-Based MudContamination—Examples from North Sea Operations,”paper SPE 71736, presented at the SPE Annual TechnicalConference and Exhibition, New Orleans, Louisiana,USA, September 30-October 3, 2001.

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> Comparing different methods of evaluating contamination. Contamination measurements of fluidsamples from Hebron field (left) and Gulf of Mexico wells (right) indicate agreement among differentmethods for most samples.

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> Using reservoir properties to evaluate contamination measurements. The known gas-oil contact,pressure gradient (blue line) and saturation-pressure, or bubblepoint, gradient (green line) intersect atthe gas-oil contact for a North Sea well. The contaminated sample had a bubblepoint pressure ofabout 272 bar [27.2 MPa or 3950 psi] (dark brown). PVT modeling allowed prediction of bubblepointpressure of uncontaminated oil by mathematically removing measured contamination from the sample.Removing 9% contamination, measured using isotopic tagging and the FFA procedure, produced anunphysical result above the reservoir values (purple). Removing only 3% contamination (dark blue),based on the OFA-OCM result, did not raise the bubblepoint enough. Assuming the sample bottle deadvolume of 2.5% was all lost gas provides another factor to adjust the PVT properties of the contami-nated sample (light brown). Combining the 3% contamination correction with the gas-loss correctionbrings the prediction of bubblepoint (light blue) close to the saturation-pressure gradient.

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properties determined with contaminants in thefluid, was about 20 bar [2 MPa or 290 psi] belowthe saturation-pressure gradient at the samplingdepth. These PVT properties can be mathemati-cally corrected to remove the effect of contami-nants and then compared with the reservoir-gradient calculation.

When using the FFA contamination value of9%, the resulting calculated Psat was greaterthan the reservoir pressure, which is an unphysi-cal result. When using the OFA-OCM value ofcontamination, Psat was about 10 bar [1 MPa or145 psi] below the expected value. This indicatesthe sample may have lost gas before PVT proper-ties were evaluated. Gas could separate from liq-uid in the formation due to near-well pressuredrawdown, but the downhole conditions werenot known well enough to evaluate this effect.The investigation focused on what happened tothe sample coming out of the hole.

The sample bottle did not allow for downholepressure compensation. The fluid could enter thetwo-phase region due to cooling from the reser-voir temperature of 107ºC [225ºF] during trans-port to surface. The sample had probably cooledbelow 102ºC [217ºF]—the temperature at whichpressure in the enclosed chamber decreasedbelow the bubblepoint—and was in two phasesby the time it reached the surface. The 450-cm3

bottle has a dead volume of 2.5% between theisolating valve on the bottle and the valve on thedownhole flowline, which could have been filledwith gas that was lost when the valves wereopened at the surface. The PVT properties of the contaminated samples can be corrected forthis gas loss, increasing the contaminated-sample bubblepoint pressure by 10 bar. Whenthe gas-loss correction is combined with removalof the contamination, as measured by the OCM-color method, Psat increased to within 4 bar

[0.4 MPa or 58 psi] of the expected reservoirvalue, which is reasonable agreement. This anal-ysis could not have been performed without thedownhole OCM-contamination measurement.

Monitoring Gas DirectlyGas-condensate fields engender additional diffi-culties for fluid sampling when OBM and SBMare used. Although they contain single-phase flu-ids in the reservoir, gas condensates separateinto a gas phase and a liquid phase when condi-tions drop below the dewpoint. The liquidderived from gas condensates is a more valuablecommodity than the gas. Surface-separator con-ditions are tuned to optimize the volume andvalue of liquid obtained from condensates. Theseparator designs often are based on fluid prop-erties from wireline samples, so determining thelevel of contamination and correcting the PVTproperties are essential.

OBM and SBM filtrate may mix only partiallywith condensate in a reservoir, leaving mud fil-trate in a liquid-hydrocarbon phase and a gasphase with some of the more volatile compo-nents of the filtrate. A wireline sampling probedraws both hydrocarbon phases into the device,and samples collected contain both reservoirfluid and filtrate contamination. When the fluidpressure is lowered during laboratory testing, thephases separate. All mud filtrate is concentratedin the liquid phase; presence of contaminationstrongly affects a sample’s dewpoint pressure.

To calculate a correct GOR and other reser-voir-fluid properties, the volume of the oil phasemust be adjusted to remove contamination. Thatliquid-phase contamination must be kept low toavoid excessive correction factors, just as with ablack oil. However, to compensate for the con-centration of SBM and OBM contaminants in theliquid phase, many companies set the acceptablelevel of contamination in a gas condensatebelow that for a black oil. The LFA tool providessignificant new information for gas-condensatereservoirs, improving data quality used fordesigning production facilities.15

A gas-condensate prospect in the NorwegianNorth Sea offered one of the first tests for the LFAtool, used in this case without the OCM module.16

A mobile C36+ GC, capable of measuring individualconstituents up to C36 at the rigsite, indicatedcontamination of 32% to 60% in the low-pressureliquid phase. This was comparable to results fromsubsequent FFA analysis onshore. The LFA time-sequence data were later analyzed using the

36 Oilfield Review

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> Cleanup curve for gas condensate. This North Sea gas condensate wastransparent. Even the OD of the shortest wavelength channel (top) showedinsufficient contrast to reliably determine OD buildup using the OCM-colormethod (red). Cleanup was more reliable in the methane channel (bottom)(pink), giving a more quantifiable OCM-methane fit to the OD data (black). Calculated values of contamination are shown in the lower plot, with anOCM-color curve (green), an OCM-methane curve (purple) and the average of the two (blue). In this case, the large discrepancy is caused by the lightcolor of the condensate.

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Autumn 2001 37

OCM method. Mud filtrate and the reservoir fluidwere indistinguishable in the color channels. The OCM-methane analysis provided a quantita-tive contamination measurement, about 8% of the live oil (previous page). The operator had littleexperience with the new tool and sought to under-stand the difference.

A subsequent well test proved a gas-conden-sate find. Surface-separator samples collectedduring the flowing well test and analyzed using aC36+ GC indicated stock-tank oil contamination of23%. A full PVT analysis provided the GOR,allowing correction of contamination to single-phase, downhole conditions. The result indicated6 to 7% contamination, which agreed well withthe OCM-methane measurement on the live fluid.

During determination of fluid properties for agas-condensate reservoir drilled with OBM, thebuildup of methane measured with the LFA moduleis essential to obtain accurate, real-time conden-sate-contamination measurement. The alternativesare to conduct a DST or complete a well withwater-base mud to avoid oil contamination altogether. Moreover, using the LFA device alsoprovides a simultaneous measurement of GOR.

The gas refractometer on both the OFA and LFA tools indicates gas only when it is in con-tact with the detector window. Gas bubbles maynot be detected if they are in the center of the

flowstream, or on the opposite side. The refrac-tometer detects all gases, regardless of composi-tion, so CO2 and H2S are flagged.

The LFA module also provides a complemen-tary gas-detection system using measurement ofOD in the methane channel. Although insensitiveto other gases, this detector monitors allmethane passing through the flowline. If live oilis flowing, the volume percentage of methanewill be low. However, if the pressure drops belowthe bubblepoint, gas evolves and methaneabsorption will be high when a bubble passes thelight beam anywhere within the flowline. Thecombination of the gas refractometer andmethane detector makes a robust LFA gas-detec-tion method (right).

The ratio of the methane peak to the oil peakin the LFA module correlates with GOR both formixtures of pure components and for live crudeoils (above). A multiplying factor applied to themethane-heptane mixtures compensates forother hydrocarbon components in the gas phaseof reservoir oils. The tool does not measure CO2 orH2S, so the LFA-GOR measurement may be incor-rect for fluids from reservoirs containing signifi-cant quantities of these nonhydrocarbon gases.

15. Mullins et al, reference 9.16. Fadnes et al, reference 14.

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> LFA gas-detection combination. After an initialcleanup period, the color Channels 1 through 5 inTrack 4 show little absorption, confirming a gascondensate. Channels 6 and 9 also have low OD,which means no water is present. The oil peak inChannel 8 is transformed into an oil flag in Track 2(green), indicating periods when no oil flows, particularly from 1116 to 1188 seconds and 1422 to 1458 seconds. The gas refractometer in Track 1(red) measures all gases, but only when they contact the sapphire window of the refracto-meter. It misses some periods of gas flow. The LFAmethane response from Channel 0, expanded inTrack 5, is sensitive to all methane in the flowline,but not to other gases. The combination of the twogas detectors is more robust than either alone.

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> GOR measurement derived from molecular vibration peaks. In laboratorytests, the ratio of absorption at the methane peak to the oil peak fits well withGOR for both methane-heptane mixtures (red squares) and live oils (blue circles). The multiplicative factor applied to the methane-heptane mixturesaccounts for the absence of other gases normally present in live oils. The deadcrude oil (orange triangle) was evaluated after gas was removed in the laboratory.

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Real-Time Fluid TypingThe combination of the MDT system and theCMR Combinable Magnetic Resonance toolrevealed new insights about a reservoir operatedby Shell in the Gulf of Mexico. The Yellow sandunit had been depleted for two years. The newdrilling target was an underlying sandstone for-mation, called the Blue sand, separated from theoverlying reservoir by a thick shale.

A logging-while-drilling (LWD) resistivity logrevealed a 10-ft [3-m] water layer on top of theBlue sand oil, which is not a gravitationally stablesituation. A thin hydrocarbon layer sat atop thewater, just below the thick shale (below). Theoperator wanted to know whether water fromabove had broken through. The LWD gamma raylog and standard CMR processing did not explainhow this water could be above the oil (right).Pressures collected with an MDT tool indicatedthat the water zone was not in pressure commu-nication with either the Yellow sand above or theBlue sand below. Reservoir pressure in the waterzone was about 800 psi [5.5 MPa] higher than theBlue sand, and was slightly less than originalreservoir pressure for the Yellow sand.

The depleted Yellow sand placed a limit onthe mud weight that could be used in the bore-hole. This created concerns about the wellbore;the well was not stable enough to leave the MDTtool in place long enough for formation fluid toclean up. The MDT tool was used instead for fluidtyping with the gargling technique developed byShell Deepwater Services.17 In this technique,reservoir fluids from the formation were pumpedfor a short period of time through the OFA mod-ule and out to the wellbore, without collectingsamples in bottles. An OD spectrum from the OFAmodule allowed analysis of these small quanti-ties of reservoir oil. Since oil color relates to APIgravity and GOR, the color pattern from the 10OFA channels enabled discrimination betweenthe oils. In this case, the Yellow sand was a gascondensate with an API gravity of about 40º and

a GOR of 6000 scf/bbl [1080 m3/m3], while theBlue sand held a 35º API gravity oil with a GOR of2000 scf/bbl [360 m3/m3]. Surprisingly, the colorspectrum of the hydrocarbon sitting on top of thewater had the same signature as the Yellow sandabove the thick shale.

The CMR log data were reprocessed toimprove resolution from 18 in. [46 cm] to about8 in. [20 cm], revealing a thin permeability barrierat the base of water, thought to be about 6-in.[15-cm] thick. This led to a rethinking of the dis-tinction between the top and bottom units. Inother wells, the Yellow sand remained above thelarge shale, but in this well, a splinter member ofthe Yellow sand cut below the shale. The trueboundary between the zones was the thin barrier,which appeared to be sand on sand, undifferenti-ated on conventional logs.

38 Oilfield Review

Depletedcondensatein Yellowsand

Shale

Splinter ofYellow sand

Target oil inBlue sand

> Section of Yellow sand below shale. The Yellowsand above the shale is saturated with a conden-sate. The oil-saturated Blue sand did not extendto the shale, but stopped at a thin barrier (thickblack line). The splinter of the Yellow sand unitbelow the thick shale had a water leg (blue) belowa thin layer of condensate.

Pumpout at X61635° API gravity

Pumpout at X59740° API gravity

Pumpout at X64035° API gravity

Pumpout at X48240° API gravity

LWD CMR Standard-Resolution CMRHigh-Resolution

Gamma Ray Resistivity

MDT

Pressure

MDT-OFA

Fluid TypingPermeabilityPermeability Porosity

Blue

sand

Yello

w sa

ndSh

ale

NMR T2

>Water above oil investigated by MDT-OFA fluid typing. There is a water zone over the oil-saturatedBlue sand, located at the blue arrow pointing to the low resistivity in Track 2. The responses in thegamma ray and standard-resolution CMR logs do not explain how this water zone can sit atop oil. Areprocessed high-resolution CMR permeability log (Track 6) shows a thin permeability barrier, indi-cated by the green arrow. MDT logging shows three pressure compartments: the depleted Yellowsand above the shale, the Blue sand below the barrier and the region between the shale and the thinbarrier at high pressure. The MDT color channels, evaluated at the depths indicated by the blackarrows, were used to type the reservoir fluids. The oil atop the water above the barrier has the samecharacteristics as the oil in the Yellow sand. This caused the operator to reevaluate the boundarybetween the Yellow and Blue sands in this well as being at the thin barrier rather than the thick shale.

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Autumn 2001 39

Had this been an exploration well, facilitiesplanning would have relied on results from fluidsampling. Depending on where the samples werecollected, the GOR could have been too high ortoo low, leading to an inefficient design. If thesample GOR measured were lower than theactual production, the facilities would have anundercapacity for gas production, and insufficientcompression and transmission capabilities,resulting in lost or delayed revenues. Significanterror in GOR in the opposite direction could havethe opposite problem—an expensive overdesignwith too much capacity. MDT fluid typing is avaluable means for detecting such situations.

In a well in the North Sea, Norsk Hydro drilleda pilot hole through three horizons prior to drillinga horizontal section.18 The typical log response inthis field made distinguishing the fluid type ineach formation difficult. Precise definition of fluidcompositions was not required, but rapid differ-entiation of gas, oil and water was imperativebecause the rig was idle while the operatorawaited this fluid identification. The operatorwanted to drill a horizontal wellbore into thedeepest oil-bearing zone. The MDT sonde waschosen to identify the fluids in real time.

Pumping fluid into the tool progressed untilthe OFA-OCM method indicated contaminationhad dropped below 8% in the middle zone and to1% in the upper zone. The MDT tool indicatedthat the lower zone was water-filled. The lowcontamination values in the other zones gave theoperator confidence in the tool response, whichshowed that the reservoir fluid was oil. A 3%-olefin tracer placed in the OBM mud beforedrilling the section allowed rapid confirmation ofthese contamination values using a GC at the rig.The surface contamination measurements—5% in the middle zone and 4% in the upper—provided reasonable agreement with the OFA-OCM measurement.

Although additional fluid samples had beencollected for testing onshore, the real-timeresults using the OFA-OCM analysis coupled witha rigsite GC confirmation provided answers thatwere conclusive enough to cancel the onshoretesting program. The horizontal section wasdrilled into the middle horizon immediately aftercompleting the MDT run, resulting in a success-ful well.

Norsk Hydro no longer uses olefin tracers totag drilling mud. Recent wells have relied suc-cessfully on the combination of the OCM methodand a C36+ GC.

Fluid Compartments in Hibernia FieldThe Hibernia field, discovered in 1979 and oper-ated by Hibernia Management and DevelopmentCompany, Ltd. (HMDC), was the first significantoil discovery in the Jeanne d’Arc basin on theGrand Banks of Newfoundland, Canada. Oil pro-duction commenced on November 17, 1997, froman ice-resistant, gravity-based platform in 80 m[262 ft] of water, 315 km [196 miles] east-south-east of St. John’s, Newfoundland (above).

The structure is a highly faulted, south-plung-ing anticline containing approximately 3 billionbarrels [475 million m3] of oil-in-place, with anestimated 750 million recoverable barrels[120 million m3]. Most of these resources are intwo Lower Cretaceous reservoirs, the Hibernia,and the combined Ben Nevis and Avalon sand-stones. The Hibernia reservoir will be depleted

17. Hashem et al, reference 7.18. Fadnes et al, reference 14.

2000 m

100 km62 miles

200 m

NEWFOUNDLAND

Atlantic Ocean

Water depth

Rift-basinoutlines

St John’sHibernia field

C A N A D A

> Hibernia field, offshore Newfoundland, Canada.

50387schD03R1 11/29/01 3:36 AM Page 39

using both waterflood and gasflood processes(above). Delineation drilling of the Ben Nevis andAvalon formations continues; these reservoirswill be produced under waterflood.

HMDC encountered operational problemswhile drilling the first four wells using WBM.Shifting to OBM resulted in improved boreholeconditions, few seal losses while running thelogs and decreased logging-acquisition time.

Extensive faulting makes reservoir continuityuncertain. Early in field development, HMDC ini-tiated a comprehensive data-acquisition plan todetermine fluid compositional variation betweenfault blocks and within the vertically extensivefluid column. Obtaining high-quality sampleswith the MDT tool is an integral part of the program for determining reservoir-fluid proper-ties. MDT pressure measurements establishpressure gradients and locate gas-oil and water-oil contacts.

Fluid samples were collected in three ways—MDT samples, bottomhole samples and separa-tor samples. The MDT string typically wasconfigured to obtain approximately 30 pressurepoints across selected reservoir intervals andincluded six MPSR sample bottles. Several wellswere sampled using 12 sample cylinders: six

40 Oilfield Review

Bonavistaplatform

Mur

re fa

ult

Nautilus fault

N

0

0 1 2 3 miles

1 2 3 4 5 km

> Hibernia water- and gasfloods. The 3D image indicates some of the oil-production (green), water-injection (blue) andgas-injection (red) wells in the highly faulted reservoir (left). The structure map shows distinct fault blocks in the Hiber-nia formation (right). Part of the field is under waterflood (blue) and part under gasflood (red). The section line (black)indicates the location of the cross section shown on page 42.

3550

3600

3650

3700

3750

3800

3850

3900

3950

4000125 175 225

GOR, m3/m3

Dept

h, m

275 325 375

B-16 5 MDT 2B-16 5 MDT 3

B-16 6 MDT 3

B-16 3 MDT 4B-16 2 BHSB-16 6 MDT 1

B-16 1 BHSB-16 1 BHS

B-16 3 BHS

B-16 3 BHSB-16 3 BHS

B-16 1 BHS

B-16 3 MDT 3

B-16 9 MDT 6C-96 DST 4 BHS

C-96 DST 3 BHS

C-96 DST 1 BHS

B-16 9 MDT 3

B-16 11 MDT 6

B-16 7 MDT 2

B-16 7 MDT 3

> Hibernia GOR. Fluid samples from the MDT tool and from bottomhole samples(BHS) from DSTs indicate the trend of GOR with depth. Separator samples fromHibernia are not associated with a specific depth and are not shown here. (225 m3/m3 = 1249 scf/bbl.)

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Autumn 2001 41

MPSR cylinders and six pressure-compensatedSPMC cylinders. The variation of PVT propertiesin the MDT samples helped define depth andareal trends, which were further refined by geo-chemical fingerprinting of the samples. MDTdetection of OBM contamination was importantfor the program. Use of OCM real-time monitor-ing allowed collection of high-quality gas-condensate samples.

Initially, bottomhole samples from the entireperforated interval were collected during produc-tion testing to obtain representative PVT proper-ties. Single-phase flow conditions weremaintained downhole during sampling. Fluidsamples collected from test separators were lessexpensive, allowing continued monthly samplingto monitor compositional changes. Samples fromthe three sources have shown excellent agree-ment in PVT studies and determination of OBM-contamination levels (previous page, bottom).

The operator uses PVT data from thesesources for well-test analysis, reserves determi-nation, material balances, reservoir simulation,production allocation, production monitoring andfluid-metering factors, process simulation andregulatory reporting.

The initial pressure in the Hibernia reservoirwas approximately 40 MPa [5800 psi]. Becausethe bubblepoint varies across the field, the company avoided sampling below bubblepointpressure. The MDT tool monitored pressure during sampling, allowing minimal drawdownand accurate bubblepoint determination fromrecovered samples.

The OFA module detected sample contamina-tion levels to estimate pumping time to achievecleanup. About halfway through the sample-col-lection program, the OCM option became avail-able, providing a quantitative measure of

contamination in real time. The OFA results fromthe previous logging runs were analyzed laterusing the OCM-color methodology to determinecontamination levels (above).

The MDT sampling tool is an effective meansof collecting representative fluid samples to eval-uate variations through long fluid columns. TheHibernia group has successfully run the tool onwireline, but because of wellbore deviations upto 80°, the tool typically was run as part of a TLCTough Logging Conditions superstring. The TLCtool usually includes the Platform Express inte-grated tool, including the AIT Array InductionImager Tool sonde, a caliper and gamma ray tool,and the MDT modules. Logs collected on a firstpass were transmitted in real time to the com-pany office in St. John’s where engineers pickedpoints for MDT pressure determination and asample-collection pass. With fluid columns inexcess of 400 m [1300 ft] thick in areas of the

5-2

5-3

5-4

5-5

5-6

8-1

8-3

8-5

11-5

11-6

12-1

12-2

12-3

12-4

12-5

12-6

14-2

14-3

Sam

ple

num

ber

0 20 40 80 10060Oil-base mud contamination, %

Sam

ple

num

ber

0 20 40 80 10060Oil-base mud contamination, %

20-6

20-5

20-4

20-3

20-2

20-1

19-1.11

19-1.10

19-1.09

19-1.08

Sam

ple

num

ber

0 20 40 80 10060Oil-base mud contamination, %

OFA-OCM measurementGas chromatograph

Gasflood Wells Waterflood Wells Ben Nevis and Avalon Wells

6-1

6-3

6-4

6-5

6-6

7-2

7-3

9-1

9-3

9-5

16-1

16-2

16-4

16-5

16-6

17-1

17-2

17-3

17-4

17-5

17-6

OFA-OCM measurementGas chromatograph

OFA-OCM measurementGas chromatograph

> Comparison of contamination measurements. The OFA-OCM measurement at the wellsite agrees well with laboratory GC measurements for the gasflood(left) and waterflood (middle) zones of the Hibernia formation and Ben Nevis and Avalon formations (right).

50387schD03R1.p41.ps 11/17/01 8:32 PM Page 41

42 Oilfield Review

NW C block SEB block

4200

Dept

h su

bsea

, m

3400

4000

3800

3600

WOC

GOC

B-08

B-16 10z

B-1614

5:1 vertical exaggeration

B-1615z

B-1611

0

0 10.5 1.5 miles

1 2 km

> Cross section spanning Blocks B and C in the Hibernia field gasflood area. The Hibernia formation dips steeply,plunging into the Murre fault in the northwest. The gas-oil contact (GOC) is shown at the crest. The water-oil contact(WOC) is unknown in the southeast; in the northwest it lies between the two marked depths. This section line is indi-cated on the map on page 40.

Dete

ctor

resp

onse

700

600

500

400

300

200

100

00 10 20 30 40

Time, min

50 60 70 80

n-C 10

n-C 15

n-C 30

n-C 22

n-C 20

n-C 18

Ph

n-C 17

Pr

n-C 16

n-C 12

n-C 14

Pr Ph

n-C 20

Hibernia oil sample

Base oil

n-C 25

n-C 30

> Gas chromatograms of reservoir and drilling-mud base oils. The sharp peaks on the curves are spe-cific carbon compounds, such as normal-alkane C30 [n-C30]. Pristane (Pr) and phytane (Ph) are geo-markers found in reservoir fluids. A scaling factor is applied to the base-oil spectrum before subtract-ing it from the reservoir-oil spectrum. The scaling factor is related to the degree of contamination.

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Autumn 2001 43

field, using MDT pressures and fluid-type deter-mination to establish gas-oil and water-oil contacts was important (previous page, top). A significant benefit of the MDT logging program is real-time decision-making on sample collection points.

MDT fluid-sample composition was deter-mined in a PVT laboratory by the GC method. Thechromatogram of the base oil of the mud wassubtracted from the sample GC spectrum (previous page, bottom). The resulting peak-height spectra from different blocks, coupledwith other PVT data such as the bubblepointpressure, GOR and formation volume factor, pro-vided evidence to correlate oil from differentfault blocks, indicating seven distinct fluidregions across the field (above). With this infor-mation, gasflooding and waterflooding can beimplemented more efficiently. Formation pres-sures from openhole MDT runs also indicatedwhether offset production had drawn down for-mation pressure in the new locations. Other mea-surements made on the reservoir fluids, includingwax content, sulfur content, acid number, pourpoint, cloud point and saturates-aromatics-resins-asphaltenes content, also indicated varia-tions by fault block, impacting the production andcompletion strategies.19

A Downhole Chemistry LaboratoryDistinguishing fluid phases may seem like someof the simplest chemistry that can be performed.Doing it from miles away, in a harsh environment,is the significant new accomplishment of theMDT tool. The channels of absorption informa-tion in the OFA tool have allowed correlationwith many more attributes of the fluid: oil-shrink-age factor, bubblepoint pressure, oil compress-ibility, oil density and average molecularweight.20 Minimizing contamination in collectedsamples and controlling phase separation duringcollection to enhance the value of in-situ fluidproperties measurements is an ongoing chal-lenge. The additional capabilities in the new LFAmodule provide direct measurement of methanecontent, allowing estimation of GOR and a morerobust gas flag to avoid taking the fluid into thetwo-phase region.

In addition, obtaining fluid samples frombehind casing is significantly easier now. TheCHDT Cased Hole Dynamics Tester tool can drillup to six holes through casing in one trip and, incombination with other MDT modules, obtainsamples and monitor contamination in real time.It then seals the hole through the casing with a

corrosion-resistant plug rated to 10,000-psi [69-MPa] differential pressure.

Already, significant decisions are made basedon real-time downhole fluid measurements.Continuing development will improve the rangeand reliability of these measurements. —MAA

Bonavistaplatform

Mur

re fa

ult

Nautilus fault

N

0

0 1 2 3 miles

1 2 3 4 5 km

> Fluid regions in Hibernia field. Seven distinct regions are defined for Hibernia fluids, based on constituents and physical properties determined from DST and MDT fluid samples.

19. The pour point is the lowest temperature at which an oil will begin to flow under standard test conditions. The cloud point is the temperature at which paraffinmolecules first start to crystallize from oil, as observed visually.

20. Van Dusen A, Williams S, Fadnes FH and Irvine-Fortescue J: “Determination of Hydrocarbon Propertiesby Optical Analysis During Wireline Fluid Sampling,”paper SPE 63252, presented at the SPE Annual TechnicalConference and Exhibition, Dallas, Texas, USA, October 1-4, 2000.

50387schD03R1.p43.ps 11/17/01 8:33 PM Page 43

44 Oilfield Review

Global Warming and the E&P Industry

Melvin CannellCentre for Ecology and HydrologyEdinburgh, Scotland

Jim FilasRosharon, Texas, USA

John HarriesImperial College of Science, Technology and MedicineLondon, England

Geoff JenkinsHadley Centre for Climate Prediction and ResearchBerkshire, England

Martin ParryUniversity of East AngliaNorwich, England

Paul RutterBPSunbury on Thames, England

Lars SonnelandStavanger, Norway

Jeremy WalkerHouston, Texas

For help in preparation of this article, thanks to DavidHarrison, Houston, Texas, USA; Dwight Peters, Sugar Land,Texas; and Thomas Wilson, Caracas, Venezuela. Specialthanks to the Hadley Centre for Climate Prediction andResearch for supplying graphics that were used as a basisfor some of the figures appearing in this article.

The question as to what extent man-made emissions of greenhouse gases may be

causing climate change has stirred intense debate around the world. Continued shifts

in the Earth’s temperatures, predicted by many scientists, could dramatically affect the

way we live and do business. This article examines the evidence and the arguments,

and describes some of the mitigating actions being taken by the exploration and pro-

duction (E&P) industry.

Scientists use language cautiously. They tend toerr on the side of understatement. During themid-1990s, in the Second Assessment Report ofthe Intergovernmental Panel on Climate Change(IPCC), leading scientists from around the worldexpressed a consensus view that “the balance ofevidence suggests a discernible human influenceon global climate.” In July 2001, for the IPCCThird Assessment Report, experts took this con-clusion a step further. Considering new evidence,and taking into account remaining uncertainties,the panel stated “most of the observed warmingover the last 50 years is likely to have been dueto the increase in greenhouse-gas concentra-tions.”1 The word ‘likely’ is defined by the IPCC asa 66 to 90% probability that the claim is true.

An important and influential segment of theglobal scientific community firmly believes thathuman activity has contributed to a rise in theEarth’s average surface temperature and a result-ing worldwide climate change. They contend thatsuch activity may be enhancing the so-called‘greenhouse effect.’ Other distinguished scien-tists disagree, some dismissing the IPCC view as simplistic.

The Greenhouse and EnhancedGreenhouse EffectsThe greenhouse effect is the name given to theinsulating mechanism by which the atmospherekeeps the Earth’s surface substantially warmerthan it would otherwise be. The effect can beillustrated by comparing the effects of solar radiation on the earth and the moon. Both areroughly equidistant from the sun, which suppliesthe radiation that warms them, and both receiveabout the same amount of heat energy persquare meter of their surfaces. Yet, the earth ismuch warmer—a global average temperature of15°C [59°F] compared with that of the moon, -18°C [-0.4°F]. The difference is largely due to thefact that the moon has almost no atmospherewhile the Earth’s dense atmosphere effectivelytraps heat that would otherwise escape into space.

Climatologists use a physical greenhouseanalogy to explain how warming occurs. Energyfrom the sun, transmitted as visible light, passesthrough the glass of a greenhouse without hin-drance, is first absorbed by the floor and con-tents, and then reemitted as infrared radiation.

1. Climate Change 2001: The Scientific Basis: TheContribution of Working Group I to the Third AssessmentReport of the Intergovernmental Panel on ClimateChange. New York, New York, USA: Cambridge UniversityPress (2000): 10.

50387schD01R1 11/29/01 5:23 AM Page 44

50387schD01R1 11/29/01 5:24 AM Page 45

Because infrared radiation cannot pass throughthe glass as readily as sunlight, some of it istrapped, and the temperature inside the green-house rises, providing an artificially warm envi-ronment to stimulate plant growth (right).

In the natural greenhouse effect, the Earth’satmosphere behaves like panes of glass. Energycoming from the sun as visible short-wavelengthradiation passes through the atmosphere, just asit does through greenhouse glass, and isabsorbed by the surface of the earth, which thenreemits it as long-wavelength infrared radiation.Infrared radiation is absorbed by naturally occur-ring gases in the atmosphere—water vapor, carbon dioxide [CO2], methane, nitrous oxide,ozone and others—and reradiated. While someenergy goes into outer space, most is reradiatedback to earth, heating its surface.2

An enhanced greenhouse effect occurs whenhuman activities increase the levels of certainnaturally occurring gases. If the atmosphere ispictured as a translucent blanket that insulatesthe earth, adding to the concentration of thesegreenhouse gases is analogous to increasing thethickness of the blanket, improving its insulatingqualities (below).

46 Oilfield Review

Visible energy from the sun passes through the glass, heating the ground.

Some reemitted infrared radiation is reflected by the

glass and trapped inside.

> The greenhouse analogy. A greenhouse effectively traps a portion of thesun’s energy impinging on it, raising the interior temperature and creating anartificially warm growing environment.

Absorption of outgoingradiation by indigenousatmospheric gases

Incomingshort-wavelength

radiation

Natural Greenhouse Effect Enhanced Greenhouse Effect

Reradiationinto space

Reradiationto earth

Outgoinglong-wavelength

radiation

Enhancedabsorption bygreenhouse gases

Reradiationinto space

Incomingshort-wavelength

radiation

Reradiationto earth

Outgoinglong-wavelength

radiation

> Natural and enhanced greenhouse effects. In the natural greenhouse effect (left), indigenous atmospheric gases contribute to heating of the Earth’s surface by absorbing and reradiating back some of the infrared energy coming from the surface. In the enhanced greenhouse effect (right), increased gasconcentrations, resulting from human activity, improve the atmosphere’s insulating qualities.

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Autumn 2001 47

Man-made emissions of greenhouse gasesoccur in a number of ways. For example, carbondioxide is released to the atmosphere when solidwaste, wood and fossil fuels—oil, natural gasand coal—are burned. Methane is emitted by decomposing organic wastes in landfill sites, during production and transportation of fossilfuels, by agricultural activity and by dissoci-ation of gas hydrates. Nitrous oxide is ventedduring the combustion of solid wastes and fossil fuels (above left).

Carbon dioxide is the most important, dueprincipally to the fact that it has an effective life-time in the atmosphere of about 100 years, and isthe most abundant. Every year, more than 20 bil-lion tons are emitted when fossil fuels areburned in commercial, residential, transportationand power-station applications. Another 5.5 bil-lion tons are released during land-use changes,such as deforestation.3 The concentration of CO2

in the atmosphere has increased by more than30% since the start of the Industrial Revolution.

Analysis of air trapped in antarctic ice capsshows that the level of carbon dioxide in theatmosphere in pre-industrial days was about 270parts per million (ppm). Today, readings taken atthe Mauna Loa Observatory in Hawaii, USA,place the concentration at about 370 ppm.4

Concentrations of methane and nitrous oxide,which have effective lifetimes of 10 and150 years, respectively, also have increased—methane more than doubling and nitrous oxiderising by about 15% over the same time span.Both are at much lower levels than CO2—methane at 1.72 ppm and nitrous oxide at0.3 ppm—but they exert a significant influencebecause of their effectiveness in trapping heat.Methane is 21 times more effective in this regardthan CO2, while nitrous oxide is 310 times moreeffective, molecule for molecule.5

The global-warming potential of a gas is ameasure of its capacity to cause global warmingover the next 100 years. The warming effect ofan additional 1-kg [2.2-lbm] emission of a green-house gas discharged today—relative to 1 kg of

CO2—will depend on its effective lifetime, theamount of extra infrared radiation it will absorb,and its density. On this basis, experts calculatethat, during this century, CO2 will be responsiblefor about two-thirds of predicted future warming,methane a quarter and nitrous oxide around atenth (above right).6

2. The description above is a simplification. In fact, about25% of solar radiation is reflected back into space beforereaching the Earth’s surface by clouds, molecules andparticles, and another 5% is reflected back by the Earth’ssurface. A further 20% is absorbed before it reaches theearth by water vapor, dust and clouds. It is the remain-der—just over half of the incoming solar radiation—thatis absorbed by the Earth’s surface. The greenhouse anal-ogy, although widely used, is also only partly accurate.Greenhouses work mainly by preventing the natural pro-cess of convection.

3. Jenkins G, Mitchell JFB and Folland CK: “The GreenhouseEffect and Climate Change: A Review,” The Royal Society(1999): 9-10.

4. Reference 1: 12.5. “The Greenhouse Effect and Climate Change: A Briefing

from the Hadley Centre,” Berkshire, England: HadleyCentre for Climate Prediction and Research (October1999): 7.

6. Reference 5: 7.

Methane 24%

Nitrous oxide 10%

Others 3%

Carbon dioxide 63%

> Relative warming projected from differentgreenhouse gases during this century. Of the various greenhouse gases, carbon dioxide is pre-dicted to have the greatest capacity for causingadditional global warming, followed by methaneand nitrous oxide.

Carbon dioxide

Methane

Nitrous oxide

Chlorofluorocarbons

Ground-level ozone

Aerosols

Combustion of fossil fuels and woods Land-use changes

Production and transport of fossil fuelsDecomposing wasteAgricultureDissociation of gas hydrates

Combustion of fossil fuelsCombustion of waste

Production

TransportIndustrial emissions

Power generationTransport

100 years

10 years

150 years

100 years

3 months

2 weeks

Atmospheric constituent Source Lifetime

> Man-made emission sources and lifetimes forgreenhouse gases. Various gases and aerosolsare emitted daily in commercial, industrial andresidential activities. Carbon dioxide is the mostimportant, because of its abundance and effec-tive lifetime in the atmosphere of about 100 years.

50387schD01R1 11/29/01 5:24 AM Page 47

Measuring and Modeling Climate ChangeIPCC scientists believe that we are already expe-riencing an enhanced greenhouse effect.According to their findings, the Earth’s globalaverage surface temperature increased by about0.6°C [1.1°F] during the last century. They main-tain that this increase is greater than can beexplained by natural climatic variations. Thepanel believes there is only a 1 to 10% probabil-ity that inherent variability alone accounts for thisextent of warming. Most studies suggest that,over the past 50 years, the estimated rate andmagnitude of warming due to increasing concen-trations of greenhouse gases alone are compara-ble to, or larger than, the observed warming.7

To better understand the physical, chemicaland biological processes involved, scientistsinvestigating climate variations construct complexmathematical models of the Earth’s weather sys-tem. These models are then used to simulate pastchanges and predict future variations. The moreclosely that simulations match historical climaterecords built from direct observations, the moreconfident scientists become in their predictivecapabilities (left).

Greater emphasis on diagnosing and predict-ing the impact of global warming has resulted inincreasingly sophisticated simulations. For exam-ple, a state-of-the-art, three-dimensional (3D)ocean-atmosphere model developed at theHadley Centre for Climate Prediction andResearch in Berkshire, England, appears to repli-cate—with reasonable precision—the evolutionof global climate during the late 19th and 20thcenturies. This simulation matches records thatclearly show that the global mean surface airtemperature has increased by 0.6°C ± 0.2°C[1.1°F ± 0.4°F] since 1860, but that the progres-sion has not been steady. Most of the warmingoccurred in two distinct periods—from 1910 to1945, and since 1976—with little change in theintervening three decades.

When factors that impact the Earth’s climatevary—concentrations of greenhouse gases, butalso heat output from the sun, for example—they exert a ‘forcing’ on climate (see “Increasesin Greenhouse Forcing,” next page). A positiveforcing causes warming, a negative one resultsin cooling. When researchers at the HadleyCentre and the Rutherford Appleton Laboratory,near Oxford, England, simulated the evolution of 20th century climate, they concluded that, by themselves, natural forcings—changes in volcanic aerosols, solar output and other phenomena—could not account for warming

48 Oilfield Review

Update and refine model

Comparison and

validation

Climate-system model

Computersimulation

Predictedbehavior

Observedbehavior

> Climate simulations. Scientists use sophisticated models and computer sim-ulations of the Earth’s climate system to confirm historical, and predict future,temperature changes. Results are validated by comparison with actual tem-perature measurements. Such analyses form a basis for updating and refiningthe reliability of simulations.

1.0ModelObservations

0.5

0.0

–0.5

–1.01850 1900

Tem

pera

ture

ano

mal

ies,

C

Tem

pera

ture

ano

mal

ies,

C

Natural factors only

1950 2000

1.0ModelObservations

ModelObservations

0.5

0.0

–0.5

–1.01850 1900

Human factors only

1950 2000

1.0

0.5

0.0

–0.5

–1.01850 1900

Human and natural factors

1950 2000

> Observed and simulated global warming. Neither natural nor man-made effects alone account forthe evolution of the Earth’s climate during the 20th century. By combining the two, however, theobserved pattern is reproduced with reasonable accuracy.

50387schD01R1 11/29/01 5:24 AM Page 48

Autumn 2001

in recent decades. They also concluded thatanthropogenic, or man-made, forcings alonewere insufficient to explain the warming from1910 to 1945, but were necessary to reproducethe warming since 1976. However, by combiningthe two simulations, researchers were able toreproduce the pattern of temperature changewith reasonable accuracy. Agreement betweenobserved and simulated temperature variationssupports the contention that 20th century warm-ing resulted from a combination of natural andexternal factors (previous page, bottom).8

In addition to examining the global mean tem-perature, researchers at the Hadley Centre also

compared geographic patterns of temperaturechange across the surface of the earth. Theyused models to simulate climate variationsdriven by changes in greenhouse-gas concentra-tions and compared the ‘fingerprint’ producedwith patterns of change that emerge from obser-vation. Striking similarities are evident betweenthe fingerprint generated by a simulation of thelast 100 years of temperature changes and thepatterns actually observed over that period (above).

Despite many advances, climate modelingremains an inexact science. There is concernthat, at present, simulations may not adequatelyrepresent certain feedback mechanisms, espe-cially those involving clouds. Researchers, like

those at Hadley, do not claim that close agree-ment between observed and simulated tempera-ture changes implies a perfect climatic model,but if today’s sophisticated simulations of climate-change patterns continue to closelymatch observations, scientists will rely to agreater extent on their predictive capabilities.

7. Reference 1: 10.8. Stott PA, Tett SFB, Jones GS, Allen MR, Mitchell JFB

and Jenkins GJ: “External Control of 20th CenturyTemperature by Natural and Anthropogenic Forcings,”Science 290, no. 5499 (December 15, 2000): 2133-2137.

90˚ N

45˚ N

90˚ S

45˚ S

90˚ NSimulated

Observed

45˚ N

90˚ S

45˚ S

90˚ W 0˚ 90˚ E 180˚ E

–0.5 0.5 1 1.5 20–1

90˚ W 0˚ 90˚ E 180˚ E

180˚ W

180˚ W

–0.5 0.5 1 1.5 20–1

> Observed (top) and simulated (bottom) surface air temperature changes.Computer models closely resemble the global temperature signature pro-duced by measurements of the change in air temperature. Values increasefrom negative to positive as the color scale moves from blue to red.

Increases in Greenhouse Forcing

Early this year, scientists at the ImperialCollege of Science, Technology and Medicine inLondon, England, provided the first experimen-tal observation of a change in the greenhouseeffect. Previous studies had been largely limitedto theoretical simulations.1 Changes in theEarth’s greenhouse effect can be detected fromvariations in the spectrum of outgoing long-wavelength radiation, a measure of how theearth gives off heat into space that also carriesan imprint of the gases responsible for thegreenhouse effect.

From October 1996 until July 1997, an instru-ment on board the Japanese ADEOS satellitemeasured the spectra of long-wavelength radia-tion leaving the earth. The Imperial Collegegroup compared the ADEOS data with dataobtained 27 years earlier by a similar instru-ment aboard the National Aeronautics andSpace Administration (NASA) Nimbus 4meteorological satellite. The comparison of thetwo sets of clear-sky infrared spectra provideddirect evidence of a significant increase in theatmospheric levels of methane, carbon dioxide,ozone and chlorofluorocarbons since 1970.Simulations show that these increases areresponsible for the observed spectra.

1. Harries JE, Brindley HE, Sagoo PJ and Bantges RJ:“Increases in Greenhouse Forcing Inferred from theOutgoing Longwave Radiation Spectra of the Earth in1970 and 1997,” Nature 410, no. 6832 (March 15, 2001):355-357.

49

50387schD01R1 11/29/01 5:25 AM Page 49

The Opposing View Not all scientists accept the IPCC findings. Many distinguished researchers argue that thepanel’s approach is too simplistic. For instance,Dr Richard Lindzen, Alfred P. Sloan Professor ofMeteorology at the Massachusetts Institute ofTechnology (MIT) in Cambridge, USA, suggeststhat clouds over the tropics act as an effectivethermostat and that any future warming becauseof increased carbon dioxide concentration in theatmosphere could be significantly less than cur-rent models predict.

Scientists have voiced strong objections thateven sophisticated circulation models do notadequately describe the complexity of the mech-anisms at work. A group of researchers at theHarvard-Smithsonian Center for Astrophysics inCambridge, Massachusetts, for example, claimsthere are too many unknowns and uncertaintiesin climate modeling to have confidence in theaccuracy of today’s predictions. The group arguesthat even if society had complete control over how much CO2 was introduced into the atmosphere, other variables within the climatesystem are not sufficiently well-defined to pro-duce reliable forecasts. The researchers are nottrying to disprove a significant man-made contri-bution, but rather contend that scientists do notknow enough about the complexity of climatesystems, and should be careful in ascribing toomuch relevance to existing models.9

New scientific studies are shedding morelight on the problem. For example, previousinvestigations have concluded that the Earth’sclimate balance is upset not only by emissions ofman-made greenhouse gases during processessuch as the combustion of fossil fuels, but alsoby small particles called aerosols, such as thoseformed from sulfur dioxide, which cool the Earth’ssurface by bouncing sunlight back into space.But, new findings suggest that things may not bethat simple. A researcher at Stanford University,California, USA, states that black carbon, or soot,emissions from the burning of biomass and fossilfuels are interfering with the reflectivity ofaerosols, darkening their color so that theyabsorb more radiation. This reduces the coolingeffect, and could mean that black carbon is amajor cause of global warming, along with car-bon dioxide and other greenhouse gases.

50 Oilfield Review

9. Soon W, Baliunas S, Idso SB, Kondratyev KY andPostmentier ES: “Modelling Climatic Effects ofAnthropogenic Carbon Dioxide Emissions: Unknowns and Uncertainties.” A Center for Astrophysics preprint.Cambridge, Massachusetts, USA: Harvard-SmithsonianCenter for Astrophysics (January 10, 2001): to appear asa review paper in Climate Research.

10. Jacobson M: “Strong Radiative Heating due to theMixing State of Black Carbon in Atmospheric Aerosol,”Nature 409, no. 6821 (2001): 695-697.

11. Reference 1: 2-4.12. Reference 1: 12-13.13. Climate Change 2001: Impacts, Adaptation and

Vulnerability: Contribution of Working Group II to theThird Assessment Report of the IntergovernmentalPanel on Climate Change. New York, New York, USA:Cambridge University Press (2001): 5.

Atmospheric computer simulations usuallyassume that aerosols and soot particles are sep-arate, or externally mixed. An internally mixedstate—in which aerosols and soot coalesce—also exists, but no one has yet successfully deter-mined the relative proportions of the two states.The Stanford researcher ran a simulation inwhich black carbon was substantially coalescedwith aerosols. His results were more consistentwith observations than simulations that assumedmainly external mixing. Although this could meanthat black carbon is a significant contributor towarming, there is a bright side to the discovery.Unlike the extended lifetime of carbon dioxide,black carbon disappears much more rapidly. Ifsuch emissions were stopped, the atmospherewould be clear of black carbon in only a matter ofweeks (left).10

Radiation into space

Radiation into space

Radiation from Earth's

surface

Radiation from Earth's

surface

Coalesced state

Soot

Aerosol

Coalesced sootand aerosolconstituents

(internal mixing)

Separate sootand aerosolconstituents

(external mixing)

> Impact of aerosols and soot. Temperature simulations that take into account an internallymixed, or coalesced, accumulation of aerosolsand soot (right) are more consistent with obser-vations than separate, or externally mixed, accumulations (left).

Global-averagesurface temperature

change(1900 to 2000)

Results:

10% decrease in snow cover(since the late 1960s)

2-week shorter annual ice cover

0.1- to 0.2-m sea-level rise

0.5 to 1% increase in precipitation per decade (Northern Hemisphere)

+0.6 C

> Observed impact of global warming. The 0.6°C temperature rise observed during the last100 years has been postulated as the cause ofdecreased snow and ice cover, higher sea levelsand increased precipitation.

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Autumn 2001 51

Predicting the Future Impact of Global WarmingThe IPCC has described the current state of sci-entific understanding of the global climate sys-tem, and has suggested how this system mayevolve in the future. As discussed, the panel con-firmed that the global-average surface tempera-ture of the earth increased by about 0.6°C duringthe last 100 years. Analyses of proxy data fromthe Northern Hemisphere indicate that it is likelythe increase was the largest of any century in thepast millennium. Because of limited data, less isknown about annual averages prior to the year1000, and for conditions prevailing in most of theSouthern Hemisphere prior to 1861.

The IPCC report states that temperatureshave risen during the past four decades in thelowest 8 km [5 miles] of the atmosphere; snowcover has decreased by 10% since the late1960s; the annual period during which rivers andlakes are covered by ice is nearly two weeks

shorter than at the start of the century; and aver-age sea levels rose by 0.1 to 0.2 m [0.3 to 0.7 ft]during the 1900s. The report further states that,during the last century, precipitation increased by0.5 to 1% per decade over most middle and highlatitudes of Northern Hemisphere continents,and by 0.2 to 0.3% per decade over tropical landareas (previous page, bottom).11

While these changes may appear to be mod-est, predicted changes for this century are muchlarger. Simulations of future atmospheric levels ofgreenhouse gases and aerosols suggest that theconcentration of CO2 could rise to between 540and 970 ppm. For all scenarios considered by theIPCC, both global-average temperature and sealevel will rise by the year 2100—temperature by1.4°C to 5.8°C [2.5°F to 10.4°F] and sea level by0.09 to 0.9 m [0.3 to 2.7 ft]. The predicted tem-perature rise is significantly greater than the 1°Cto 3.5°C [1.8°F to 6.3°F] estimated by the IPCCfive years ago. Precipitation is also forecasted toincrease. Northern Hemisphere snow cover is

expected to decrease further, and both glaciersand ice caps are expected to continue to retreat.12

If climate changes occur as predicted, seriousconsequences could result, both with respect tonatural phenomena, such as hurricane frequencyand severity, and to human-support systems. TheIPCC Working Group II, which assessed impacts,adaptation and vulnerability, stated that if theworld continues to warm, we could expect watershortages in heavily populated areas, particularlyin subtropical regions; a widespread increase inthe risk of flooding as a result of heavier rainfalland rising sea levels; greater threats to healthfrom insect-borne diseases, such as malaria, andwater-borne diseases, such as cholera; anddecreased food supply as grain yields dropbecause of heat stress. Even minimal increases intemperature could cause problems in tropicallocations where some crops are already near theirmaximum temperature tolerance (above).13

Water shortages

Decreased food supply

Greater exposure to disease

Increase in frequency and intensity

of severe weather

Increased flooding

> Future impact of global warming. IPCC scientists predict a number of consequences if climate changestrack the latest simulations, ranging from water shortages to flooding and decreased food supply.

50387schD01R1 12/17/01 10:04 PM Page 51

Sea-level rises could threaten five parts ofAfrica that have large coastal population cen-ters—the Gulf of Guinea, Senegal, Gambia,Egypt and the southeastern African coast. Even asomewhat conservative scenario of a 40-cm[15.8-in.] sea-level rise by the 2080s would add75 to 200 million people to the number currentlyat risk of being flooded by coastal storm surges,with associated tens of billions of dollars in prop-erty loss per country.14

Africa, Latin America and the developingcountries of Asia may have a two-fold problem,being both more susceptible to the adverseeffects of climate change and lacking the infras-tructure to adjust to the potential social and economic impacts.

The IPCC Working Group II has ‘high confi-dence’ that:• Increases in droughts, floods and other

extreme events in Africa would add to stresseson water resources, food-supply security,human health and infrastructures, and con-strain further development.

• Sea-level rise and an increase in the intensityof tropical cyclones in temperate and tropicalAsia would displace tens of millions of peoplein low-lying coastal areas, while increasedrainfall intensity would heighten flood risks.

• Floods and droughts would become more frequent in Latin America, and flooding would increase sediment loads and degradewater quality.

The Working Group has ‘medium confidence’that:• Reductions in average annual rainfall, runoff

and soil moisture would increase the creationof deserts in Africa, especially in southern,northern and western Africa.

• Decreases in agricultural productivity andaquaculture due to thermal and water stress,sea-level rise, floods, droughts and tropicalcyclones would diminish the stability of foodsupplies in many countries in the arid, tropicaland temperate parts of Asia.

• Exposure to diseases such as malaria, dengue fever and cholera would increase inLatin America.15

Not all impacts would be negative, however.Among projected beneficial effects are highercrop yields in some mid-latitude regions; anincrease in global timber supply; increased wateravailability for people in some regions, like partsof Southeast Asia, which currently experiencewater shortages; and lower winter death rates inmid- to high-latitude countries.16

Other studies—such as the US GlobalResearch Program’s report “Climate ChangeImpacts on the United States,” and the EuropeanCommunity-funded ACACIA (A Consortium forthe Application of Climate Impact Assessments)Project report—are consistent with future IPCCforecasts, and provide a more detailed picture forparticular regions.

According to the US study, assuming there areno major interventions to reduce continued growthof world greenhouse-gas emissions, temperaturesin the USA can be expected to rise by about 3°C to5°C [5.4°F to 9°F] over the next 100 years, com-pared with the worldwide range of 1.4°C to 5.8°C[2.5°F to 10.4°F] suggested by the IPCC.17

Assuming there are no major interventions,other predictions include the following:• Rising sea levels could put coastal areas at

greater risk of storm surges, particularly in thesoutheast USA.

• Large increases in the heat index, the combi-nation of temperature and humidity, and in thefrequency of heat waves could occur, particu-larly in major metropolitan cities.

• Continued thawing of permafrost and meltingof sea ice in Alaska could further damageforests, buildings, roads and coastlines.

In Europe, negative climate changes areexpected to impact the south more than thenorth. Sectors such as agriculture and forestry

will be affected to a greater extent than sectorssuch as manufacturing and retailing, andmarginal and poorer regions will suffer moreadverse effects than wealthy ones.

The ACACIA report, which provided the basisfor the IPCC findings on impacts in Europe, makesthe following predictions for southern Europe: • Longer, hotter summers will double in fre-

quency by 2020, with a five-fold increase insouthern Spain, increasing the demand for air conditioning.

• Available water volumes will decrease by 25%,reducing agricultural potential. Careful plan-ning will be essential to satisfy future urbanwater needs.

• Desertification and forest fires will increase.• Deteriorating air quality in cities and excessive

temperatures at beaches could reduce recre-ational use and associated tourist income.

Predictions for northern Europe include thefollowing:• Cold winters will be half as frequent by 2020.• Northern tundra will retreat and there could be

a loss of up to 90% of alpine glaciers by theend of the century.

• Conversely, climate changes could increaseagricultural and forest productivity and wateravailability, although the risk of flooding couldincrease (above).18

52 Oilfield Review

Rising sea levelsHigher heat index

Droughts Floods Decreased food supply Expanding deserts Sea-level rise

Hotter summers Reduced water supply Increase in forest fires Deteriorating air quality

Floods Increased rainfall Intense cyclones Decreased food supply

Floods Droughts Degraded water quality

Retreating glaciers Thawing of permafrost Melting of sea ice

> Impact of global warming by region. All continents will be affected significantly if global warmingcontinues. The type and severity of specific impacts will vary, as will each continent’s or country’scapacity to use infrastructure and technology to cope with change.

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Autumn 2001 53

The Sociopolitical Debate and Its Impacton Process and TechnologyOn balance, the potential dangers and adverseeffects of global warming far outweigh any pos-sible benefits. Both legislative and technicaloptions are being explored to mitigate theimpacts of future climate change.

With its 100-year effective lifetime, CO2 con-centration in the atmosphere is slow to respondto any cut in emissions. If nothing is done toreduce emissions, the concentration would morethan double over the next century. If emissionsare lowered to 1990 levels, the concentrationwould still rise, probably to more than 500 ppm.Even if emissions were slashed to half that leveland held there for 100 years, there would still bea slow rise in concentration. Best estimates sug-gest it would take a reduction of 60 to 70% of the1990 emission levels to stabilize the concentra-tion of CO2 at the 1990 levels.19

Against this backdrop, there have been polit-ical attempts to grapple with the problem fornearly a decade. These have achieved, at best,modest results. Although an in-depth discussionof global-warming politics is beyond the scope ofthis technically focused article, conferences heldto date and their resulting protocols illustrate thechallenges that will be faced by new-generationoilfield processes and technologies, and by busi-ness and industry in general (above).

The political movement toward global con-sensus began in 1992 at the United NationsConference on Environment and Developmentheld in Rio de Janeiro, Brazil. This conferenceresulted in the United Nations FrameworkConvention on Climate Change (UNFCCC), astatement of intent on the control of greenhouse-gas emissions, signed by an overwhelmingmajority of world leaders. Article II of the con-vention, which came into force in 1994, said thesignatories had agreed to “achieve stabilizationof greenhouse-gas concentrations in the atmo-sphere at a level that would prevent dangerousanthropogenic interference with the climate sys-tem…within a time frame sufficient to allowecosystems to adapt naturally to climate change,to ensure that food production is not threatened,and to enable economic development to proceedin a sustainable manner.” The developed nationstaking part also committed themselves to reducetheir emissions of greenhouse gases in the year2000 to 1990 levels.

A more ambitious target was set in 1997 inthe Kyoto Protocol, an agreement designed to

commit the world’s 38 richest nations to reducetheir greenhouse-gas emissions by an average ofat least 5% below 1990 levels in the period from2008 to 2012.20 The Kyoto Protocol put most ofthe burden on developed countries, which, as agroup, had been responsible for the majority of greenhouse gases in the atmosphere. Itexcluded more than 130 developing countries,even though many poorer nations were adding tothe problem in their rush to catch up with thedeveloped world. European Union (EU) countriesagreed to a reduction of 8%, and the USApromised a 7% cutback, based on 1990 levels. Totake effect, it was agreed that the Protocol mustbe ratified by at least 55 countries, includingthose responsible for at least 55% of 1990 CO2

emissions from developed countries.The targets set in Kyoto are more rigorous

than they might first appear since many devel-oped economies have, until very recently, beengrowing rapidly and are emitting greater volumesof greenhouse gases. In 1998, for example, theUS Department of Energy forecasted that USemissions in the year 2010 would exceed theKyoto target by 43%.

The November 2000 talks in The Hague onimplementing the Kyoto Protocol collapsed whenthe EU rejected a request that the estimated310 million tons of CO2 soaked up by forests inthe USA be set against its 7% commitment. TheEU suggested instead that the USA be allocateda 7.5-million ton offset.

In July 2001, 180 members of the UNFCCCfinally reached broad agreement on an opera-tional rulebook for the Kyoto Protocol at a meet-ing in Bonn, Germany. The USA rejected theagreement. If the Protocol is to go forward, thenext step would be for developed-country

governments to ratify it so that measures couldbe brought into force as soon as possible, possi-bly by 2002.

One issue resolved at the Bonn meeting washow much credit developed countries couldreceive towards their Kyoto targets through theuse of ‘sinks’ that absorb carbon from the atmo-sphere. There was agreement that activities thatcould be included under this heading includedrevegetation and management of forests, crop-lands and grazing lands. Individual country quotaswere set so that, in practice, sinks will accountonly for a fraction of the emission reductions thatcan be counted towards the target levels.Similarly, storage options exist for carbon dioxidethat offer attractive alternatives to sinks undercertain conditions (see “Mitigating the Impact ofCarbon Dioxide: Sinks and Storage,” page 54).The conference also adopted rules governing theso-called Clean Development Mechanism (CDM)through which developed countries can invest inclimate-friendly projects in developing countriesand receive credit for emissions thereby avoided.

Conference

_____

Outcome

1992

Rio de Janeiro,Brazil

_________

Statement of intent on controlof greenhouse

gases

1997

Kyoto,Japan

_________

Protocol onreduction levels

for specific commitment

period

2000

The Hague,The Netherlands

_________

Collapse ofimplementationplan for Kyoto

Protocol

2001

Bonn,Germany

_________

Broad agreement on rulebook

for implementing Kyoto protocol(except USA)

> Major international global warming conferences. A concerted effort ataddressing the sociopolitical implications of global warming in a forum ofnations began in 1992 in Rio de Janeiro, Brazil. The most recent conference,held in July 2001 in Bonn, Germany, was the latest attempt to reach sometype of formalized agreement on reducing greenhouse-gas emissions.

14. Reference 13: 13-14.15. Reference 13: 14-15.16. Reference 13: 6.17. Climate Change Impacts on the United States, The

Potential Consequences of Climate Variability andChange: Foundation Report, US Global Change ResearchProgram Staff. New York, New York, USA: CambridgeUniversity Press (2001): 6-10.

18. Parry ML (ed): Assessment of Potential Effects andAdaptations for Climate Change in Europe. Norwich,England: Jackson Environment Institute, University ofEast Anglia, 2000.

19. Jenkins et al, reference 3: 10.20. Kyoto Protocol, Article 31, available at Web site:

http://www.unfccc.de/resource/docs/convkp/kpeng.html

(continued on page 56)

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54 Oilfield Review

In the short to medium term, the world will continue to depend upon fossil fuels as cheapenergy sources, so there is growing interest inmethods to control carbon dioxide emissions—for example, the creation of carbon sinks andstorage in natural reservoirs underground or inthe oceans.1

Carbon sinks—Carbon sinks are newlyplanted forests where trees take CO2 from theatmosphere as they grow and store it in theirbranches, trunks and roots. If too much CO2 isbeing pumped into the atmosphere by burningfossil fuels, discharge levels can be compen-sated for, to some extent, by planting new treesthat soak up and store CO2.

In 1995, the IPCC estimated that some345 million hectares [852 million acres] of newforests could be planted between 1995 and 2050that would sequester nearly 38 gigatons of car-bon. These actions would offset about 7.5% offossil-fuel emissions. The IPCC added that othermeasures, like slowing tropical deforestation,could sequester another 20 to 50 gigatons.Taken together, new forests, agroforestry, regen-eration and slower deforestation might offset 12to 15% of fossil-fuel emissions by the year 2050.An attractive feature of this approach is that, ifimplemented globally, it buys time during whichlonger term solutions can be sought to meetworld energy needs without endangering the climate system.

There are, however, other factors that mustbe considered, such as how to quantify theamount of carbon being sequestered, how toverify sequestration claims and how to deal with‘leakage.’ Leakage occurs when actions toincrease carbon storage in one place promoteactivities elsewhere that cause either adecrease in carbon storage (negative leak) or an increase in carbon storage (positive leak).Preserving a forest for carbon storage may, forinstance, produce deforestation elsewhere (neg-ative leakage) or stimulate tree planting else-where to provide timber (positive leakage). Thecarbon-sink process is reversible. At somefuture date, some forests could become unsus-tainable, leading to a rise in CO2 levels.

Carbon storage—Carbon dioxide is producedas a by-product in many industrial processes,

usually in combination with other gases. If theCO2 can be separated from the other gases—atpresent, an expensive process—it can be storedrather than released to the atmosphere. Storagecould be provided in the oceans, deep salineaquifers, depleted oil and gas reservoirs, or onland as a solid. Oceans probably have the great-est potential storage capacity. While there are no real engineering obstacles to overcome, the environmental implications are not ade-quately understood.

For years, carbon dioxide has been injectedinto operating oil fields to enhance recovery,and normally remains in the formation. The useof depleted oil or gas reservoirs for CO2 storage,however, has a further advantage in that thegeology is well-known, so disposal takes place inareas where formation seals can contain the gas.

The first commercial-scale storage of CO2 inan aquifer began in 1996 in the Sleipner naturalgas field belonging to the Norwegian oil com-pany Statoil. The project is named SACS (SalineAquifer CO2 Storage) and is sponsored by theEU research program Thermie. A million tons, a year of CO2 production, are removed from thenatural gas stream using a solvent-absorptionprocess and then reinjected into the Utsirareservoir, 900 m [2950 ft] below the floor of the North Sea (above). According to a report bythe Norwegian Ministry of Petroleum andEnergy, the Utsira formation is widespread and about 200 m [660 ft] thick, so it can theo-retically accommodate 800 billion tons of CO2—equivalent to the emissions from allnorthern European power stations and majorindustrial establishments for centuries to come(next page, bottom).

Mitigating the Impact of Carbon Dioxide: Sinks and Storage

NORWAY

DENMARK

GERMANY

UNITED KINGDOM

NORTH SEA

Stavanger

Statfjord

Gullfaks

Frigg

Heimdal

Ula

Ekofisk

Sleipner

Sleipner West

Sleipner East

> Sleipner field location.

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Autumn 2001 55

To monitor the CO2-injection area,Schlumberger is conducting four-dimensional(4D), or time-lapse, seismic studies that com-pare seismic surveys performed before and dur-ing injection. A survey acquired in 1994, twoyears before injection began, served as the base-line for comparison with a 1999 survey acquiredafter about 2 million tons of CO2 had beeninjected. Higher seismic amplitudes in the 1999survey show the location where gas has dis-placed brine in the Utsira formation. Another4D survey is scheduled for late 2001 (right).

The Sleipner CO2 sequestration projectalready has inspired other oil and gas compa-nies to consider or plan similar efforts in south-east Asia, Australia and Alaska.

1. Cannell M: Outlook on Agriculture 28, no. 3: 171-177.

Depth, m

Sleipner T Sleipner A

CO2 injection well

Utsira formation

Heimdal formation

CO2

0

500

1000

1500

2000

2500

0

0 1640 3280 4920 ft

500 1000 1500 m

Sleipner East productionand injection wells

> Carbon dioxide injection well in Utsira. The Utsira formation is about 200 m [660 ft] thick and can hold the equivalent of all carbon dioxide emissionsfrom all northern European power stations and industrial facilities for centuries to come.

1994 1999

Sleipner CO2 injection siesmic monitoring E-W section preliminary raw stack

after injecting 2 millIon tons of CO2 since 1996no change above this level

Velocity push-down beneath CO2 cloud

–250 m

Injection point

Top Utsira formation

500 m

> Seismic responses due to carbon dioxide injection. A 1994 seismic survey (left)served as a baseline for a 1999 survey (right) that showed the pattern of brinedisplacement by carbon dioxide following injection of 2 million tons of the gas.

50387schD01R1 11/29/01 5:21 AM Page 55

The Kyoto Protocol includes a compliancemechanism. For every ton of gas that a countryemits over its target, it will be required to reducean additional 1.3 tons during the Protocol’s sec-ond commitment period, which starts in 2013.Some reports contend that concessions made atthe conference reduced emissions cuts requiredby the Protocol from 5.2% to between 0 and 3%in 2010. The UNFCCC is more cautious in itsstatements. As of August of this year, its secre-tariat had not calculated how the Bonn agree-ments might affect developed-country emissionreductions under the Kyoto Protocol, and indi-cated that this would not be known with any pre-cision until the 2008-2012 target period.

E&P Company InitiativesToday, many oil and gas companies are takingglobal warming seriously, convinced that it is sen-sible to adopt a precautionary approach. Othershave taken a more conservative stance: theyagree that climate change may pose a legitimatelong-term risk, but argue that there is still insuffi-cient scientific understanding to make reasonablepredictions and informed decisions, or to justifydrastic measures. All agree that a combination ofprocess changes and advanced technologies willbe required within the industry to meet the typesof emission standards being proposed.

BP and Shell have implemented strategiesbased on a judgment that while the science ofclimate change is not yet fully proven, it is pru-dent to behave as though it was. Both companieshave established ambitious internal targets forreduction of their own emissions. The KyotoProtocol calls for an overall reduction of green-house-gas emissions of at least 5% by 2008 to2012, compared with 1990. BP has undertaken to

reduce its greenhouse-gas emissions by 10% bythe year 2010, against the 1990 baseline. Shellintends to reduce emissions by 10%, against thesame baseline, by 2002.

Companies are choosing to cut emissions inseveral different ways. The BP emissions reduc-tion program, for instance, includes ambitiouscommitments:• Ensure that nothing escapes into the environ-

ment that can be captured and, ideally, usedelsewhere. BP intends to stop the deliberateventing of methane and carbon dioxide wher-ever possible. This may involve redesigning orreplacing equipment, and identifying and elim-inating leaks.

• Improve energy efficiency. Engineers are exam-ining all energy-generating equipment toensure that the company is making the bestpossible use of hydrocarbon fuels and the heatthat is a by-product of energy generation.

• Eliminate routine flaring. It is better to flare gasthan vent it directly to the atmosphere, but it is still a waste of hydrocarbons—althoughsome flaring may still be necessary for safety reasons.

• Develop technology to separate carbon dioxidefrom gas mixtures, then reuse it for enhancedoil recovery or store it in oil and gas reservoirsthat are no longer in use, or in saline forma-tions (above).

Integrated oil companies also are trying tohelp customers reduce greenhouse-gas emissionsby increasing the availability of fuels with lowercarbon content and offering renewable energyalternatives, like solar and wind-driven power.

Some companies, including BP and Shell,have introduced internal greenhouse-gas emis-sions trading systems. The attraction of emissionstrading is that it allows reductions to be achievedat the lowest cost; companies for whom emis-sions reductions are cheap can lower their

emissions and sell emission rights to firms thatwould have to pay more to decrease emissions.

The BP emissions trading system is based ona cap-and-trade concept, and was primarilydesigned to provide BP with practical experiencedealing with an emissions trading market and tolearn about its complexities. At its simplest level,a cap is set each year to steer the group towardthe most efficient use of capital to meet its 2010target of 10%. Say, for example, increased pro-duction is planned from an offshore platform,thereby causing emissions above its allocatedallowance. If the platform’s on-site abatementcosts are higher than the market price of CO2, thecompany may decide to purchase CO2

allowances for that unit. Similarly, if a down-stream unit has upgraded its refinery and emitsless CO2 than its allowances cover, it is econom-ically desirable to both companies if the lattersells its allowances to the former (below).

The operation of these systems will beclosely followed not only by other oil and gascompanies but also by governments, since theprinciples behind emissions trading are broadlythe same whether trading takes place within asingle company, among companies within a sin-gle country, among companies internationally orbetween nations.

Oilfield Technology Development and ApplicationWorking with oil and gas companies, major oil-field service suppliers have been at the forefrontin addressing a range of health, safety and envi-ronmental issues—from reducing personnelexposure to risks at the wellsite, to application of‘green’ chemicals that provide equal or enhancedperformance while decreasing ecological impact,and to methods for cutting or eliminating emis-sions resulting from processes such as burningoil and flaring gas during well-testing operations.

56 Oilfield Review

BP Emissions-Reduction Program_________

Capture and reuse emissions.

Stop deliberate venting of carbon dioxide and methane.

Improve energy efficiency.

Eliminate routine flaring.

Develop technologies to separate carbon dioxide from gas mixtures.

> Cutting emission levels. BP has undertaken anaggressive, multifaceted program to reduceemissions, ranging from improved energy effi-ciency to elimination of routine gas flaring.

Company A Company B

Each companyinitially is

allocated 50 permits to emit

50 tons

Units sold

Units boughtEmission limit before trading

Emission limit after trading

Carb

on d

ioxi

de e

mis

sion

s

–10

40 50

+10

> Emissions trading system. This process strives to reduce emissions at thelowest cost by permitting the buying and selling of emissions rights betweenvarious units within a given company or between companies.

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Autumn 2001 57

Solutions to eliminate flaring—Burning oiland flaring natural gas during testing operationsnot only are costly due to lost revenue, but alsoproduce large quantities of carbon dioxide. Smallamounts of toxic gases, soot and unburnedhydrocarbons are also released. Eliminating oilburning and, ultimately, gas flaring not only cre-ates a safer working environment, but also helpsreduce the key constituent, carbon dioxide,thought to be associated with global warming.

Recently, a Schlumberger team in the MiddleEast, working closely with a major operator in theregion, addressed the flaring problem for produc-tion testing where an existing export pipelinewas available. Considering the nature of the test-ing program, there were several key challengesthat had to be overcome. Wells are typicallyhighly deviated or horizontal, and penetrate mas-sive carbonate formations. Large quantities ofacid are used to treat the zones, giving rise tolong cleanup periods and an erratic initial flow ofmixtures of spent acid, emulsions, oil and gas.

Traditionally, the wells were flowed until suffi-cient oil was produced at sufficient pressure togo directly into the production pipeline, requiringburning of oil in the interim. Care had to be takenthat the fluid’s pH was high enough so as not tocause corrosion problems.

A three-stage program to eliminate flaringand simultaneously solve associated well-testingproblems was undertaken. In the first stage,beginning in 1998, the goal was to pump sepa-rated oil into the pipeline from the outset,instead of burning it. This required the design ofspecialized, dual-packing centrifugal pumps thatwere run in series to achieve the required pres-sure for oil injection into the pipeline. Naturalgas was still flared, and separated water dis-carded. Residual oil and water emulsionsremained a problem, since a single separatorwas insufficient to break them.

In the second stage of the project, a neutral-izer and breaker system was designed for treat-ment of the emulsion phase prior to entering the

main separator. Remaining gas and oil were thenflowed through the separator. A skimmer andchemical injection system were employed toreduce the oil content in the water underflowstream from 3000 ppm to less than 80 ppm,allowing safe disposal of all residual water. Oilproduced through emulsion breaking waspumped into a surge tank and then into the pro-duction pipeline, saving additional oil that wouldhave otherwise been discarded.

In the third stage, currently under way, thegoal is for complete elimination of flaring byusing advanced multiphase pumping technologywith multiphase metering. When the wellheadpressure is insufficient to route gas back throughthe line after the multiphase meter, a variable-drive multiphase pump—that can handle a vari-ety of flow rates and pressures—would beintroduced so that both oil and gas can beinjected into the production pipeline (above).

Gas

Oil

Water and oil emulsion

Series of pumps

Series of pumps

Produced fluidPipeline

Flaring

Separator

Disposal

Gas

Pipeline

Flaring

Skimmer

SeparatorProduced fluid

Stag

e 1

Stag

e 2

Stag

e 3

Gas and oilNeutralizer and emulsion breaker

Neutralizer and emulsion breaker

Broken emulsion

Broken emulsion

Oil

Oil

Oil

Clean water

Clean water

Disposal

Surge tank

Pipeline

Skimmer

Produced fluid Gas and oil Gas and oil

Disposal

Surge tank

Multiphase flowmeter Multiphase pump

> Three-stage program to eliminate flaring. A Schlumberger team in the Middle East committed to first reduce and then fully eliminate flaring of gas andburning of oil and, at the same time, generate greater revenue for the operator by increasing pipeline throughput.

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In the first year of implementation of the initialstages of the project, the operator was able to sellan additional 375,000 barrels [59,600 m3] of oilthat otherwise would have been burned, generat-ing more than $11 million in increased revenues.21

Zero-emission testing—The next frontier is ageneralized solution for zero-emission testing forexploration and appraisal wells where an exportpipeline is not available. Here, the challenge is totake a quantum step beyond improved burnertechnology. The goal is elimination of all emis-sions by keeping produced hydrocarbons con-tained either below surface or the mudline, or inspecial offshore storage vessels. Through the useof advanced downhole measurements and tools,high-quality test data and samples could still be captured.

There are several approaches to downholecontainment. In particular, three options are

currently undergoing intensive investigation. Thefirst is closed-chamber testing. Here, test fluidsflow from the formation into an enclosed portionof a tool or pipestring. A short flow period isachieved as the chamber fills and its original con-tents become compressed. Flow stops as thechamber reaches equilibrium, allowing analysisof the subsequent buildup. This method, applica-ble to both oil and gas wells, is simple, and theshort test duration limits rig time compared witha conventional test. But, there are drawbacks.With only a small flowed volume due to capacitylimitations of the test string or wellbore, only alimited radius of investigation near the wellborecan be evaluated. Lack of thorough cleanup afterperforating can potentially affect the quality ofcollected samples. If the formation is not well-consolidated, hole damage or collapse may occurbecause of high inflow rates (below left).

A second method is production from one zoneand reinjection into the same zone, known asharmonic testing. Here, fluid is alternately with-drawn into a test string and then pumped backinto the reservoir at a given periodic frequency.The reservoir signature is determined point-by-point as a function of frequency by varying thefrequency during testing. The advantage is that a

58 Oilfield Review

Pressure gauge

Packer

Produced fluid and initial liquid cushion

Gas-liquid interface

Test valve

Surface valve

> Closed-chamber testing. Test fluids from theformation enter an enclosed space until the con-tents compress and reach equilibrium. This briefflow period is then followed by a second stage ofpressure buildup.

Tubing

Circulating valve

Barrier valve

Upper packer

Circulating valve

Ball valve

Downholepump assembly

Lower packer

Sand screen and gravel pack

Flow direction

> Continuous production and reinjection. A spe-cially designed tool allows produced fluid fromone zone to be continuously injected into anotherusing a downhole pump to provide a prolongedtesting period. Samples can be retrieved, andflow and pressure data are measured downholefor subsequent analysis.

21. The team that spearheaded this project won thePerformed by Schlumberger Chairman’s Award 2000, the top award in a company-wide program to strengthenthe Schlumberger culture of excellence. Client teammembers included Abdullah Faddaq, Suishi Kikuchi,Mahmoud Hassan, Eyad Al-Assi, Jean Cabillic, Graham Beadie, Ameer El-Messiri and Simon Cossy.Schlumberger team members included Jean-FrancoisPithon, Abdul Hameed Mohsen, Mansour Shaheen,Thomas F. Wilson, Nashat Mohammed, Aouni El Sadek,Karim Mohi El Din Malash, Akram Arawi, Jamal AlNajjar, Basem Al Ashab, Mohammed Eyad Allouch,Jacob Kurien, Alp Tengirsek, Mohamed Gamad andThomas Koshy.

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separate zone for disposal of the produced fluidis not needed, but defining the pressure-responsecurve would require more time than for a con-ventional test and may not be cost-effective.Advanced signal processing may be able toreduce the time required, but still may not makethe process economically viable.

The third method is to continually producefrom one zone and inject the produced fluid intoanother zone. Reservoir fluids are never broughtto surface, but are reinjected using a downholepump. Drawdown is achieved by pumping fromthe production zone into the disposal zone.Buildup is provided by simultaneously shutting inthe production zone and stopping the downholepump. If injectivity can be maintained, this con-tinuous process emulates a full-scale well test. Alarger radius of investigation is possible due tolarger flow volumes, with the potential to inves-tigate compartmentalization or even reservoirlimits. A longer flow period improves cleanupprior to sampling. Flow and pressure are mea-sured downhole and analyzed with conventionalmethods for radial flow. It is possible to capturesmall pressure-volume-temperature (PVT)-qualitysamples and larger dead-oil samples downhole.Drawbacks include a somewhat complex toolstring, an inability to handle significant quantitiesof gas and no time-saving over a conventionalwell test. The key factor is having a suitableinjection zone that provides sufficient isolation(previous page, bottom right).

Two joint industry programs have been estab-lished to investigate each of the three methods indetail, with participation by BP, Chevron, NorskHydro and Schlumberger. The first, conducted bySchlumberger, is assessing downhole tool design

and capability requirements. The second, a three-year program at Imperial College in London,England, is defining the interpretation packagesand procedures that would be required to capturethe maximum amount of reliable informationfrom the data.

Once the selection of the preferred method isfinalized, the next step will be a proof-of-conceptfield experiment that mirrors the requirements ofa variety of well-test conditions. Currently, thecontinuous production-reinjection option looksmost promising.

Modules mounted on the deck or in the holdof a suitable floating vessel are being investi-gated for storing fluids collected offshore duringtesting. Fluid-processing facilities also would beprovided onboard. Large discoveries, marginalfields and deepwater prospects are targetedapplications. Equipment would be designed tohandle a broad range of testing conditions anddurations. The vessel would receive and storegas and liquids, and offload the contents at theend of the well test or at intervals during the test.This concept could completely eliminate the needfor flaring, and generate revenues from sale ofproduced fluids that would otherwise be lost. Theprocedures for handling and storing liquids havealready been successfully demonstrated inextended well tests in fields such as BP’sMachar—proving both the feasibility and finan-cial viability of the approach. Gas handling andstorage, however, pose additional challengesthat would probably require compression and transfer facilities to create compressed natural gas. This is a costly proposition and may not be economically viable at current gas prices (above).

With growing emphasis on eliminating alltypes of gas emissions, particularly carbon diox-ide, these areas of investigation are expected tocontinue to receive close attention and signifi-cant industry funding.

Future ChallengesIn the near future, governments around the worldwill receive the IPCC Synthesis Report which willattempt to answer, as clearly and simply as pos-sible, 10 policy-relevant scientific questions.Perhaps the pivotal question, as stated by theIPCC, is: “How does the extent and timing of theintroduction of a range of emissions-reductionactions determine and affect the rate, magnitudeand impacts of climate change, and affect globaland regional economies, taking into account his-torical and current emissions?”

In another five years, the IPCC is expected topublish its Fourth Assessment Report. By then,climatologists may have resolved some of theuncertainties that limit today’s climate models.They should, for example, be able to provide abetter description of the many feedback systemsassociated with climatic phenomena, particularlyclouds. Greater understanding could lead toreduced uncertainty about a causal connectionbetween increased greenhouse-gas concentra-tions and global warming. This would be a majorstep forward.

In the interim, oil and gas companies, working closely with oilfield service companies,will continue to be proactive in developing technologies and operational procedures forreducing emissions. —MB/DEO

Storage modules andprocessing facilities

Drilling andproduction unit

Export flowline

Dynamically positionedstorage or shuttle tanker

Rigid productionriser

BOP or subseatest tree

> Offshore storage-module concept. A vessel for storing and offloading fluids collected in closed modules during testing operations might offer an approach to eliminate the need for flaring while generating increased revenues.

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60 Oilfield Review

Isolate and Stimulate Individual Pay Zones

Kalon F. DegenhardtJack StevensonPT. Caltex IndonesiaRiau, Duri, Indonesia

Byron GaleTom Brown Inc.Denver, Colorado, USA

Duane GonzalezSamedan Oil CorporationHouston, Texas, USA

Scott HallTexaco Exploration and Production Inc. (a ChevronTexaco company)Denver, Colorado

Jack MarshOlympia Energy Inc.Calgary, Alberta, Canada

Warren ZemlakSugar Land, Texas

ClearFRAC, CoilFRAC, CT Express, DepthLOG, FMI (FullboreFormation MicroImager), Mojave, NODAL, PowerJet,PowerSTIM, PropNET, SCMT (Slim Cement Mapping Tool)and StimCADE are marks of Schlumberger.For help in preparation of this article, thanks to TarynFrenzel and Bernie Paoli, Englewood, Colorado; Badar ZiaMalik, Duri, Indonesia; and Eddie Martinez, Houston, Texas.

Coiled tubing-conveyed fracturing is a cost-effective alternative to conventional

reservoir-stimulation techniques. This innovative approach improves hydrocarbon

production rates and recovery factors by providing precise, reliable placement of

treatment fluids and proppants. What began as a fracturing service is evolving into

broad technical solutions for new completions, as well as workovers in mature fields.

Operators traditionally rely on drilling programs toachieve peak productivity, maintain desired pro-duction levels and optimize hydrocarbon recovery.As oil and gas developments mature, however,reservoir depletion reduces field output and feweropportunities exist to drill new wells. Drilling pro-grams alone may not effectively stem the naturaldecline of production. In addition, infill and reen-try drilling often become less profitable and pre-sent greater operational and economic risksrelative to their higher capital investments.

In many fields, operators intentionally andunintentionally bypass some pay zones duringinitial phases of field development by focusingonly on the most prolific producing horizons.Cumulatively, these marginal pay intervals con-tain substantial hydrocarbon volumes that can beproduced, especially from laminated formationsand low-permeability reservoirs. Accessingbypassed pay zones is economically attractive toenhance production and increase reserve recov-ery, but poses several challenges.

Typically, bypassed zones have lower perme-abilities and require fracturing treatments toachieve sustainable commercial production.Conventional well-intervention and stimulationmethods involve extensive remedial operations,such as mechanically isolating existing perfora-tions or squeezing them with cement and utiliz-ing multiple runs to perforate bypassed pay.

These procedures are expensive and cannot bejustified for zones with limited production poten-tial. In the past, fracture stimulations were notcommonly attempted on bypassed pay, especiallywhen multiple stringers were involved.

The mechanical condition of wellbores can bea limitation as well. If fracture stimulations are notanticipated during well planning, completion tubu-lars may not be designed to withstand high-pressure pumping operations. Also, scale buildupand corrosion from prolonged exposure to forma-tion fluids at reservoir temperatures and pressurescan compromise tubular integrity in older wells. Inslimhole wells, workover options are further lim-ited by small tubulars. These operational and eco-nomic constraints often mean that bypassed ormarginal pay remains untapped. Ultimately, hydro-carbons in these intervals are left behind whenwells are plugged and abandoned.

Integration of coiled tubing with fracturingoperations overcomes many of the constraintsassociated with stimulating bypassed ormarginal pay zones using conventional tech-niques, allowing additional reserves to be tappedeconomically. High-strength continuous coiledtubing strings transport treatment fluids andproppants to target intervals and protect existingwellbore tubulars from high-pressure pumpingoperations, while specialized downhole toolsselectively isolate existing perforations withincreased precision.

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> A fit-for-purpose CT Express coiled tubing unit performing a selective fracturing treatment in Medicine Hat, Alberta, Canada.

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This article describes operational and designaspects of coiled tubing-conveyed fracturingtreatments, including enabling technologies suchas surface equipment improvements, high-pres-sure coiled tubing, low-friction fracturing fluidsand new downhole isolation tools. Case historiesdemonstrate how this technique reduces comple-tion time and cost, improves post-treatmentcleanup, increases production and helps tapreserves bypassed by conventional completionand fracturing methods.

Conventional StimulationsAverage recovery factors for most reservoirs fromprimary- and secondary-drive mechanisms arejust 25 to 35% of original hydrocarbons in place.Producible reserves also are left behind in thin,lower permeability zones of many mature reser-voirs. One North Sea study, for example, deter-mined that more than 25% of recoverablereserves lie in the low-permeability, laminatedhorizons of Brent sandstone reservoirs.1

Matrix acidizing and hydraulic fracturing arecommon reservoir-stimulation techniques used toenhance well productivity, increase recovery effi-ciency and improve well economics.2 However,effectively completing and stimulating heteroge-

neous reservoirs and discontinuous pay zonesamong numerous shale intervals are challenging,particularly when fracture stimulations arerequired. Reservoir pay thickness, quality, pres-sure and stage of depletion, and cost to treat anentire productive horizon all must be consideredwhen choosing completion strategies.

Conventional fracture stimulations attempt toconnect as many producing zones as possiblewith single or multiple treatments performed dur-ing separate operations. Historically, net payzones over several hundred feet of gross intervalare grouped into “stages,” with each stage stim-ulated by a separate fracturing treatment. Thesemassive hydraulic fracturing jobs, pumpeddirectly down casing or through standard jointedtubing, are designed to maximize fracture heightwhile attempting to optimize fracture length.However, uncertainty associated with predictingheight growth often compromises the stimulationobjectives of large treatments and precludes cre-ation of the fracture lengths required to optimizeeffective wellbore radius and reserve drainage.

Proppant placement in individual zones is dif-ficult to achieve when a single treatment is per-formed across numerous perforated zones(below). Thin or low-permeability zones grouped

with thicker zones may remain untreated or maynot be stimulated effectively, and some zones areoccasionally bypassed intentionally to ensureeffective stimulation of more prolific pay. Limited-entry perforations and ball sealersdistribute fluid efficiently during pad injection,but less effectively during proppant placement as perforations are enlarged by erosion or treatment fluids flow preferentially into higherpermeability zones.3

Unintentionally bypassed and untreatedzones also are attributed to variable in-situstresses. In past conventional fracturing designs,the fracture gradient, or stress profile, wasassumed to be linear and to increase graduallywith depth. In reality, formation stresses oftenare not uniform across an entire geologic horizon,and again, some zones may be difficult to treatand stimulate effectively (next page, top).

Grouping pay zones in smaller stages over-comes some of these limitations and helpsensure sufficient fracture coverage, but multi-stage treatments usually require several perfo-rating and fracturing operations in succession.Isolating individual zones for conventional frac-ture stimulations with workover rigs and jointedtubing is problematic as well, requiring addi-tional equipment and workover procedures.There are fixed costs associated with each stageof multistage fracturing operations. Conventionalfracturing operations add redundancy to stimula-tion operations and increase overhead costs.

Every time wireline units and pumping equip-ment are moved onto a wellsite for perforatingand stimulation operations there are separatemobilization and setup charges. There are alsoseparate coiled tubing or slickline costs to washout sand plugs or set and retrieve bridge plugs,which have to be purchased or rented. Hauling,handling and storing stimulation and displacementfluids for each nonconsecutive fracturing opera-tion involve additional costs. Testing each individ-ual stage in a well again requires multiple setupsand significantly increases completion time.

Some gas wells with several large treatmentstages may take weeks to complete. Redundantcharges accumulate quickly on wells with morethan three or four stages and significantly affectthe economics of stimulation procedures. Thesehigher costs typically become a major influenceon completion or workover decisions and strate-gies and may limit development of marginal payzones that cumulatively contain sizeable volumesof oil and gas.

To stimulate bypassed zones in existingwells, conventional fracturing requires that lowerproducing zones be isolated by a sand plug or

62 Oilfield Review

> Single-stage treatment diversion: radioactive tracers and production logs. With limited-entry tech-niques, some zones are not stimulated effectively and others may remain untreated. In this example,six pay zones over a 300-ft [90-m] gross interval were fractured through 24 perforations. A radioactive-tracer survey shows that the three upper zones received most of the treatment fluids and proppant,while the three lower zones were not adequately stimulated (left). If an interval did not take fluid at thebeginning of a treatment, perforation erosion in other sands eliminated the backpressure necessaryfor diversion. The lowest zone contributes no production; the other two contribute very little flow onthe production log spinner survey (right).

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downhole mechanical tool such as a retrievableor drillable bridge plug. Upper perforations aresealed off by cement squeezes that are often dif-ficult to achieve, require additional rig time andadd to completion costs. There also is a risk thatsqueezed perforations will break down duringhigh-pressure pumping operations.

These limitations, inherent in conventionalfracturing techniques, reduce stimulation effec-tiveness. Unconventional well intervention andstimulation techniques are needed to ensurehydrocarbon production from as many intervalsas possible, especially from zones that previouslycould not be completed economically. Coiled tub-ing-conveyed fracturing techniques overcomemany of the limitations associated with conven-tional fracturing treatments (below left).4

Selective StimulationsCombining coiled tubing and stimulation servicesis not new. In 1992, coiled tubing was used tofracture wells in Prudhoe Bay, Alaska, USA. The31⁄2-in. coiled tubing was connected into the well-head and left in the well as production tubing tohelp maintain flow velocity. This technique never gained wide acceptance because it waslimited to smaller intervals and lower treatingpressures in wells where a single zone was targeted for completion.

1. Hatzignatiou DG and Olsen TN: “Innovative ProductionEnhancement Interventions Through Existing Wellbores,”paper SPE 54632, presented at the SPE Western regionalMeeting, Anchorage, Alaska, USA, May 26-28, 1999.

2. In matrix treatments, acid is injected below fracturingpressures to dissolve natural or induced damage thatplugs pore throats.Hydraulic fracturing uses specialized fluids injected atpressures above formation breakdown stress to createtwo fracture wings, or 180-degree opposed cracks,extending away from a wellbore. These fracture wingspropagate perpendicular to the least rock stress in apreferred fracture plane (PFP). Held open by a proppant,these conductive pathways increase effective wellradius, allowing linear flow into the fractures and to thewell. Common proppants are naturally occurring orresin-coated sand and high-strength bauxite or ceramicsynthetics, sized by screening according to standard USmesh sieves. Acid fracturing without proppants establishes conductiv-ity by differentially etching uneven fracture-wing sur-faces in carbonate rocks that keep fractures fromclosing completely after a treatment.

3. Limited entry involves low shot densities—1 shot per footor less—across one or more zones with different rockstresses and permeabilities to ensure uniform acid orproppant placement by creating backpressure and limit-ing pressure differentials between perforated intervals.The objective is to maximize stimulation efficiency andresults without mechanical isolation like drillable bridgeplugs and retrievable packers. Rubber ball sealers canbe used to seal open perforations and isolate intervalsonce they are stimulated so that the next interval can betreated. Because perforations must seal completely, holediameter and uniformity are important. The pad stage of a hydraulic fracturing treatment is thevolume of fluid that creates and propagates the fractureand does not contain proppant.

4. Zemlak W: “CT-Conveyed Fracturing Expands ProductionCapabilities,” The American Oil & Gas Reporter 43, no. 9(September 2000): 88-97.

Incr

easi

ng d

epth

> Variations in formation stress. In single, multizone treatments, pressurechanges are assumed to be linear with depth (far left). Depleted zones causepressure to decrease abruptly (middle left). Excessively depleted sands alsoreduce pressure over extensive intervals (middle right). In some cases, for-mations have pressure and stress variations that make diversion of treatmentfluids and stimulation coverage during a single-stage treatment extremelydifficult (far right).

> Conventional and selective stimulations. Fracturing several zones groupedin large intervals, or stages, is a widely used technique. However, fluid diver-sion and proppant placement are problematic in discontinuous and heteroge-neous formations. Conventional treatments, like this four-stage example,maximize fracture height, often at the expense of fracture length and com-plete interval coverage (left). Some zones remain untreated or may not bestimulated adequately; others are bypassed intentionally to ensure effectivetreatment of more permeable zones. Selective isolation and stimulation withcoiled tubing, in this case nine stages, overcome these limitations, allowingengineers to design optimal fractures for each pay zone of a productive interval (right).

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By 1996, coiled tubing-conveyed fracturingwas identified as a preferred completion strategyfor shallow gas fields in southeastern Alberta,Canada.5 Selective placement of proppant in allthe productive intervals of a wellbore reducedcompletion time and enhanced productivity. Thebest candidates were wells with multiple low-permeability zones where gas production wascommingled after fracturing. Previously, thesewells were stimulated by fracturing one intervalper well and then moving to the next well. Whilea fracturing crew treated the first interval of thenext well, a rig crew prepared previous wells forfracturing of subsequent intervals.

Extensive rig-up and rig-down times wererequired to treat as many as four wells a day. Interms of number of treatments performed, thisprocess was efficient, but moving equipmentfrom one location to another took more time thanactually pumping the fracturing treatments.Operators evaluated the possibility of groupingzones into stages for conventional multizonestimulations using limited-entry perforating, ballsealers or other diversion techniques to individu-ally isolate zones, but could not justify thesestandard industry practices economically.

One solution was to use a coiled tubing ten-sion-set packer and sand plugs for zonal isolation.The lowest zones were treated first by setting the

packer above the interval to be fractured.Proppant schedules for each zone included extrasand to leave a sand plug across fractured inter-vals after pumping stopped and before treatingthe next zone. Each treatment was underdis-placed, and wells were shut in to allow the extrasand to settle into a plug. A pressure test verifiedsand-plug integrity and the packer was resetabove the next interval. This procedure wasrepeated until all pay intervals were stimulated(above). The larger coiled tubing string was riggeddown and smaller coiled tubing was brought in towash out sand and initiate well flow.

Coiled tubing-conveyed fracturing has sinceexpanded to slimhole wells—23⁄8-, 27⁄8- and 31⁄2-in.tubulars cemented as production casing—and towells with open perforations or questionabletubular integrity that prevented fracturing downcasing. Conventional workovers and stimulationsthat require cement squeezes to isolate openperforations are expensive and risky under theseconditions. Shallow gas and deeper coiled tubingstimulations in mature oil and gas regions of thecontinental region of the United States formedthe basis for CoilFRAC selective isolation andstimulation services.

In east Texas, USA, coiled tubing was used tostimulate wells with open perforations abovebypassed zones and wells with low-strength 27⁄8-in. production casing weakened further by

corrosion. After the target zone was perforated, atension-set packer on coiled tubing isolated thewellbore and upper perforations (next page, topleft). In south Texas, bypassed pay zonesbetween open perforations in wells with casingdamage near the surface were stimulated suc-cessfully by setting a bridge plug below the tar-get zone and then running a tension-set packeron coiled tubing (next page, top right). Thesefracture stimulations were performed withoutcementing existing perforations or exposing pro-duction casing to high pressures.

Early CoilFRAC techniques with tension-setpackers improved stimulation results, but werestill time-consuming and limited by having to setand remove plugs. The next step was to developa coiled tubing straddle-isolation tool that sealedabove and below an interval to eliminate sepa-rate operations for spotting sand or setting bridgeplugs with a wireline unit (next page, bottom). Thismodification allowed coiled tubing strings to bemoved quickly from one zone to the next withoutpulling out of the well.

64 Oilfield Review

5. Lemp S, Zemlak W and McCollum R: “An EconomicalShallow-Gas Fracturing Technique Utilizing a CoiledTubing Conduit,” paper SPE 46031, presented at theSPE/ICOTA Coiled Tubing Roundtable, Houston, Texas,USA, April 15-16, 1998. Zemlak W, Lemp S and McCollum R: “Selective HydraulicFracturing of Multiple Perforated Intervals with a Coiled Tubing Conduit: A Case History of the UniqueProcess, Economic Impact and Related ProductionImprovements,” paper SPE 54474, presented at theSPE/ICOTA Coiled Tubing Roundtable, Houston, Texas,USA, May 25-26, 1999.

> Coiled tubing-conveyed fracturing with a single tension-set packer and sand plugs.

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> Multistage coiled tubing-conveyed fracturing operation with early straddle-isolation tools.

> Coiled tubing-conveyed fracturing with a singletension-set packer for casing and tubing protection.

> Coiled tubing-conveyed fracturing with a singlepacker and mechanical bridge plugs. In southTexas, a well with casing damage near the sur-face and a bypassed zone between existing openperforations was stimulated successfully withcoiled tubing. The operator set a bridge plug toisolate the lower zone before running a tension-set packer on coiled tubing to isolate the upperzone and protect the casing. This technique elimi-nated a costly workover and remedial cement-squeeze operations.

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Elastomer cup-type seals were added above atension-set packer to isolate perforated intervalsand eliminate separate plug-setting operations.However, additional modifications were requiredto further reduce time and cost. In Canada, anisolation tool with elastomer cups above andbelow an adjustable ported spacer assembly, ormandrel, was developed to allow multiple zonesto be treated in one trip (right).

This version of the straddle-isolation tool,which had no mechanical slips to facilitate quickmoves and fishing, carried shallow-gas projectsin Canada through more than 200 wells and 1000individual CoilFRAC treatments. Continuingimprovements to this tool allow bypassed andmarginal zones to be stimulated at nominal incre-mental cost. Efficient isolation and stimulation ofindividual sands maximized completed net payand made zones previously considered marginaleconomically viable.

More Experience in CanadaWildcat Hills field is located west of Calgary,Alberta, Canada, on the eastern slope of theRocky Mountains in a protected grassland area.6

This area has produced natural gas from deepMississippian discoveries since 1958. During theearly 1990s, two Olympia Energy wells testedshallower Viking sands. The wells initially pro-duced about 900 Mcf/D [25,485 m3/d], butdeclined rapidly to 400 Mcf/D [11,330 m3/d].Although pressure-buildup and production testsindicated substantial reserves, the low reservoirpressure, poor deliverability and high completioncosts precluded development of marginal Viking zones.

A 1998 seismic survey identified a third Vikingtarget in an area where the formation wasuplifted by more than 3000 ft [914 m], potentiallycreating natural fractures that might enhance gasdeliverability. The 3-3-27-5W5M well encoun-tered about 45 ft [14 m] of pay in five zonesacross 82 ft [25 m] of gross interval (next page,top). An FMI Fullbore Formation MicroImagermicroresistivity log verified existing natural frac-tures in the reservoir, but drillstem testing indi-cated a low pressure of 1100 psi [7.6 MPa].Pressure-buildup tests before setting 41⁄2-in. cas-ing and after perforating indicated drilling-fluidinvasion into natural fractures and additional for-mation damage from completion fluids.

A mud-solvent treatment failed to remove thedamage, so a fracturing treatment was selected

to increase gas deliverability. Fracturing downcasing with limited-entry diversion was not anoption because the well had already been perfo-rated. The operator evaluated diversion with ballsealers as well as mechanical zonal isolationwith sand plugs, bridge plugs or coiled tubing.Ball-sealer effectiveness is questionable, espe-cially during fracturing treatments, so mechani-cal diversion was deemed the most reliablemethod to ensure stimulation of all pay zones.

With only 13 to 16 ft [4 to 5 m] between fourzones, engineers eliminated use of sand plugsbecause close spacing made it difficult to accu-rately place the correct sand volumes.Conventional jointed tubing with packers andbridge plugs for isolation involved separate oper-ations to treat individual zones one at a time fromthe bottom up. This required repeated equipmentmobilization and demobilization, redundant ser-vices for each zone and retrieving or movingbridge plugs after each treatment—all of thesemade the costs prohibitive.

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> Coiled tubing isolation tools. The first CoilFRAC operations used a single tension-set packer above a zone with sand plugs or bridge plugs to isolatebelow the zone (left). Subsequent versions were modified to include an upperelastomer seal cup above the zone and a lower packer to isolate below (mid-dle). This second-generation tool was followed by a straddle design with elas-tomer seal cups on the top and bottom of a ported spacer, which increasedthe speed of packer moves, and reduced execution time as well as operationalcosts (right). These specialty tools eliminated rig and wireline operationsbecause sand plugs and bridge plugs were not needed. Coiled tubing could be moved quickly from one zone to the next without pulling out of the well.

6. Marsh J, Zemlak WM and Pipchuk P: “EconomicFracturing of Bypassed Pay: A Direct Comparison ofConventional and Coiled Tubing Placement Techniques,”paper SPE 60313, presented at the SPE Rocky MountainRegional/Low Permeability Reservoirs Symposium,Denver, Colorado, USA, March 12-15, 2000.

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The operator selected CoilFRAC services tostimulate each zone separately and treat severalzones in a single day. On the first day, the jointedtubing string used to perform production tests andthe solvent treatment was pulled from the well.Coiled tubing, fracturing and testing equipmentwas moved to location on the second day while awireline unit set a bridge plug to isolate the lowerViking formation. The maximum recommendedinterval that the isolation tool could straddle atthat time was 12 ft [3.7 m], which was less thanthe length of the lowest interval, so a tension-setpacker was used to fracture the first zone.

Three fracture stimulations were attemptedon the third day. Sticking problems required thestraddle-isolation tool to be pulled for repair ofthe elastomer seal cups. A casing scraper runsmoothed the rough casing. This step is now performed routinely before CoilFRAC treatmentsas part of wellbore preparation. Annulus pres-sure increased while pumping pad fluids in thesecond interval, indicating possible communica-tion behind pipe or fracturing into an adjacentzone. This treatment was cancelled before initi-ating proppant, and the tool was moved to thethird interval.

After the fourth interval was stimulated, thestraddle-isolation tool was pulled, so that open-ended coiled tubing could be used to clean outsand and unload fluids. On the fourth day, a snub-bing unit ran jointed production tubing in the wellunder pressure to avoid formation damage fromcompletion-fluid invasion.

To eliminate the snubbing unit, coiled tubingnow is used to run a packer with an isolationplug. After the packer is set, coiled tubing isreleased and removed from the well. The packerplug controls reservoir pressure until jointed pro-duction tubing is run. A slickline unit thenretrieves the isolation plug, initiating well flow.

Before stimulation, the 3-3-27-5W5M wellflowed 3.5 MMcf/D [99,120 m3/d] of gas at 350-psi [2.4-MPa] surface pressure. After threeof the upper four zones were fractured success-fully, the well produced 6 MMcf/D [171,818 m3/d]at 350 psi. The well continued to produce at 5 MMcf/D [143,182 m3/d] and 450 psi [3.1 MPa]for several months. The CoilFRAC treatmentdelivered an economic production gain in addi-tion to reducing cleanup time and simplifyingcompletion operations (left). Minimal operationsand faster cleanup helped bring production online sooner by reducing completion cycle timefrom 19 to 4 days.

>Well 3-3-27-5W5M, Wildcat Hills field. Previous attempts to stimulate the Viking formation as a contin-uous interval were not successful because of difficulty in intersecting multiple zones with conventionalsingle-stage fracture treatments. Closely spaced perforated intervals prohibited isolation with a packerand sand or bridge plugs. Selective CoilFRAC treatment placement simulated four zones individually toincrease recovery by isolating and fracturing pay that often is bypassed or left untreated. Secondarygoals were to simplify several days of completion operations into a single day and reduce cost.

> Comparison of conventional and CoilFRAC Viking completions. Coiled tub-ing-conveyed fracture stimulations required 58% less total proppant, reducedoverall completion operations from 19 days to 4, and improved well cleanupand fracturing fluid recovery. CoilFRAC treatment placement and simultane-ous flowback improved fluid recovery and saved Olympia Energy about$300,000 per well in the Wildcat Hills field, which reduced cost per Mcf/D byabout 78%.

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Olympia Energy drilled six more wells in theWildcat Hills field after completion of the 3-3-27-5W5M well. Because the Viking formation variesfrom well to well, the operator selected fractur-ing techniques based on sand thickness, fracturecontainment barriers, vertical spacing betweensands and required number of treatments. Threeof these wells contained two or three thick Vikingsands that were fractured down casing. Thelarger zones required higher pump rates to opti-mize fracture height and length, which ruled outuse of coiled tubing because of potentially exces-sive surface treating pressures.

Like the 3-3-27-5W5M well, the other threewells had similar interbedded sand-shalesequences and 6- to 13-ft [2- to 4-m] pay zones,so Olympia Energy used CoilFRAC selective stim-ulations. This approach increased productivityand recovery by selectively treating pay that hadbeen bypassed or not stimulated effectively, andit ultimately decreased operational costs.

Pre- and post-treatment production logs wererun on the 4-21-27-5W5M well to evaluateincreased production from zones in one of the

wells that was fractured using coiled tubing (below). Prior to fracturing, the well produced2 MMcf/d [57,300 m3/d] with flow from two intervals. After CoilFRAC treatments on five intervals, gas production increased to4.5 MMcf/D [128,900 m3/d] with flow from fourof the five intervals. Olympia Energy saved$300,000 per well on fracturing operations aloneby using CoilFRAC techniques to stimulateWildcat Hills Viking wells. One of the original Vikinggas wells has been reevaluated and identified asa candidate for stimulation with coiled tubing.

At a depth of 8200 ft [2500 m], this coiled tub-ing-conveyed application demonstrated theimpact of combining coiled tubing and stimula-tion technologies on well productivity andreserve recovery. The smaller surface footprint,less time on location and fewer wellsite visitscombined with less gas emissions and flaring asa result of flowing, testing and cleaning up all thepay zones at one time make CoilFRAC treatmentsparticularly attractive in environmentally sensi-tive areas like the grasslands around WildcatHills field.

Fracturing Designs and OperationsCoiled tubing-conveyed fracturing is constrainedby restrictions on fluid and proppant volumesrelated primarily to smaller tubular sizes andpressure limitations. The application of CoilFRACservices requires alternative fracture designs,specialized fluids, high-pressure coiled tubingequipment, and integrated fracturing and coiledtubing service teams to ensure effective stimula-tions and safe operations.7

Injection rates, fluid parameters, treatmentvolumes, in-situ stresses and formation charac-teristics determine the net pressure availabledownhole to create a specific fracture geo-metry—width, height and length. Minimumpump rates are required to generate the desiredfracture height and to transport proppant alongthe length of a fracture. Minimum proppant con-centrations are needed to attain adequate frac-ture conductivity.

Coiled tubing strings have a smaller internaldiameter (ID) than the standard jointed work-strings used in conventional fracturing opera-tions. At the injection rates required for hydraulicfracturing, frictional pressure losses associatedwith proppant-laden slurries can lead to hightreating pressures that exceed surface equip-ment and coiled tubing safety limits. Using largercoiled tubing reduces friction pressures, butincreases equipment, logistics and maintenancecosts, and may not be practical for small-diame-ter slimhole and monobore wells.

This means that treatment rates and proppantvolumes for coiled tubing-conveyed fracturingmust be reduced compared with those of con-ventional fracturing. The challenge is to achieveinjection rates and proppant concentrations thattransport proppant effectively and create therequired fracture geometry. Coiled tubing-con-veyed fracturing requires alternative equipmentand treatment designs to ensure acceptable sur-face treating pressures without compromisingstimulation results.

Reservoir characterization is the key to anysuccessful stimulation treatment. Like conven-tional fracturing jobs, coiled tubing treatmentsmust generate a fracture geometry consistentwith optimal reservoir stimulation. The preferredapproach is to design CoilFRAC pumping sched-ules that balance required injection rates andoptimal proppant concentrations with coiled tub-ing treating-pressure constraints. Fracturing fluidselection depends on reservoir characteristicsand fluid leakoff, downhole conditions, requiredfracture geometry and proppant transport. Fluids

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> Pre- (left) and post-stimulation (right) evaluation. Production log spinner surveys in Viking Well 4-21-27-5W5M confirmed that CoilFRAC selective fracturing treatments in each Viking sand improved theproduction profile and total gas rate (right).

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for CoilFRAC treatments include water-base lin-ear or low-polymer systems and polymer-freeClearFRAC viscoelastic surfactant (VES) fluids.8

In the past, polymers provided fluid viscosityto transport proppant. However, residue fromthese fluids can damage proppant packs andreduce retained permeability. Engineers oftenincrease proppant volumes to compensate forany reduced fracture conductivity, but slurry friction increases exponentially with higher prop-pant concentrations and can limit the effective-ness of CoilFRAC treatments. Increased surfacetreating pressure from frictional pressure lossesis the dominant factor in coiled tubing-conveyedfracturing, so reducing surface pump pressures iscritical in CoilFRAC applications, particularly indeeper reservoirs.

Because of their unique molecular structure,VES fluids exhibit as much as two-thirds lower frictional pressures than polymer fluids (right). Nondamaging ClearFRAC fluids may pro-vide adequate fracture conductivity with lowerproppant concentrations at acceptable surfacetreating pressures. This facilitates optimized frac-ture designs. These fluid characteristics makecoiled tubing-conveyed fracturing feasible at com-monly encountered well depths.

Another advantage of ClearFRAC fluids isreduced sensitivity of fracture geometry to fluidinjection rate. Height growth is better contained,resulting in longer effective fracture lengths,which is particularly important when treating thin,closely spaced zones. Fluids based on a VES alsoare less sensitive at downhole temperatures and conditions that cause fracturing fluids to break prematurely.

If pumping stops because of an operationalproblem or fracture screenout, the stable suspen-sion and transport characteristics of ClearFRACfluids prevent proppants from settling too quickly,especially between the seal cups of straddle-iso-lation tools. This allows time to clean out remain-ing proppant and decreases the risk of stuck pipe.In addition, these fluids provide a backup contin-gency in high-risk environments, such as high-angle or horizontal wells, where proppant settlingalso can be a problem.

Recovering treatment fluids is critical whentarget zones have low permeability or low bot-tomhole pressure. Another benefit of VES fractur-ing fluids is more effective post-stimulationcleanup. Field experience has shown that VESfluids break down completely in contact withreservoir hydrocarbons, through extended dilu-tion by formation water or under prolonged expo-sure to reservoir temperature, and aretransported easily into wellbores by produced flu-ids. Retained permeability is close to 100% of

original permeability with VES fluids. In addition,treating and flowing back all the zones at onetime improve fluid recovery and fracture cleanup.

High-strength, 13⁄4- to 27⁄8-in. coiled tubing isused to accommodate higher injection pressures.Coiled tubing for fracturing operations is fabri-cated from high yield-strength, premium-gradesteels with high burst pressure. For example, 13⁄4-in., 90,000-psi [621-MPa] yield strength coiledtubing has a burst-pressure rating of 20,700 psi[143 MPa] and can withstand collapse pressuresof 18,700 psi [129 MPa]. Coiled tubing is hydro-statically tested to about 80% of its burst-pressurerating, 16,700 psi [115 MPa] for this 13⁄4-in. stringprior to pumping operations, and maximum pumppressure is set at 60% of the design burst pressure, or about 12,500 psi [86 MPa], forthis example.

Because the entire coiled tubing string con-tributes to friction pressure, regardless of howmuch is inserted in a well, the length of coiledtubing on a reel should be minimized relative tothe deepest interval. There has been concernthat centrifugal forces on the proppant woulderode the inner wall of spooled coiled tubing.However, visual and ultrasonic inspection beforeand after fracturing found no erosion inside thecoiled tubing and detected only minor erosion atcoiled tubing connectors after pumping as manyas nine treatments.

Operational safety is critical at the high pres-sures required for hydraulic fracturing treat-ments. For example, personnel should not bepermitted near wellheads or coiled tubing equip-ment during pumping operations. Coiled tubing-conveyed fracturing requires specialized surfaceequipment and innovative modifications to

ensure safe operations and to deal with contin-gencies in the event of a screenout.9 On the surface, coiled tubing equipment, such as quick-response, gas-operated relief valves, remotelyoperated fracturing manifolds and modificationsto coiled tubing reels and manifolds, allow high-rate pumping of abrasive slurries.

Precise depth control also is important forselective stimulations. Inaccurate positioning ofcoiled tubing results in serious and costly prob-lems—perforating off-depth, placing a sand plugin the wrong place, problems positioning straddle-isolation tools or stimulating the wrong zone.Straddle-isolation tools must be positioned accu-rately across perforated intervals. Five types ofdepth measurements are used: standard level-wind pipe measurements as coiled tubing comesoff the reel, a depth-monitoring system in the injector head, mechanical casing-collar locatorsand two new independent systems used by Schlumberger—the Universal Tubing-LengthMonitor (UTLM) surface measurement and theDepthLOG downhole casing-collar locator.

7. Olejniczak SJ, Swaren JA, Gulrajani SN and OlmsteadCC: “Fracturing Bypassed Pay in TubinglessCompletions,” paper SPE 56467, presented at the SPEAnnual Technical Conference and Exhibition, Houston,Texas, USA, October 3-6, 1999.Gulrajani SN and Olmstead CC: “Coiled Tubing ConveyedFracture Treatments: Evolution, Methodology and FieldApplication,” paper SPE 57432, presented at the SPEEastern Regional Meeting, Charleston, West Virginia,USA, October 20-22, 1999.

8. Chase B, Chmilowski W, Marcinew R, Mitchell C, Dang Y,Krauss K, Nelson E, Lantz T, Parham C and Plummer J:“Clear Fracturing Fluids for Increased Well Productivity,”Oilfield Review 9, no. 3 (Autumn 1997): 20-33.

9. A screenout is caused by proppant bridging in the frac-ture, which halts fluid entry and fracture propagation. Ifa screenout occurs early in a treatment, pumping pres-sure may become too high and the job may be termi-nated before an optimal fracture can be created.

> Effect of friction-reducing fluids. As CoilFRAC applications expand to includedeeper wells, low-friction fluids will be a key to future success. This plot com-pares surface-treating pressure versus depth for 2-in. coiled tubing using apolymer-based fracturing fluid and a ClearFRAC viscoelastic surfactant (VES)fluid, both with 4 ppa proppant concentrations.

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In the past, the accuracy of standard coiledtubing depth measurements was about 30 ft[9.1 m] per 10,000 ft [3048 m] under the best con-ditions and as much as 200 ft [61 m] per 10,000ft in the worst cases. The dual-wheel UTLM sur-face measurement is self-aligning on the coiledtubing, minimizes slippage, offers improved wearresistance and measures unstretched pipe(below).10 Two measuring wheels constructed ofwear-resistant materials, on-site data processingand routine calibration eliminate the effects ofwheel wear on surface measurement repeatabil-ity and provide automatic redundancy in additionto slippage detection.

The remaining factors that affect measure-ment accuracy and reliability are contaminantsand buildup on wheel surfaces, and thermaleffects that change wheel dimensions. An anti-buildup system prevents contamination of wheelsurfaces. Downhole coiled tubing pipe deforma-tion is evaluated using computer simulation. For thermal pipe deformation modeling, a well-bore simulator provides a temperature profile.The total deformation can be estimated with anaccuracy of about 5 ft [1.5 m] per 10,000 ft. Thecombination of more accurate surface measure-ments with modeling and improved operationalprocedures result in about a 11 ft [3.4 m] per10,000 ft accuracy, and a repeatability of about 4 ft [1.2 m]. In most cases, a value of less than 2 ft[0.6 m] is achieved.

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> The UTLM dual-wheel surface depth-measurement device.

> Hiawatha field producing horizons. In the Hiawatha field of northwest Colorado (insert), pay zones historically were grouped in intervals, or stages,of 150 to 200 ft [46 to 61 m] and stimulated with a single fracture treatment.Thin sands were grouped with thick sands, and occasionally thin sandswere bypassed to avoid less effective stimulation of more prolific sands.Multiple hydraulic fracture stages were still required to treat the entire wellbore. Each fracture stage was isolated with a sand plug or mechanicalbridge plug. Justifying completion of thin sands capable of 100 to 200 Mcf/D[2832 to 5663 m3/d] was difficult.

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Previously, depth correction with wirelineinside coiled tubing or memory gamma ray log-ging tools, “flags” painted directly on the coiledtubing and mechanical casing-collar locatorsoften were inaccurate, costly and time-consum-ing. Schlumberger now uses a wirelessDepthLOG tool, which detects magnetic varia-tions at joint casing collars as tools are run into awell and sends a signal to surface throughchanges in hydraulic pressure. Subsurfacedepths are determined quickly and accurately bycomparison with baseline gamma ray correlationlogs. The use of wireless technology decreasesthe number of coiled tubing trips into a well andsaves up to 12 hours per operation on typicalcoiled tubing-conveyed perforating and stimula-tion operations.

In the past, separate coiled tubing services, ifrequired, followed fracturing operations to cleanout excess proppant. Coiled tubing-conveyedfracturing, however, requires the combinedefforts of fracturing and coiled tubing personnel.Initially, service crews faced a steep learningcurve as they began working together to reducethe time required for various operations.Subsequent CoilFRAC projects increased opera-tional efficiency and reduced completion time. Tofurther increase efficiency, Schlumberger hasformed dedicated CoilFRAC teams to integratecoiled tubing and fracturing expertise.

Revitalizing a Mature FieldTexaco Exploration and Production Inc. (TEPI),now a ChevronTexaco company, extended the productive life of West Hiawatha field inMoffat county, Colorado, USA, with CoilFRACtechniques.11 Discovered in the 1930s, this field has 18 pay sands over 3500 ft [1067 m] of gross interval. Gas production comes from the Wasatch, Fort Union, Fox Hills, Lewis andMesaverde formations (previous page, right).Previously, wells were completed with 41⁄2-, 5- or7-in. casing and stimulated using conventionalstaged fracturing treatments.

A common practice was to stimulate zonesfrom the bottom upward until production rateswere satisfactory. As a result, thin zones oftenwere ignored and undeveloped uphole potentialexisted throughout the field. In 1999, TEPI evalu-ated bypassed pay in the field to identify and rankworkover potential based on reservoir quality,cement integrity, completion age and wellboreintegrity. New drilling locations were identifiedafter a successful workover on Duncan Unit 1Well 3, but the challenge was to develop a strat-egy that could effectively stimulate all of the payzones during initial completion operations.

The operator chose CoilFRAC services toselectively stimulate Wasatch and Fort Unionsands, which comprise multiple sands from 5 to60 ft [1.5 to 18 m] thick from 2000 to 4000 ft [600to 1200 m] deep. This approach provided flexibil-ity to design optimal fracture treatments for eachzone rather than large jobs to intersect multiplezones over longer intervals.

In the first drill well, individual CoilFRACtreatments were performed on 13 zones in threedays. Seven zones were treated in a single day.This well’s average first month production was2.3 MMcf/D [65,900 m3/d]. The second drill wellinvolved eight treatments in one day. Averageproduction from the second well during the firstmonth was 2 MMcf/D. Treating pressures rangedfrom 3200 psi [22 MPa] to the maximum allow-able 7000 psi [48 MPa].

Zones separated by 10 to 15 ft [3 to 4.6 m]were fractured with no communication betweenstages. Pump-in tests verified that fracture gradi-ents between zones varied from 0.73 to 1 psi/ft[16.5 to 22.6 kPa/m]. The variation in fracturegradient for each zone confirmed the difficulty ofstimulating multiple zones with conventionalstage treatments (above). In addition to eightworkovers with mixed success, nine successful

10. Pessin JL and Boyle BW: “Accuracy and Reliability ofCoiled Tubing Depth Measurement,” paper SPE 38422,presented at the 2nd North American Coiled TubingRoundtable, Montgomery, Texas, USA, April 1-3, 1997.

11. DeWitt M, Peonio J, Hall S and Dickinson R:“Revitalization of West Hiawatha Field Using Coiled-Tubing Technology,” paper SPE 71656, presented at theSPE Annual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 30-October 3, 2001.

> Evaluating single-stage Hiawatha field fracture stimulations. Without selective isolation of individualsands, variations in fracture gradients make it difficult to optimize fracture lengths with a single con-ventional treatment and limited-entry perforating. For two Wasatch zones that would be grouped whenstimulating multiple intervals with a single treatment, StimCADE hydraulic fracturing simulator plotsindicate that about two-thirds of the proppant is placed in the upper interval (top). This results in awider, more conductive fracture and a half-length almost 50% greater than in the lower interval (bottom). If there are more than two zones, this problem is further compounded by variations in dis-continuous sands from wellbore to wellbore.

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wells were drilled in Hiawatha field from May2000 through July 2001. These new wells werecompleted with CoilFRAC stimulations in theWasatch and Fort Union formations, and conven-tional fracture treatments for the more continu-ous Fox Hills, Lewis and Mesaverde intervalsbelow 4000 ft [1220 m].

To quantify coiled tubing stimulation results,the CoilFRAC completions were compared withwells fractured conventionally between 1992 and1996 (right). Average production from CoilFRACcompletions increased 787 Mcf/D [22,500 m3/d],or 114%, above historical rates. However, pro-duction from individual wells may be misleadingif reserves are drained from offset wells. Fieldoutput will not increase as expected when thereis interference between wells; natural pressuredepletion should result in new wells producingless, not more.

From 1993 to 1996, Hiawatha field outputincreased from 7 to 16 MMcf/D [200,500 to460,000 m3/d] as a result of the 12-well drillingprogram. Production doubled again from 11 to 22 MMcf/D [315,000 to 630,000 m3/d] as a resultof workovers and new wells completed mostlywith coiled tubing-conveyed stimulations. Fieldproduction is at the highest level in 80 years.Stimulating each zone individually during initialcompletion operations is believed to be the keyto improving production and increasing reserverecovery in this mature field.

State-of-the-Art Downhole ToolsIsolation tools have evolved along with CoilFRACtreatments and specific requirements generatedby various stimulation applications. Coiled tubing-conveyed fracturing operations are performedunder the most dynamic reservoir stimulationconditions. Treatments take place in live wells atformation temperatures and pressures, and withthe completion of each selective stimulation,these conditions change. As a result, increasinglydemanding applications in deeper wells requiremore reliable, multiple-set isolation tools.

Driven by a need to minimize operational andfinancial risks and reduce the impact ofunplanned events, like proppant screenout,Schlumberger developed the CoilFRAC Mojaveline of downhole tools (next page). This improvedstraddle system consists of three technologies—the pressure-balanced disconnect, the modularstraddle assembly with ported sub, and the slurrydump valve. In combination, these componentsprovide selective placement of sequential acid orproppant fracture stimulations, and matrix acid,

screenless sand-control or scale-inhibitor treat-ments in a single trip with coiled tubing.

The pressure-balanced disconnect features amechanical shear disconnect that is pressure-balanced to coiled tubing treating pressure. Onlymechanical coiled tubing loads are transferred tothe shear-release pins; treating pressure doesnot affect the shear-pin release function. Thisreduces the likelihood of leaving the tool in awell as a result of unexpectedly high downholetreating pressures during CoilFRAC stimulations,such as a screenout. The pressure-balanced dis-connect allows coiled tubing to be run deepbecause the disconnect does not require extrashear pins to account for pressure loads duringtreatments. If the tool becomes stuck, it can befished by overshot or internal fishing neck.

The CoilFRAC Mojave isolation tool hasopposing elastomer cups for 41⁄2- to 7-in. casing.The tool functions in vertical or horizontal wellsand has no mechanical slips and no moving parts.An internal fluid bypass in the tool body permitsrunning to deeper depth—10,000 ft instead ofless than 4000 ft. This feature lightens coiledtubing loads during trips in and out of wells toreduce elastomer wear, minimize swab and surgeforces on formations and decrease the risk of atool sticking between zones. A modular designand special 2-ft [0.6-m] ported fracturing suballow 4-ft sections to be assembled for spacingelastomer cups up to 30 ft apart.

The CoilFRAC fracturing sub also includes afluid bypass and resists erosion when pumpingup to 300,000 lbm [136,100 kg] of sand. It is pos-sible to pump up to 500,000 lbm [226,800 kg] ofless erosive resin-coated and man-made ceramic proppants. Reverse circulation isrequired to clean the coiled tubing and CoilFRACMojave isolation tool when run without a slurrydump valve. A lower reversed bottom cup seals during reverse circulation to improve post-treatment cleanup. A gauge port is built into the tool for downhole pressure and temper-ature measurements.

Since the slurry dump valve (SDV) is flow-operated, no coiled tubing movement is required.One SDV design in two sizes is compatible withstandard 41⁄2- to 7-in. CoilFRAC Mojave tools and functions in vertical or horizontal wells.Incorporating a SDV allows slurry to be dumpedfrom the coiled tubing between zones and facili-tates stimulations in low-pressure reservoirs andformations with fracture gradients of less than afull water gradient, or 0.4 psi/ft [9 kPa/m].

The SDV is closed and acts as a fill valvewhen running in a well. It also reduces formationdamage during multizone well treatments.Reverse circulation is not required for coiled tub-ing cleanup, which reduces total stimulation fluidrequirements, eliminates the environmentalimpact of slurry returned to surface, reduceselastomer wear by equalizing pressure acrosselastomer seal cups, and reduces abrasive wearon coiled tubing and surface equipment.

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> Analyzing Hiawatha field coiled tubing fracturing results. Production fromwells completed with CoilFRAC selective isolation and simulation treatments(red) was compared with production from wells that were previously frac-tured conventionally (black). Average daily well rates for each month wasnormalized to time zero and plotted for the first six months. Initial productionfrom the CoilFRAC completions was about 787 Mcf/D [22,500 m3/d], or 114%,more than historical rates.

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Optimizing Recovery in South TexasSamedan Oil Corporation operates North Rinconfield in south Texas, producing gas from variouszones of the Vicksburg formation at 6000 to7000 ft [1800 to 2100 m]. The Martinez B54 well,completed in a single 25-ft [7.6-m] zone, had aninitial production rate of 4.5 MMcf/D beforedeclining to 1 MMcf/D. In December 2000,Samedan evaluated fracturing this zone for thefirst time as well as completing deeper pay in theMartinez B54 well. Openhole logs had identifiedseveral other productive zones that had beenintentionally bypassed because of marginal eco-nomics. In February 2001, Schlumberger assem-bled a multidisciplinary team to integratepetrophysical and reservoir knowledge with completion design, execution and evaluation services using the PowerSTIM stimulation opti-mization initiative.12

Samedan and the PowerSTIM team analyzedwell data to determine reservoir size and remain-ing reserves for the current producing zone.These calculations indicated a 19-acre [7700-m2]drainage area and confirmed that a nearby geo-logic unconformity acted as a seal. Productionand NODAL analyses matched the 1-MMcf/Dproduction and indicated that, based on a limiteddrainage area and low formation damage,remaining reserves could be recovered in a few months.13 This interval was not a candidatefor stimulation.

Samedan decided to deplete the existingzone before completing the most attractivebypassed zones. Reinterpreted logs indicated77 ft [23 m] of high-quality net pay with signifi-cant recoverable reserves in five deeper zonesover 700 ft [213 m] of gross interval.Conventional stimulation techniques requiredlimited-entry perforating for diversion of largefluid and proppant volumes pumped at high ratesto cover and fracture this entire interval.

The operator considered setting productiontubing and a packer below existing perforationsand completing only one or two of the uppermostbypassed zones. This approach, however, wouldleave a significant volume of additional reservesuntapped behind pipe. The PowerSTIM team rec-ommended CoilFRAC selective isolation serviceswith optimized fracture designs to complete andindividually stimulate all five bypassed zones. A2-in. coiled tubing string was selected to conveyfracturing fluids and proppant at the requiredrates. An SCMT Slim Cement Mapping Tool logconfirmed cement integrity and adequate zonalisolation behind pipe across the proposed completion intervals. The existing perforationswere sealed with a cement squeeze prior toCoilFRAC operations.

12. Al-Qarni AO, Ault B, Heckman R, McClure S, Denoo S,Rowe W, Fairhurst D, Kaiser B, Logan D, McNally AC,Norville MA, Seim MR and Ramsey L: “From ReservoirSpecifics to Stimulation Solutions,” Oilfield Review 12,no. 4 (Winter 2000/2001): 42-60.

13. NODAL analysis couples the capability of a reservoir toproduce fluids into a wellbore with tubular capacity toconduct flow to surface. The technique name reflectsdiscrete locations—nodes—where independent equa-tions describe inflow and outflow by relating pressure

> CoilFRAC Mojave isolation tools. From single mechanical packers to elas-tomer cup and packer combinations and the earliest versions of opposingelastomer-cup straddle tools, the suite of CoilFRAC tools has expanded toinclude specially designed straddle assemblies. The effectiveness of CoilFRACstraddle assemblies for zonal isolation has been aided by more reliable seal-ing technologies. An annular flow path within the assembly allows for easydeployment and retrieval.

losses and fluid rates from outer reservoir boundariesacross the completion face, up production tubing andthrough surface facility piping to stock tanks. Thismethod allows calculation of rates that wells are capa-ble of delivering and helps determine the effects of dam-age, or skin, perforations, stimulations, wellhead orseparator pressure and tubular or choke sizes. Futureproduction also can be estimated based on anticipatedreservoir and well parameters.

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In May 2001, Samedan and Schlumbergerperformed a five-stage CoilFRAC selective stimulation (next page, top). On the first day, thefive zones were perforated with deep-penetrat-ing PowerJet premium charges to maximize perforation entry-hole size and reservoir penetra-tion. After perforating, the commingled zonesproduced 1.1 MMcf/D [31,500 m3/d] during aprestimulation test.

On the second day, each zone was isolatedsequentially with a 5-in. CoilFRAC Mojave straddle tool and fracture-stimulated with a non-damaging ClearFRAC fluid and 136,000 lbm[61,700 kg] of man-made ceramic proppant. Allfive zones were treated within a 24-hour period.Pump rates ranged from 8 to 10 bbl/min [1.3 to1.6 m3/min] with treating pressures up to11,000 psi [76 MPa]. Because of potentially highgas production rates, PropNET fiber additiveswere incorporated at the end of the pumpingschedules to prevent proppant flowback.14

When all the zones were commingled andtested, the well flowed more than 5.1 MMcf/D[146,000 m3/d] and 120 B/D [19 m3/d] of conden-sate, which closely matched production predic-tions. A production log spinner survey indicatedthat four of the five Vicksburg zones had beenstimulated successfully (above and left). One monthlater, the well was still producing about 5 Mcf/D,which did not follow the expected decline.Estimated payout was three months. Samedanengineers evaluated the next three drill wells, butnone of these new wells were viable candidatesfor coiled tubing-conveyed fracture stimulation.

Completing five zones in a single trip miti-gated the risk of formation damage from multiplewell interventions, and risk of fluid swabbingassociated with conventional fracturing opera-tions, jointed tubing and standard downholetools. This CoilFRAC treatment took only twodays, while a conventional five-stage fracturingjob might have taken up to two weeks.

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< Martinez B54 well CoilFRAC treatment stimulation results for five zones.

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Additional ApplicationsThe combination of reservoir-stimulation andwell-treatment technologies with coiled tubingconveyance is expanding selective CoilFRACtechniques to include applications, like acid frac-turing, and specialized completion techniquessuch as scale inhibition, controlling proppantflowback and screenless sand control (above).

With advances in friction-reducing fluids,injection rates are sufficient for coiled tubing and CoilFRAC tools to be used as mechanical

diversion during acid fracturing. This capability isincreasingly important in mature carbonatereservoirs when small zones within larger pro-ducing intervals require stimulation. CoilFRACstimulations help operators deplete reserves uni-formly across an entire hydrocarbon-bearinginterval and facilitate reservoir management.

The downhole buildup of scales, asphaltenesor migrating fines and the plugging of perforationsand completion equipment impair permeabilityand can restrict or prevent production altogether.

Accurate CoilFRAC selective placement allowsscale inhibitors to be conveyed deeper into the for-mation during fracturing or acidizing stimulationtreatments. Integrating scale inhibitors and stimu-lation treatment fluids into a single step ensuresthat the entire productive interval—including theproppant pack—is treated.

Performing multiple, smaller fracture treat-ments is another approach to reduce scalebuildup and sand production. This methodreduces the pressure drop across the formationface, which decreases or, in some cases, pre-vents scale and asphaltene formation. Duringproduction, pressure drawdown increases thevertical stress on producing intervals and exacer-bates sand production. An alternative is to treatsmaller intervals and reduce the pressure dropacross the formation face.

Screenless Sand-Control CompletionsInnovative screenless completions provide sandcontrol without the need for downhole mechani-cal screens and gravel packing by using tech-nologies such as resin-coated proppants andPropNET fibers to control proppant flowback andsand production. The primary challenge of apply-ing screenless technology is ensuring coverageof all perforated pay zones. In general, intervallength is the controlling factor. Thicker intervalstypically reduce treatment success rates. Coiledtubing-conveyed fracturing, with the capability oftreating numerous zones, increases screenlesscompletion effectiveness and reduces overallcosts while increasing net pay potential.Treatments in North America have reduced prop-pant flowback by five-fold.

PT. Caltex Pacific Indonesia, a ChevronTexacoaffiliate, operates the Duri field in the CentralSumatra basin.15 Primary recovery is low, sosteam injection is used to achieve higher recov-ery factors. This multibillion-barrel steamflood cov-ers 35,000 acres [14 million m2] and produces280,000 B/D [44,500 m3/d] of high-viscositycrude oil. Oil-bearing sands are highly unconsoli-dated, Miocene-age formations with permeability

14. Armstrong K, Card R, Navarrete R, Nelson E, Nimerick K,Samuelson M, Collins J, Dumont G, Priaro M, Wasylycia Nand Slusher G: “Advanced Fracturing Fluids ImproveWell Economics,” Oilfield Review 7, no. 3 (Autumn 1995):34-51.

15. Kesumah S, Lee W and Marmin N: “Startup of ScreenlessSand Control Coiled Tubing Fracturing in Shallow,Unconsolidated Steamflooded Reservoir,” paper SPE74848, prepared for presentation at the SPE/ICOTACoiled Tubing Conference and Exhibition, Houston,Texas, USA, April 9-10, 2002.

> Martinez B54 well in the North Rincon field, south Texas (Courtesy of Samedan Oil Corporation).

> Unconventional coiled tubing-conveyed treatments. CoilFRAC treatments also are applicable forchemical scale inhibition and sand-control methods. Coiled tubing places scale inhibitors included in apreflush before fracturing or proppant impregnated with scale inhibitors more effectively than conven-tional treatment techniques (left). Novel screenless completions provide sand control without down-hole mechanical screens and gravel packing by using technology like resin-coated proppants andPropNET fibers to control proppant flowback and sand production (right). The primary challenge ofapplying these techniques is ensuring coverage of all perforated pay zones.

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as high as 4000 mD (right). Combined pay thick-ness is about 140 ft [43 m] over an interval fromX430 to X700 ft. In addition to 3600 producingwells, the operator maintains about 1600 steam-injection and temperature-observation wells.

Heat requirements are lower in temperature-mature areas where the steamflood has been inoperation for an extended period of time. Steaminjection can be reduced, allowing the operatorto convert injectors and observation wells intoproducers. Low reservoir pressure causesdrilling, completion and production problemsincluding lost circulation, hole collapse and sandproduction. Severe sanding leads to frequentwell servicing to replace worn or stuck artificial-lift equipment. The marginal nature of thesewells, initially completed with 4-, 7-, or 95⁄8-in. ODmonobore casing, limits conventional gravel-packed screens for sand control. In most wells,screens are not installed because of restrictedwellbore access, smaller pump sizes and, conse-quently, unfavorable production rates.

In a recent field test on several wells, theoperator in Duri field used CoilFRAC techniquesto perform screenless completions using curableresin-coated sand and tip-screenout fracturedesigns to prevent proppant flowback and migra-tion of formation grains.16 After resin-coated sandis placed and cured, proppant packs are locked in place to create a stable filter against the formation in perforation tunnels and near-wellbore regions.

Using resin-coated proppant to control sandwithout mechanical screens is not new. In 1995, aDuri field pilot project used conventional fractur-ing with resin-coated sand to complete Rindusands at about X450 ft. Single-stage tip-scree-nout treatments attempted to place resin-coatedproppant in multiple zones across 50 to 100 ft [15to 30 m] of gross interval. This technique failed toachieve acceptable results because the grossintervals were too long and not all perforationsreceived resin-coated sand. In addition, producedformation sand covered some lower zones andsteam injection did not cure the resin-coated sandacross the entire section.

The primary objectives of the most recentfield test were to ensure complete treatment coverage of all perforations and achieve tip-screenout fractures for proper proppant packing.Grain-to-grain contact and closure stress improvethe curing process and ensure a strong com-pacted filter medium. Heat or alcohol-base fluidscure phenolic resins. The operator uses bothmethods to ensure a complete resin set.CoilFRAC selective isolation and treatmentplacement provided accurate and complete per-foration coverage, which made screenless completions a viable alternative to gravel

packing or frac packing with screens, and previous screenless completions that wereattempted conventionally.

Fracture treatments and pumping scheduleswere designed to achieve required fracture half-length and conductivity. Relatively low pumpingrates control vertical coverage, while higherproppant concentrations are needed to ensurefracture conductivity and achieve tip screenout.The maximum rate is usually about 6 bbl/min[1 m3/min] with proppant concentrations of8 pounds of proppant added (ppa). The number oftreatment stages in a given well was determinedby evaluating perforated interval length andspacing between zones.

Interval length needed to be less than 25 ft toensure complete coverage with a minimum of 7 ft[2 m] between intervals to allow the isolationtool to set properly. The operator verified cementbond and quality to ensure isolation behind thepipe and avoid proppant channeling. Extra resin-coated sand deposited after each treatment iso-lated that interval from subsequent treatmentintervals. After all zones were treated, the oper-

ator left the well undisturbed for about 12 hoursto allow the resin to set and obtain adequatestrength. Partially cured resin-coated sand in thewellbore was drilled out prior to production.

With the exception of one well, screenlesscompletions significantly increased cumulativeoil production during nine months of evaluation(next page, left). Average failure frequencybefore CoilFRAC screenless completions was 0.5per well per month. The operator allocated 36 rigdays and 32,000 bbl [5080 m3] of deferred oil pro-duction for all four wells to clean out sand. AfterCoilFRAC screenless treatments were performed,failure frequency dropped to 0.14 per well permonth, resulting in an extra five months of oilproduction per well per year. Screenless

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16. In standard fracturing, the fracture tip is the final area to be packed with proppant. A tip-screenout designcauses proppant to pack, or bridge, near the end of thefractures in early stages of a treatment. As additionalproppant-laden fluid is pumped, the fractures can nolonger propagate deeper into a formation and begin towiden or balloon. This technique creates a wider, moreconductive pathway as proppant is packed back towardthe wellbore.

> Duri field, Indonesia, producing horizons and typical well completion.

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CoilFRAC treatments paid out in 35 to 59 days.However, the use of resin-coated sand inextremely hot steamflood conditions was foundto have limitations.

Early in the application of screenless comple-tions, the operator recognized a need to use inertproppant flowback control. The resin coating usedinitially in CoilFRAC screenless completions wasthermally stable to 375°F [191°C], but could fail insteam environments of 400°F [204°C]. As a result,periodic steam injection and flowback to stimu-late oil output could cause stress cycling andproppant-pack failure that resulted in sand pro-duction. Proppant flowback control using PropNETfibers rated to 450°F [232°C] is proving to be asolution to this problem.

The operator selected a local sand combinedwith PropNET fibers in place of resin-coated sandfor eight recent screenless completions in Durifield. The PropNET fibers were added throughout

sand-laden treatment stages to ensure completeinterval coverage. Optimized perforating tech-niques also has been introduced for screenlesssand control. These wells have minimal productiondata, but early production results are encouraging.

Milestones in Selective StimulationsSelective coiled tubing-conveyed isolation andstimulation have established a template forfuture workovers on existing wells and new wellcompletions. The CoilFRAC methodology allowscontrolled delivery and accurate placement oftreatment fluids and proppant in existing orbypassed pay intervals at little or no additionalcost because decreased fluid volumes and elimi-nation of redundant operations reduce mobiliza-tion, equipment and material charges.

CoilFRAC treatments are useful for fracturingbypassed single or multiple zones, protection ofcasing and completion equipment, and for

development of coalbed methane reserves. Thistechnique is also valuable in settings wherechemical inhibition, reservoir flow-conformancemodifications, water-control or sand-controlmethods may be required. Schlumberger haspumped more than 12,000 CoilFRAC fracturestimulations in more than 2000 wells. Coiled tub-ing-conveyed treatments can now be performedin vertical, high-angle and horizontal wells withmeasured vertical depths up to 12,200 ft [3720 m].Pumping rates can range from 8 to 25 bbl/min[1.3 to 4 m3/min] with 5 to 12 ppa of proppant.

Coiled tubing-conveyed fracturing was origi-nally developed for multilayered shallow-gasreservoirs in Canada and further developed in theUSA (above). These CoilFRAC treatments, how-ever, are being refined in applications around theworld, from Indonesia, Argentina and Venezuelato Mexico and now Algeria.

The largest total volume of proppant placed ina single wellbore was 850,000 lbm [385,555 kg]for a well treatment in northern Mexico. A well insoutheast New Mexico, USA, was the first hori-zontal well to be fracture stimulated using aCoilFRAC Mojave tool. Two separate zones at9123 and 9464 ft [2781 and 2885 m] measureddepth were treated. The deepest CoilFRAC job todate was recently performed at 10,990 ft [3350 m]for Sonatrach in Algeria. The progress to date inselective stimulations has been impressive.Continued research and field experience areexpected to further extend the range of applicationsand reach of this innovative technique. —MET

> CoilFRAC screenless completion results in Duri field, Indonesia.

> Ongoing CoilFRAC operations in Medicine Hat,Alberta, Canada.

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R. John Andrews is currently a senior staff reservoirengineer with Husky Energy Inc. in St. John’s,Newfoundland, Canada. He provides reservoir engi-neering technical expertise to support developmentplanning in relation to Husky’s East Coast assets. Hiskey responsibilities include monitoring Terra Novafield operations, reserves evaluation and manage-ment, and assistance in the development of a data-acquisition strategy for the White Rose field. Otherresponsibilities involve detailed reservoir-fluid analy-sis, equation-of-state modeling and reservoir simula-tion. John spent his first eight years in Calgary,Alberta, Canada, on reservoir engineering assign-ments involving conventional oil and gas, and heavy-oil and oil-sands projects. After returning toNewfoundland in 1989, John spent seven years as areservoir-conservation engineer with the Canada-Newfoundland Offshore Petroleum Board, and fiveyears as a senior reservoir engineer with HiberniaManagement and Development Company Ltd.(HMDC) before accepting his current position withHusky Energy Inc. in May 2001. A Committee memberfor the SPE Atlantic Canada Section for six years,John received a BS degree in mathematics from theMemorial University of Newfoundland in St. John’s,and a Bachelor of Industrial Engineering degree atTechnical University of Nova Scotia in Halifax, Canada.

Cosan Ayan, Account Manager and PrincipalReservoir Engineer for the UK, is based in Aberdeen,Scotland, where he works on interpretation and devel-opment such as transient well tests, wireline forma-tion testers, production logging and reservoirmonitoring. Previously, he held similar responsibili-ties as division reservoir engineer for SchlumbergerCentral Gulf division based in Abu Dhabi, coveringUAE, Qatar, Iran and Yemen. Cosan was also divisionreservoir engineer for Schlumberger EastMediterranean division in Cairo, Egypt (1991 to 1993).He joined the company in 1990 to work withSchlumberger Reservoir Characterization Services inDubai, UAE. During this assignment, he worked ongeological modeling and developed scaling-up algo-rithms for reservoir-simulation grid blocks. Beforejoining Schlumberger, he was an assistant professor at the Middle East Technical University in Ankara,Turkey. Cosan holds a BS degree from Middle EastTechnical University, and MS and PhD degrees fromTexas A&M University in College Station, USA, all inpetroleum engineering. The author of papers on welltesting and reservoir engineering, he is currently atechnical editor for SPE Formation Evaluation.

Gary Beck received his BS degree in geology fromHofstra University in Hempstead, New York, USA, andhis MS degree in geology from Purdue University, WestLafayette, Indiana, USA. He then joined Chevron inNew Orleans, Louisiana, USA, where he worked indevelopment geology before moving into formation

evaluation in 1988. In 1997 Gary moved to VastarResources in Houston, Texas, where he was principalpetrophysicist, Deepwater Special Projects. After BPacquired Vastar in 2000, he became a staff petrophysi-cist for BP in the North American ExplorationDeepwater Appraisal Group in Houston, Texas. Therehe is involved in all aspects of petrophysics with aspecial interest in mineral-based log analysis, capil-lary pressure, formation sampling, measurements-while-drilling and nuclear magnetic resonance. Garyhas written and presented numerous papers on vari-ous topics at SPWLA symposia and chapter meetingsand at SPE conferences, and was awarded the BestPaper Award at the 1996 SPWLA Annual Symposium.He is a past-president of the SPWLA and has servedmultiple positions on the SPWLA Board of Directorsduring the past seven years.

Melvin Cannell has been Director of the Centre forEcology and Hydrology (CEH) at Edinburgh, Scotland,since 1987. CEH is a component of the UK NaturalEnvironment Research Council (NERC). He began hiscareer in 1966 as a research scientist, and worked forthe Coffee Research Foundation in Kenya, Africa. In1971 he joined NERC as a research scientist at theInstitute of Tree Biology in Edinburgh. Three yearslater he became a senior scientist at the NERCInstitute of Terrestrial Ecology in Edinburgh.Professor Cannell holds BS, PhD and DSc degrees inagricultural botany from University of Reading inEngland. He is a Fellow of the Royal Society ofEdinburgh and a Fellow of the UK Institute ofChartered Foresters.

Kees Castelijns manages the Schlumberger DataServices Center in London, England. He joinedSchlumberger in 1977 as a wireline field engineer andspent four years in Oman, Saudi Arabia, Iran, thePhilippines, Dubai, Yemen and Egypt. In 1982 hebecame wireline location manager in Kirkuk, Iraq.After Wireline sales and marketing assignments inOman, India, Malaysia, Norway and The Netherlands,he became manager of the Data Services Center inThe Hague, The Netherlands. He transferred to theSugar Land Product Center as domain expert for thedevelopment of a thin-bed evaluation program in1994. From 1994 to 1997, he was section manager ofpetrophysics, in charge of developing and sustainingpetrophysical interpretation products, such asPrePlus*, ELAN* Elemental Log Analysis andPetroViewPlus* software. Prior to his current assign-ment, he was Schlumberger interpretation develop-ment manager, responsible for interpretation supportand new technology introduction. Kees obtained anengineering degree in applied physics from EindhovenTechnical University in The Netherlands.

Andy Chen has been a Calgary, Alberta, Canada-basedreservoir engineer with Schlumberger of Canada since1996. He earned a BS degree in 1983 and an MSdegree in 1986, both in petroleum engineering, fromEast China Petroleum Institute, and a PhD degree inmechanical engineering in 1995 from University ofManitoba, Winnipeg, Canada.

Myrt E. Cribbs is a senior reservoir engineer forTexaco Exploration in Bellaire, Texas. After receivinghis BS degree in petroleum engineering fromMississippi State University, he joined Getty Oil inNew Orleans, Louisiana. He worked as a productionand reservoir engineer until the merger with Texacoin 1984. For Texaco, he continued to work as a reser-voir engineer on shelf and deepwater properties inthe Gulf and participated in several early DeepStarsubcommittees. He also had international experienceworking on carbonates. For the last four years, he hasbeen Texaco Exploration's deepwater Gulf of Mexicoreservoir engineering specialist, responsible for data-collection plans and reservoir evaluation, while devel-oping a keen interest in downhole fluid sampling andwell testing. Recently, he has been responsible for thedesign and execution of several international deepwa-ter well tests.

Finn H. Fadnes is principal research engineer atNorsk Hydro Petroleum Research Centre, in Sandsli,Bergen, Norway. He has been involved in supervisingpressure-volume-temperature and fluid characteriza-tion since 1987. Prior to this (1983 to 1987), he was aresearch engineer and then manager of the FluidProperties department at Rogaland Research inStavanger, Norway. He has also been a visitingresearch associate in chemical engineering at RiceUniversity in Houston, Texas. Finn obtained a BSdegree in chemical engineering and an MS degree inphysical chemistry from the University of Bergen.

Jim Filas, Well Testing Joint Industry Projects (JIP)Coordinator at Schlumberger Reservoir CompletionsCenter in Rosharon, Texas, is responsible for coordi-nating various joint industry projects with clients(including the development of zero-emission well-testing technology). He is also involved in technicalcoordination between Schlumberger business seg-ments, client business development, and contract andlicense negotiation. He began his career in 1977 as aproject engineer for a manufacturing subsidiary ofSonat Offshore Drilling, where he worked on design,analysis and manufacturing management of oilfieldequipment and drilling rigs. In 1982 he became aresearch associate for Getty Oil Exploration andProduction Research Center in Houston, Texas. Twoyears later he moved to Texaco Central OffshoreEngineering in New Orleans, Louisiana, as anadvanced petroleum engineer. He joinedSchlumberger in 1984 as a senior development engi-neer for logging vehicle and hydraulic system design,structural analysis and strain gauge testing. From1992 to 1998, he was section manager for WirelineEngineering units in Houston and Austin, Texas. Priorto his current position, he was product champion forfiber-optic sensing in Paris, France. Jim earned a BS degree in engineering science at Louisiana State University in Baton Rouge, and an MS degree in mechanical engineering at University of Houston.

Contributors

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Byron Gale is currently a senior production and oper-ations engineer for Tom Brown, Inc. in Denver,Colorado, USA. His main responsibilities involve newwell completions, workovers and recompletions, andproduction operations in the Paradox and Piceancebasins, in Colorado and Utah (USA). He joined ARCOOil and Gas Company in 1986 and spent the nextdecade with them and with Vastar Resources, workingin operations and analytical engineering projects inBakersfield, California, USA, and in Midland andHouston, Texas. Before joining Tom Brown in 1997, hespent a year with WhitMar Exploration Company inDenver. Byron has a BS degree in petroleum engineer-ing from Montana College of Mineral Science andTechnology in Butte, USA.

Duane Gonzalez, a production engineer for SamedanOil Corporation in Houston, Texas, works in south andwest Texas. He joined Schlumberger Dowell in 1993 asa field engineer in Laredo, Texas and moved to theirproduction enhancement group three years later. From1996 to 1998, he was a DESC* Design and EvaluationServices for Clients engineer in Midland, Texas, work-ing with Mobil and Texaco. He performed the samefunction for Mobil and Conoco in Houston from 1998 to2000. Duane earned a BS degree in mechanical engi-neering from Texas A&M University in College Station.

Hafez Hafez, Senior Reservoir Engineer with AbuDhabi Oil Company for Onshore Oil Operations(ADCO) in the United Arab Emirates, deals with reser-voir modeling, performance and management.Previously, he spent five years with the Gulf of Suez OilCompany in Egypt as an operations and reservoir engi-neer involved in different aspects of reservoir engi-neering. Hafez received a BS degree from University ofCairo in Egypt and has written several SPE papers onwaterflooding and permeability distribution.

Scott Hall, Team Leader, ChevronTexaco, is based inDenver, Colorado, where he manages new drilling andworkover opportunities in Wyoming, USA. He joinedthe company in 1981 as a field engineer. He becameproduction supervisor in 1984, and a production engi-neer in 1985. From 1986 to 1987, he was a reservoirengineer, and then became assistant to the vice presi-dent of exploration (1988 to 1990). For the next twoyears he was a drilling engineer before moving to pro-duction engineering (1993 to 1994). He spent fouryears as an asset-team engineer, before assuming hiscurrent position as team leader for Wyoming in 1999.Scott holds a BS degree in civil engineering fromUniversity of Colorado in Boulder. He served as an SPEDistinguished Lecturer in 1997.

John Harries, Professor and Chair of EarthObservation at Imperial College of Science,Technology and Medicine in London, England, hasheld his current position since 1994. As a teacher andresearcher, he heads the Space and AtmosphericPhysics research group. In 1972, after receiving a BSdegree (Hons) in physics from University ofBirmingham, England, and a PhD degree from King’sCollege in London, he was appointed senior scientificofficer at the National Physical Laboratory (NPL).Three years later he became principal scientific officerand head of the Environmental Standards group atNPL. In 1980 he was appointed senior principal scien-tific officer and head of the Remote Sounding divisionat Appleton Laboratory. Four years later he became

deputy chief scientific officer and head of theGeophysics and Radio division, Rutherford AppletonLaboratory, becoming the laboratory’s associate direc-tor and head of the space science department in 1986.Since 1985 he has been a member of the HALOEInternational Science team, and since 1995 has beenprincipal Investigator for the Geostationary EarthRadiation Budget (GERB) experiment. Author of manybooks and papers, he has also served as president ofthe International Radiation Commission (1992 to1996), president of the Royal Meteorological Society(1994 to 1996), and as a member of NERC Council andchair of Earth Observation Science & TechnologyBoard (1995 to 1997).

Mohamed Hashem, Global Consultant and StaffPetrophysical Engineer for Shell Deepwater Services,is based in New Orleans, Louisiana. His projects spanthe globe and involve advising on fluid sampling andpressure testing for Shell's projects worldwide, withmore than 100 sampling jobs and eight years of MDT*Modular Formation Dynamics Tester developmentexperience. He joined Shell in 1990, and worked fiveyears in exploration and production as a petrophysicalengineer for the Shelf Division. Following that, heworked on Gulf of Mexico deepwater exploration,development and production projects. He workedextensively in the Garden Banks area of the Augerbasin, with three major developments and three dis-coveries. Previously, he worked for Schlumberger invarious Middle Eastern and European locations as wellas in California; he also taught formation evaluation atUniversity of Southern California in Los Angeles.Author of numerous publications, he received theSPWLA Best Paper Award in 1998. Mohamed earned aBS degree in mechanical engineering from Ain ShamsUniversity in Cairo, Egypt; an MS degree in petroleumengineering from University of Southern California inLos Angeles; and an engineer’s degree in petroleumengineering from Stanford University in California.

Sharon Hurst, Senior Reservoir Project DevelopmentEngineer, Bohai Commercial Group, Phillips ChinaInc., is responsible for engineering support of explo-ration activities in Bohai Bay, China, including projectevaluation and economics, as well as cased-hole log-ging and well-testing design, supervision and analysis.She joined Phillips in Houston, Texas, in 1987 as areservoir and production engineer in the Gulf Coastand areas across the USA (1987 to 1992). From 1994 to1997, she was a reservoir and operations engineer forthe eastern Gulf of Mexico. She then served two yearsas company well-test specialist at Phillips ResearchCenter in Bartlesville, Oklahoma, USA. Prior to hercurrent position, she was an international explorationengineer, based in Bartlesville (1999 to 2000). In addi-tion to her other assignments, she has served as explo-ration and well-test engineer and supervisor in Alaska(USA), the Gulf of Mexico, Venezuela and China (1992to 2000). Sharon obtained a BS degree from theUniversity of Texas at Austin, and an MS degree fromthe University of Houston, both in petroleum engineering.

Jamie Irvine-Fortescue, Norsk Hydro ASA ProductionTechnology Discipline Manager for Njord field, is basedin Bergen, Norway. There he is responsible for all pro-duction technology work including production opti-mization. He began his career with BP Exploration in1984 and for the next eight years held various posi-tions including petroleum engineer, field production

engineer, commissioning engineer and productionengineer in Scotland, England and Norway. Since 1993he has been with Norsk Hydro as a completion tech-nologist and production technologist in Oslo, Norway,and as manager and advisor for well testing in Bergen.Jamie received a degree in mechanical engineeringfrom Robert Gordon's Institute of Technology inAberdeen, Scotland, and a BS degree in petroleumengineering from Imperial College in London,England. Author of many papers, he has served asmembership chairman and director of the BergenSection of the SPE.

A. (Jamal) Jamaluddin, Fluid Analysis BusinessManager-Worldwide, works at Oilphase, a division ofSchlumberger in Houston, Texas. His main responsibil-ity is developing the company’s reservoir-fluid analysisbusiness globally. He began his career as a researchscientist at Noranda Technology Centre in Montreal,Quebec, Canada, in 1990. For the next six years heserved as project leader and then program leader onprojects related to oil and gas research and technologydevelopment. Prior to assuming his current position in1998, he was director of technical services at HycalEnergy Research Laboratories in Calgary, Alberta,Canada. Jamal earned a BS degree in petroleum engi-neering from King Fahad University of Petroleum andMinerals, Dhahran, Saudi Arabia, and MS and PhDdegrees in chemical engineering from the University ofCalgary. He is a coinventor of five patented processesrelated to petroleum production and optimization andhas coauthored more than 70 technical papers on vari-ous subjects.

Geoff Jenkins, Head of the Climate PredictionProgramme at the Hadley Centre for ClimatePrediction and Research in Berkshire, England, hasheld his current position since 1995. Previously, heheld another post at the center and at the UKDepartment of the Environment. Dr. Jenkins obtainedBS and PhD degrees in physics from University ofSouthampton in England.

Fikri Kuchuk, Schlumberger Fellow, is chief reservoirengineer for Schlumberger Oilfield Services in theMiddle East and Asia. Previously, he was senior scien-tist and program manager at Schlumberger-DollResearch, Ridgefield, Connecticut, USA. From 1988 to1994, he was a consulting professor in the PetroleumEngineering department of Stanford University inCalifornia. Before joining Schlumberger in 1982, heworked on reservoir performance and management forBP/Sohio Petroleum Company. He has an MS degreefrom Technical University of Istanbul, and MS and PhDdegrees from Stanford University, all in petroleumengineering. Fikri received the SPE 1994 ReservoirEngineering, SPE 2000 Formation Evaluation, and SPE2001 Regional Service Awards. In 1995, he was electedto the Russian Academy of Natural Sciences andreceived the Nobel Laureate Physicist Kapitsa GoldMedal. In 1996, he was named SPE DistinguishedMember and received Henri G. Doll Award in 1997 and1999. He is currently SPE International Director-at-Large, SPE Northern Emirates Section Director and amember of many SPE committees. A prolific author, hehas been associate editor of Journal of PetroleumScience and Engineering since 1994, Turkish Journalof Oil and Gas since 1996, and editor of Middle EastReservoir Review since 1996.

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Andrew Kurkjian, Schlumberger Customer Needsand Product Strategy Manager in Sugar Land, Texas,assesses client needs to determine an appropriateproduct development strategy. In 1982 he joinedSchlumberger-Doll Research in Ridgefield,Connecticut, as a research scientist. There he wasprincipal inventor of the DSI* Dipole Shear SonicImager tool. From 1988 to 1990, he was engineeringmanager for cross-well seismic development atSchlumberger Riboud Product Center in Clamart,France. He then moved to Schlumberger CambridgeResearch in England where he headed borehole seis-mic research. Since 1993 he has been involved withthe MDT tool as principal authority on fluid samplingand is also a coinventor of the CHDT* Cased HoleDynamics Tester tool. Andrew earned a BS degree inelectrical engineering from Catholic University inWashington, DC, USA, and MS and PhD degrees, alsoin electrical engineering, from MassachusettsInstitute of Technology in Cambridge, USA.

Larry W. Lake is a professor in the Department ofPetroleum and Geosystems Engineering at TheUniversity of Texas (UT) at Austin. He holds BSE andPhD degrees in chemical engineering from ArizonaState University in Tempe, USA, and Rice University inHouston, respectively. Dr. Lake has published widely;he is the author or coauthor of more than 100 techni-cal papers, the editor of three bound volumes andauthor or coauthor of two textbooks. He has beenteaching at UT for 22 years prior to which he workedfor the Shell Development Company in Houston,Texas. He has served on the Board of Directors for theSociety of Petroleum Engineers (SPE) as well as onseveral of its committees; he has also been an SPEdistinguished lecturer. Among his many honors andawards are the Shell Distinguished Chair, 1996Anthony F. Lucas Gold Medal of the SPE, 1998Election to the National Academy of Engineers andthe 2000 IOR Pioneer Award from the SPE.

Jack Marsh, Vice President of Engineering andBusiness for Olympia Energy Inc. in Calgary, Alberta,Canada, has been with the company since 1994. He isresponsible for all facets of production and reservoirengineering as well as business development, assetmanagement and evaluation. Previously, from 1976 to1994, he worked for Imperial Oil (an Exxon affiliate)in Calgary, in positions such as wellsite geologicaltechnologist, production and drillstem testing tech-nologist, business development engineer and fieldproduction engineer. He earned a diploma in earthsciences from the Northern Alberta Institute ofTechnology in Edmonton, Alberta, Canada, and a BSdegree in chemical engineering from the University ofCalgary. A director of the Canadian Gas ProcessorsAssociation, Jack is also a registered member of theAlberta Professional Engineers Geologist andGeophysicist Association.

Oliver C. Mullins received a BS degree in biologyfrom Beloit College in Wisconsin, USA, and MS andPhD degrees in chemistry from Carnegie-MellonUniversity, Pittsburgh, Pennsylvania, USA. After hold-ing a research position in chemistry at the Universityof Chicago, Illinois, USA, and in physics at theUniversity of Virginia in Charlottesville, USA, hejoined Schlumberger-Doll Research (SDR),Ridgefield, Connecticut in 1986. He is a principal con-tributor to the OFA* Optical Fluid Analyzer, the SASSpectral Analysis System, the LFA* Live FluidAnalyzer and to other projects currently in field test-ing. Oliver is currently a principal research scientist,manager of the MDT program at SDR and FlowAssurance Theme champion. He has coauthored about50 articles in refereed journals, is coholder of 14 USpatents and has coedited two books on asphaltenes.

Aubrey O’Callaghan, Principal Reservoir Engineerwith Schlumberger GeoQuest in Puerto La Cruz,Venezuela, provides technical support for reservoirstudies. His current interests include dynamic reser-voir characterization through numerical simulationand well testing. He also maintains an interest in hori-zontal well evaluation and advances in production log-ging. Since joining Schlumberger in 1979 as a fieldengineer in Norway, he has held many technical posi-tions during his 22 years with the company. He hasmanaged the Schlumberger Training Center in Parma,Italy. In Nigeria and later Algeria, he was in charge ofdynamic reservoir studies and reservoir simulation.Aubrey obtained a BS degree in engineering scienceand an MS degree in mathematics from The Universityof Dublin, Trinity College, Ireland. He also holds anMS degree in petroleum engineering from Heriot-WattUniversity in Edinburgh, Scotland.

Martin Parry was appointed professor ofEnvironmental Science and director, JacksonEnvironment Institute at the University of East Angliain Norwich, England in 1999. From 1995 to 1999, hewas professor of Environmental Management atUniversity College in London; professor ofEnvironmental Management, and director of theEnvironmental Change unit at the University ofOxford (1992 to 1995); and professor ofEnvironmental Management, University ofBirmingham, England (1990 to 1992). He received aBA degree from University of Durham, England; an MSdegree from University of the West Indies; and a PhDdegree from University of Edinburgh in Scotland. Hereceived the Order of the British Empire (OBE) in1998 for services to the environment and to climatechange. He was also awarded the WorldMeteorological Organization's Gerbier-MummInternational Award in 1993, and the RoyalGeographical Society's Cuthbert Peek Award in 1991,both for contributions to research on climate change.

John Peffer, Reservoir Manager, Groupement Berkine(Sonatrach/Anadarko Association), is based in HassiMessaoud, Algeria. Since joining Anadarko in 1985, hehas held various reservoir engineering positions withthe company in Midland, Texas (1985 to 1989, and

1994 to 1996); Algiers, Algeria (1990 to 1993); andLondon, England (1997 to 1998). He has been basedin Hassi Messaoud since 1999 in a management role.John earned BS and MS degrees in petroleum engi-neering at University of Texas at Austin.

Julian Pop, an engineering advisor withSchlumberger Oilfield Services in Sugar Land, Texas,is involved in algorithm development for the MDT tooland design and specification of wireline formationtester interpretation-software products. Since joiningthe company in 1979, he has had technical and man-agerial involvement in interpretation developmentprojects for completion and formation testers andmanagement of tool and interpretation software. Healso has taught at University of Texas at Austin and atRice University in Houston. Julian holds a BS degreein mechanical engineering from the University ofMelbourne, Victoria, Australia, and an MS degreefrom the Johns Hopkins University, Baltimore,Maryland, USA, and a PhD degree from Rice University.

Paul Rutter, BP Group Senior Advisor onEnvironmental Technology at the BP TechnologyCentre in Sunbury on Thames, Middlesex, England,has held his current post since 2000. He maintainsstrong links with Imperial College in London, andPrinceton University in New Jersey, USA, and hasbeen involved in a number of UK government researchcommittees and advisory panels. He received a BSdegree (Hons) in chemistry and a PhD degree atUniversity of Leeds in England in 1972. After that heworked mainly in industrial research on various pro-jects centered on physical chemistry: toiletries devel-opment with Boots, oral microbiology with Unilever,and biocompatible materials as a research fellow atthe London Hospital Medical School. He joined BP in1981 to develop alternative fuels using coal. He thenworked in minerals processing and became managerof the BP Mineral Processing R&D group in 1987. In1990 he moved to BP Exploration technology as man-ager of the Production Operations branch. He startedBP’s produced water network in 1992. In 1998 he com-bined the group’s environmental technology programsinto “Green Operations.” This technology network andresearch program covers the three BP group strategicareas of climate change, water and biodiversity, aswell as technology programs specific to the individualbusiness streams. The network now has over 1200active members throughout the company’s globaloperations.

Erik Rylander, MDT Field Service Manager,Schlumberger Gulf Coast Special Services, is based inBelle Chasse, Louisiana. He joined the company in1995 as a junior field engineer in Duncan, Oklahoma,and then moved to Equatorial Guinea and Nigeria as afield engineer (1996 to 1997). He spent the next fouryears as a MDT specialist field engineer with GulfCoast Special Services before taking his current posi-tion in 2001. Erik holds a BS degree in engineeringwith an electrical specialty from Colorado School ofMines in Golden.

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Bill Sass has been a software engineer at theSchlumberger Sugar Land Product Center in Texassince 1995. He has worked on wellsite MDT interpreta-tion software and is responsible for the development ofthe OCM* Oil-Base Contamination Monitor product.He joined Schlumberger as a field engineer in 1981,after receiving a BS degree in mechanical engineeringfrom the University of Western Ontario in London,Ontario, Canada in 1981.

Lars Sonneland is research director at SchlumbergerStavanger Research in Norway, where the focus is ongeophysical reservoir characterization and monitoring.After receiving a degree in mathematics, computer sci-ence and physics and a PhD degree in applied mathe-matics from the University of Bergen, Norway, hejoined GECO in 1974. He had various technical assign-ments in geophysical applications until 1989 when hetransferred to Schlumberger-Doll Research,Ridgefield, Connecticut. From 1990 to 1998, he hadseveral technical management positions withinSchlumberger. He transferred to SchlumbergerCambridge Research (1999 to 2000). At the same time,he helped establish Schlumberger StavangerResearch. Lars has published more than 70 scientificpapers and holds a number of patents. Recipient of theNorwegian Association of Chartered Engineers'Technical Award and the Norwegian GeophysicalAward, Lars has played a major role in the develop-ment of 3D seismic technology, the Charisma* seismicinterpretation software system and seismic reservoircharacterization and monitoring.

Alexandra Van Dusen is currently pursuing a PhDdegree in geochemical oceanography in theDepartment of Earth and Planetary Science at HarvardUniversity, Cambridge, Massachusetts. Prior to this,from 1997 to 2000, she worked for SchlumbergerOilfield Services as a wireline logging engineer first inBakersfield, California, and then in Bergen, Norway.She is a graduate of Princeton University, New Jersey,with a BA degree in geological sciences.

Jeremy Walker, Schlumberger Well Completions andProductivity, Testing & Completions MarketingManager, is based in Houston, Texas. There he hasbeen responsible for development of the marketingplan and strategy for testing services since 1999. Hebegan his career in 1980 as a field engineer withFlopetrol International in The Netherlands. From 1982to 1984, he was field service manager for well testingin Al-Khobar, Saudi Arabia. Subsequent assignmentsincluded location manager for well testing inAberdeen, Scotland; sales engineer for well testing inWest Africa; staff technical engineer, testing and pro-duction services for Africa and the Mediterraneanregion; district manager, Schlumberger Wireline &Testing in Hassi Messaoud, Algeria and in PortHarcourt, Nigeria; business manager for productionservices in Paris, France; district manager, testing inAberdeen, Scotland; and business development man-ager for testing in Aberdeen. Jeremy earned a BSdegree (Hons) in mechanical engineering from theCity University of London, England.

Stephen Williams works for Norsk Hydro ASA inBergen, Norway, as technical advisor for logging. He isresponsible for planning, execution and follow-up offormation evaluation programs on Norsk Hydro wellsas well as related contracts. He has held this positionsince he joined the company in 1998. Prior to this, hespent 14 years with Schlumberger in various assign-ments in operations, technical management, training,and management in North and South America, Europe,Scandinavia and the Middle East. Stephen earned BAand MA degrees in natural sciences from University ofCambridge in England.

Warren Zemlak earned associate degrees fromRobertson and Kelsey Institutes in Saskatchewan,Canada. He began his oilfield experience with a majordrilling contractor prior to joining Schlumberger in1989. His career has included both field and technicalassignments throughout Canada in well cementing,stimulation and coiled tubing. He was project leader inseveral of the first directional underbalanced coiledtubing drilling applications and was a member of theteam that installed the first high-pressure coiled tub-ing offshore the east coast of Canada. In 1996 he pio-neered the first application of multizone fracturingthrough coiled tubing. Currently based in Sugar Land,Texas, Warren is CoilFRAC* business developmentmanager, responsible for the worldwide implementa-tion and development of multizone stimulation techniques. The author of several SPE papers, he holds patents specific to multizone stimulation andisolation tools.

Murat Zeybek, Senior Reservoir Interpretation andDevelopment Engineer for Schlumberger OilfieldServices in Saudi Arabia, Bahrain and Kuwait, workson interpretation of wireline formation testers, pres-sure-transient analysis, numerical modeling, watercontrol, production logging and reservoir monitoring.Before this, he was the Schlumberger district reservoirengineer in Doha, Qatar. He was a research associatein the Petroleum Engineering department of theUniversity of Southern California in Los Angeles from1991 to 1992 and also worked for Intera WestConsulting in California. Before joining Schlumberger,he worked as an assistant professor at TechnicalUniversity of Istanbul in Turkey. He served as a com-mittee member for 1999-2001 SPE Annual TechnicalConference and Exhibition and has written manypapers about fluid flow through porous media andpressure-transient analysis. Murat holds a BS degreefrom Technical University of Istanbul, and MS and PhDdegrees from University of Southern California, all inpetroleum engineering.

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

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Coming in Oilfield Review

Advances in Borehole Imaging.Operating environments for E&Pcompanies have become moredemanding. Oil-base and synthetic-base muds have addressed many ofthe challenges endemic to theseareas. But because these muds arenonconductive, borehole-imagingoptions are limited. A new tool thatcombines innovative technologywith the time-honored principle of resistivity logging providesmicroresistivity images in thesedifficult environments.

Well and Platform Abandonment.As abandonment of aging wellsand fields becomes more frequent,responsible operators must balanceenvironmental and financial objec-tives. Remediation of deficientplugging and abandonment (P&A)operations exacts a toll on boththe environment and the company’sfinancial performance. Many oper-ators are revising their P&A proce-dures to ensure that abandonedreservoirs are permanently sealed. In this article, we review P&A anddecommissioning practices and new technologies that bring newmeaning to the “permanent”aspects of P&A work.

Seismic Depth Imaging. In manyof today’s hot exploration areas, especially where faulting and saltstructures lead to complex seismicvelocities, traditional time-domainprocessing gives misleading results;only depth imaging reveals the truelocation and shape of subsurfacefeatures. This article explains depth imaging and presents exam-ples showing how oil and gascompanies use it to improve theirsuccess rates.

Lifelong Reservoir ManagementUsing the Web. In the new inter-net-enabled economy, the ability toact quickly with up-to-the-minuteinformation provides a businessadvantage. Web-based tools assistin portfolio management, includingacquisition and divestiture activi-ties. Collaboration among multidis-ciplinary teams and with partners,service providers and governmentalbodies is possible with data storedon secure servers. Accessing appli-cations across the net allows workto be done from anywhere, at anytime, and creates new ways forteams to accomplish tasks. Thisarticle describes tools that improvereservoir management throughoutits life.

GeoComputationStan Openshaw and Robert J. AbrahartTaylor & Francis29 West 35th StreetNew York, New York 10001 USA2000. 413 pages. $85.00ISBN 0-7484-0900-9

The book is a compilation of essays onthe specialties that geocomputationcomprises: computer technology,leading-edge mathematics, visualanalysis and modeling.

Contents:

• GeoComputation

• GeoComputation Analysis and Modern Spatial Data

• Parallel Processing in Geography

• Evaluating High PerformanceComputer Systems from aGeoComputation Perspective

• GeoComputation Using CellularAutomata

• Geospatial Expert Systems

• Fuzzy Modelling

• Neurocomputing—Tools forGeographers

• Genetic Programming: A NewApproach to Spatial Model Building

• Visualization as a Tool forGeoComputation

• Spatial Multimedia

• Fractal Analysis of Digital Spatial Data

• Cyberspatial Analysis: AppropriateMethods and Metrics for a NewGeography

• Integrating Models and GeographicalInformations Systems

• Limits to Modelling in the Earth andEnvironmental Sciences

• GeoComputation Research Agendasand Futures

• Index

…this book provides a completemap to the road that geocomputation is taking to mature into a full-fledgeddiscipline.

Spencer LT: Choice 38, no. 5 (January 2001): 936.

Combustion and Gasification of CoalA. Williams, M. Pourkashanian,J.M. Jones and N. Skorupska

Taylor & Francis29 West 35th StreetNew York, New York 10001 USA2000. 263 pages. $115.00ISBN 1-56032-549-6

The text provides information on new technology that may impact theenvironmental effects of coal gener-ation. Other topics are pollution and itscontrol and coal-gasification technology.

Contents:

• An Overview of the EnergyContribution of Coal

• Properties of Coal

• Pollutant Formation and Methods of Control

• Combustion Mechanism of Pulverized Coal

• Combustion Mechanism of CoalParticles in a Fixed, Moving, orFluidized Bed

• Industrial Applications of Coal Combustion

• Two-Component Coal Combustion

• Coal Gasification Processes

• References, Appendices, Index

Throughout, the writing is at a level that should be understandable by general readers with modest back-grounds in chemistry.

It is amply illustrated with tablesand charts….Extensive referencelist…. A very good introduction to the field.

Wenzel LA: Choice 38, no. 5 (January 2001): 937.

Sedimentology and SedimentaryBasins: From Turbulence to TectonicsMike LeederBlackwell Science, Inc.350 Main StreetMalden, Massachusetts 02148 USA1999. 620 pages. $56.00 ISBN 0-632-04976-6

The book provides explanation of thephysical and chemical processes thatcontrol the deposition of sediments. Anintroductory chapter gives perspectiveon how the discipline of sedimentologyfits into general earth science study.

Contents:

• Introduction

• Origin and Types of Sediment Grains

• User’s Guide to Sedimentological Fluid Dynamics

• Sediment Transport and Sedimentary Structures

• External Controls on SedimentDerivation, Transport and Deposition

• Sediment Deposition, Environ-ments and Facies in Continental Environments

• Sediment Deposition, Environmentsand Facies in Marine Environments

• Sedimentology in Sedimentary Basins

• References, Index

If you need an up-to-date, compre-hensive overview of depositional pro-cesses and the resulting sediments...[the book] is an excellent value and agood buy for its price.

...my fundamental criticism: it contains a fantastic amount of knowl-edge...but the book provides the readerwith neither the tools nor the perspec-tive on how to use that knowledge for a clear, practical purpose.

Van De Graaff WJE: Journal of Sedimentary

Research 70, no. 4 (July 2000): 970-971.

82 Oilfield Review

NEW BOOKS

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Gas Migration—Events Preceding EarthquakesLeonid F. Khilyuk, George V. Chilingar,Bernard Endres and John O.Robertson, Jr.Gulf Publishing CompanyP.O. Box 2608Houston, Texas 77252 USA2000. 389 pages. $125.00ISBN 0-88415-430-0

The 27 chapters in this volume coverkey themes on gas migration and itsrelation to seismic events. Included areorigins and sources of gas, migration ofnatural gas from petroleum reservoirs,and prediction of land subsidence andearthquakes based on informationabout the rates and contents ofmigrating gases.

Contents:

• Tectonics and Gas Migration

• Events Preceding Earthquakes

• Principles of Gas Migration

• Interrelationships Among Subsidence,Gas Migration, and Seismic Activity

• References, Indexes

The book provides a powerful con-ceptual basis and methodologies forunderstanding and predicting naturaldisasters and environmental hazards. It is very important for environmentalengineers and scientists, civil engi-neers, petroleum geologists and engi-neers, seismologists, urban plannersand students of related specialties.

Islam R: Journal of Petroleum Science and

Engineering 29, no. 1 (January 2001): 83-84.

Applied Sedimentology, 2nd EditionRichard C. SelleyAcademic Press525 B Street, Suite 1900San Diego, California 92101 USA2000. 523 pages. $82.50ISBN 0-12-636375-7

The book has a strong emphasis on theapplications of sedimentology, especiallyin the search for natural resources. The three main sections discuss thegeneration of sediments, sedimentaryprocesses and structures, and thetransformation of sediment into rock.

Contents:

• Introduction

• Weathering and the Sedimentary Cycle

• Particles, Pores, and Permeability

• Transportation and Sedimentation

• Sedimentary Structures

• Depositional Systems

• The Subsurface Environment

• Allochthonous Sediments

• Autochthonous Sediments

• Sedimentary Basins

• Index

Its descriptions of the industrialapplications of sedimentology andstratigraphy are found in few otherbooks and will have considerable valuefor undergraduate and graduate stu-dents in the earth sciences.

With its emphasis on the “practi-cal,” there is considerably more mate-rial on issues such as porosity andpermeability and far less on historicalpatterns of sedimentation….

The writing is unnecessarily cur-mudgeonly, bordering on rude, withremote sensing geologists termed“mouse-masters,” interpretive dia-grams “geophantasmograms,” andeven an imaginary trace fossil calledan “orgasmoglyph.”…Nevertheless, an important contribution.

Wilson MA: Choice 38, no. 5 (January 2001): 936.

Advances in Hydrogen EnergyCatherine E. Grégoire Padró and Francis Lau (eds)Kluwer Academic/Plenum Publishers233 Spring StreetNew York, New York 10013 USA 2000. 192 pages. $90.00ISBN 0-306-46429-2

The book contains 14 papers presentedat the 1999 American Chemical SocietySymposium on Hydrogen Production,Storage and Utilization, held in NewOrleans, Louisiana, USA. An introductionincludes discussion of the problem ofcarbon dioxide emission and potentialmethods of mitigation.

Contents:

• Hydrogen from Fossil Fuels WithoutCO2 Emissions

• Hydrogen Production from WesternCoal Including CO2 Sequestration and Coalbed Methane Recovery: Economics, CO2 Emissions, and Energy Balance

• Unmixed Reforming: A Novel Autother-mal Cyclic Steam Reforming Process

• Fuel Flexible Reforming of Hydrocar-bons for Automotive Applications

• The Production of Hydrogen from Methane Using Tubular Plasma Reactors

• A Novel Catalytic Process for Generat-ing Hydrogen Gas from Aqueous Borohydride Solutions

• Production of Hydrogen from Biomassby Pyrolysis/Steam Reforming

• Evaluation and Modeling of a High-Temperature, High-Pressure, HydrogenSeparation Membrane for EnhancedHydrogen Production from the Water-Gas Shift Reaction

• A First-Principles Study of HydrogenDissolution in Various Metals and Palladium-Silver Alloys

• Investigation of a Novel Metal HydrideElectrode for Ni-MH Batteries

• Hydrogen Storage Using Slurries ofChemical Hydrides

• Advances in Low Cost Hydrogen Sensor Technology

• The Application of a Hydrogen RiskAssessment Method to Vented Spaces

• Modeling of Integrated RenewableHydrogen Energy Systems for RemoteApplications

• Index

In general, Advances in HydrogenEnergy presents a very useful andreadable collection of articles. Thisbook potentially is very helpful toresearchers, students, and engineers of the field of hydrogen energy systems.

Yürüm Y: Energy and Fuels 15, no. 3

(May/June 2001): 767.

Autumn 2001 83

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Autumn 2001

Characterizing Permeability

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Global Warming

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Oilfield Review

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