4

PLATFORMEXPRESS equip-ment hangingin the derrickand ready togo downhole in Bakersfield,California, USA.In this region of1200-ft [360-m]wells, reduc-tions in rig timeand rathole arecutting loggingcosts 20 to 30%.New measure-ments andanswer prod-ucts are lead-ing to betterdetection ofbypassed pay and moreefficient steamdrivestrategies.

A First Look atPLATFORM EXPRESS Measurements

For more than 20 years, the triple combo has provided fundamental

formation evaluation in wells worldwide. Now the next generation of

wireline technology has arrived, addressing industry’s growing demand

for diverse, high-quality data and greater operational efficiency.

Alison GoligherMontrouge, France

Bill ScanlanBakersfield, California, USA

Eric StandenClamart, France

A.S. (Buddy) WylieSanta Fe Energy ResourcesBakersfield, California

For help in preparation of this article, thanks to JohnAmedick, Wireline & Testing, Buenos Aires, Argentina;Rob Badry, John Kovacs and Curtis MacFarlane, Wireline& Testing, Calgary, Alberta, Canada; Ashok Belani,Charles Currie, Henry Edmundson and Stuart Murchie,Wireline & Testing, Montrouge, France; VincentBelougne, Ollivier Faivre, David Hoyle, Laurent Jammes,Wireline & Testing, Clamart, France; Mark Bowman,Phillips Petroleum, Amarillo, Texas, USA; Charles Case,Darwin Ellis, Charles Flaum, Paul Gerardi and MichaelKane, Schlumberger-Doll Research, Ridgefield, Connecticut, USA; John Cunniff, Wireline & Testing,Midland, Texas; Bill Diggons and Stephen Whittaker,Schlumberger Oilfield Services, Sugar Land, Texas;Michael Garding, Wireline & Testing, Liberal, Kansas,USA; Jim Hemingway and Pete Richter, GeoQuest, Bak-ersfield, California; John McCarthy and Mark Rixon,Wireline & Testing, Oildale, California; Bob Mitchell,Wireline & Testing, Amarillo, Texas; Dwight Peters, Wireline & Testing, Sugar Land, Texas.AIT (Array Induction Imager), FMI (Fullbore FormationMicroImager), Litho-Density, MAXIS Express, MDLT(Dual Laterolog Tool), MicroSFL and PLATFORM EXPRESS aremarks of Schlumberger.

90 ft[27 m]

38 ft[12 m]

Specification

Length, ft (m) typic

1

3

3

8

Weight, lbm (kg)

OD, in.

Temperature rating, °F (°C)

Pressure rating, psi

Max logging speed, ft/hr (m/hr)

Tripl

Summer 1996

Low oil prices over the last decade haveforced a steady improvement in the effi-ciency of oilfield operations. This efficiencycontinues to evolve in two ways—gradually,like a river continuously reshaping itscourse, and suddenly, like a river overflow-ing and cutting a new channel that redirectsits course. Every so often, an abrupt jump inefficiency comes from a new technologythat increases productivity. In wireline log-ging, the latest catalyst of such a leap is therecently introduced PLATFORM EXPRESS tech-nology—a wireline instrument thataddresses the industry’s demand not only forefficiency, but also for improved reliability,flexibility and accuracy (previous page).

The PLATFORM EXPRESS name explains thetechnology’s most striking departures fromconvention. Platform because multiplefunctions are integrated into a single pack-age and sensors are interlaced on the samesonde, rather than assembled as a series ofseparate, connectable units. As a result, themeasurement package is less than half thelength of a conventional triple combo—38 ft [12 m] versus 90 ft [27 m]—and, at690 lbm [311 kg], about half the weight(below and right). Express because nearly

(continued on page 7)

■■Light is good, short is better. The shorterlength and lighter weight of PLATFORMEXPRESS equipment (right) compared to theconventional triple combo logging stringare made possible by integration of sensorsand telemetry equipment. Specifications ofthis technology allow it to be used in 90%of operations worldwide.

ally 90 (27) 38 (12)

500 (675) 690 (311)

3/8 to 4 1/2 3 3/8 to 4 5/8

50 (175) 250 (120)

20,000 10,000

00 (540) 3600 (1080)

e combo PLATFORM EXPRESS

5

6 Oilfield Review

■■A sample of PLATFORM EXPRESS presenta-tions.Track 1: Conventional track 1 data,including a water saturation, Sw, calculation. Gamma ray backup is used to find zones that are more radioactivethan normal. Typically, the backup isscaled 100 to 200 API units when the trackis scaled 0 to 100 units.Track 2: Calculated micronormal andmicroinverse curves, from the microresis-tivity measurement. Separation (arrows) isa qualitative permeability indicator sinceit occurs in front of mudcake, which accu-mulates at permeable intervals.

Tracks 3 and 4: AIT Array InductionImager logs, comparing 90- and 10-in.resistivity readings with the 4-ft verticalresolution 90-in. conductivity reading andthe microresistivity log. Conductivity canbe easier to read when values reachextremes, and is helpful in making com-parisons to old logs. Track 4 shows all fivedepths of investigation for the inductionlog and Rxo with an 18-in. [45-cm] verticalresolution for easier comparison withinduction measurements. Vertical resolu-tion of the Rxo measurement can be asgood as 1 in.

Track 5: Real-time resistivity-derived dipfrom the PLATFORM EXPRESS laterolog (red)and FMI Fullbore Formation MicroImagermeasurements (black). The two tracks ofdensely spaced color stripes are laterolog-derived images. The first image is the second derivative of the log curve, inwhich color changes indicate bed bound-aries that are used to compute dip. Thenext image is normalized to show bedding.These images help estimate structural dip trends.

■■Comparison of logging time expenditure before and after initiation of PLATFORM EXPRESS services (left) and rig time comparison of triplecombo versus PLATFORM EXPRESS services averages for land and offshore wells (right). In the Phillips-Schlumberger alliance in the TexasPanhandle, average time in hole with conventional logging was 9.5 hours and with PLATFORM EXPRESS equipment 3.7 hours, a savings of5.8 hours in rig time per well. “Once the logging tool is on bottom, we know within minutes if we’re going to set pipe,” said Mark Bow-man, a geologist with Phillips, “whereas before, we had another 6 to 8 hours of logging before we’d even begin printing the logs.” Someoperators have achieved greater time savings by using PLATFORM EXPRESS log quality measurements to justify elimination of routinerepeat sections.

Converted to PLATFORM EXPRESSon 8/15/95

Triple Combo vs. PLATFORM EXPRESS Logging Time

Phillips-Schlumberger Alliance

0

2

4

6

8

10

12

14

16

Hou

rsTriple Combo vs. PLATFORM EXPRESS Rig Time

Average lost time

Repeat section

Calibration

Logging time

Rig up/down

Drill rathole

Land Offshore

Hou

rs

0

TripleCombo

PLATFORM

EXPRESS

PLATFORM

EXPRESS

TripleCombo

7

6

5

4

3

2

1

1 2 3 4 5 6 7 8

■■Torture chamber,Clamart, France.Bernard Brefort,mechanical techni-cian, securing awireline tool into amachine that per-forms shock testingon PLATFORM EXPRESSequipment, prior tostart-up of a test(top). The blue I-beam movesrepeatedly up anddown, subjectingtool electronics tothousands of 250-gshocks (bottom).These qualificationcriteria are similarto those used forlogging-while-drilling equipment.(In the bottomphoto, the top of theshock chamber isopen for the photo-graph, but is nor-mally closed forsafety and noiseabatement.)

all operations take less time (previous page,top). Shorter tool length saves time drillingrathole and in rigging up and down; newtechnology speeds calibration and doubleslogging speed; faster, more comprehensivereal-time data processing reducesturnaround time and provides answers pre-viously unobtainable at the wellsite.

During the initial commercialization ofPLATFORM EXPRESS, reliability was five timesthat of conventional technology, mainly dueto shock-resistant designs adapted from log-ging-while-drilling equipment developed byAnadrill (right). Greater flexibility is both lit-eral and figurative. Two hinge joints com-bined with the shorter 38-ft length allowmore successful logging of higher angleholes and provide new opportunities to logthe increasing number of short-radius wells.The articulated pad, which is also shorterthan previous designs, improves sensorpositioning to provide better data in roughholes. Coupling this new service with thehigh-efficiency MAXIS Express surface sys-tem provides data in formats that can beconfigured to diverse markets—from themost cost-sensitive to those demanding themost comprehensive and accurate informa-tion (previous page, bottom and below).

For drillers, flexibility, efficiency and relia-bility all contribute to higher productivity.But perhaps the most significant advance-

7Summer 1996

Track 6: Lithocolumn display, at 1:1300, ascale geologists use for correlation. The lefttrack is a laterolog-derived image thatshows the degree of bedding. Light is low-resistivity contrast and dark is high. Theright track, in which the right margin ofthe track is effective porosity and the left is bounded by the gamma ray log,shows lithology.Track 7: A resistivity invasion profile, 90 in.from the center of the borehole, in whichred is high resistivity and blue is low.

Track 8: A laterolog-derived image, in which light bands are resistive and dark are conductive. This image is used mainlyfor bedding identification and correlation,but can also be used for dip analysis on aworkstation. The white trace represents thepath followed by the high-resolution pad.Track 9: Log quality control (LQC) output.The seven stripes to the left of the inductionlog are LQC tracks for resistivity measure-ments. Each stripe represents a parameter.The five stripes to the left of the nuclear track are five parameters for the nuclear logand accelerometer, including accelerome-ter, density hardware, neutron porosity correction, density processing and photo-electric factor processing checks. A flagappears in the green tracks if any criticalparameters exceed predetermined values.

Track 10: Rt and mud resistivities frominduction and laterolog measurements,and invaded zone microresistivity, filteredat 18 in.Track 11: Environmentally corrected neu-tron porosity and a standard-resolutiondensity porosity. Although not shown here,the density reading has been computed atresolutions as good as 2 in. [5 cm].Track 12: A lithology quicklook at a moreexpanded scale than in track 6. Inputs are density, photoelectric effect andgamma ray or SP. The left margin is clayvolume. The color scheme (inset) indicatesquartz, dolomite, calcite and anhydritevalues. The points remain fixed and, asclay content increases, the color tone shiftstoward red.

AIT signals

Incr

easi

ng re

d

Vcl 95%

100%

0%

Vcl 65%

Vcl 35%

Vcl 5%

9 10 11 12

ment is in the measurements and answersthey provide, since this informationimproves the geoscientist’s understanding ofreservoirs and, ultimately, enhances theprofitability of field developments. Withnearly a year of experience so far, the influ-ence of new data is yet to be felt fully, butearly results give a sense of how this newinformation leads to a clearer picture ofreservoir properties. Summarized here arehighlights of the new technology, somecommon problems addressed by PLATFORM

EXPRESS logs, and a recent case studyfrom California.

Better Measurements, New AnswersPLATFORM EXPRESS technology contributesnew measurements, improved processingapproaches and real-time log quality con-trols. For all three, common features aregreater accuracy, breadth of data and speedof interpretation. Many computations thatformerly took place after some delay—onthe surface at the wellsite after logging, orhours to days later at the log interpretationcenter—can now be done downhole in realtime. We will look first at the measurementsthemselves.

From top to bottom, the platform makesseven petrophysical measurements: gammaray, neutron porosity, bulk density, photo-electric effect (Pe), flushed zone resistivity(Rxo), mudcake thickness (Hmc), also calledpad standoff, and true resistivity (Rt ) derivedfrom laterolog or induction imaging mea-surements (right).1 Integrated into the pack-age is a z-axis accelerometer, permittingreal-time speed correction (next page, top).This correction for irregular motion is per-formed on first-generation raw data, ratherthan on multisensor data that have beenthrough one or more processing cycles,resulting in more accurate and precise real-time depth matching for all measurements(next page, bottom).2 Other measurementsinclude caliper, mud temperature and mudresistivity and, with a special head, down-hole cable tension.

Except for the gamma ray and neutronmeasurements, which have standard verticalresolutions, other measurements elevate thestandards of wireline logging.3 In the densitymeasurement, a reengineered pad, additionof a third detector and data processing pro-vide improvements over conventional dual-spacing measurements.4 These improve-ments yield better compensation for largestandoff (up to 1 in. [2.5 cm]), higher preci-sion in denser formations and less sensitivityto barite, which compromises Pe measure-ments. A shorter measurement pad and

HALS

Highly IntegratedGamma Ray

Neutron Sonde(HGNS)

Electronicscartridge

High-ResolutionAzimuthal Laterolog

Sonde (HALS)

High-ResolutionMechanical

Sonde

AIT

AIT Array InductionImager Tool

Rt, Rm

Toolacceleration

Caliper

Hingejoint

Hingejoint

ρb, Pe

2, 8, 18 in.

Rxo, Hmc2, 8, 18 in.

GR24 in.

ØN12 to 24 in.

■■PLATFORM EXPRESSmeasurements. Thelower section of thestring can be aninduction- or lat-erolog-type device,depending on bore-hole mud resistivityand borehole/for-mation resistivitycontrast. Hingejoints above andbelow the High-Res-olution MechanicalSonde allow thetool to better nego-tiate rough bore-holes and improvepad contact.

8 Oilfield Review

1. Standoff refers to the distance between the pad andformation, regardless of whether this is filled with mudor mudcake. Standoff usually equals mudcake thick-ness in permeable formations.

2. Belougne V, Faivre O, Jammes L, and Whittaker S:“Real-Time Speed Correction of Logging Data,” Trans-actions of the 37th SPWLA Annual Logging Sympo-sium, New Orleans, Louisiana, USA, June 16-19,1996, paper F.

3. Vertical resolution of the gamma ray and neutronporosity measurements is 24 in. [60 cm] and for theneutron up to 12 in. [30 cm] with enhanced resolu-tion processing. See:Flaum C, Galford JE and Hastings A: “Enhanced Verti-cal Resolution Processing of Dual Detector Gamma-Gamma Density Logs,” The Log Analyst 30, no. 3(May-June) 1989: 139-149.

Galford JE, Flaum C, Gilchrist WA and Duckett SW:“Enhanced Resolution Processing of CompensatedNeutron Logs,” paper SPE 15541, presented at the61st SPE Annual Technical Conference and Exhibition,New Orleans, Louisiana, USA, October 5-8, 1986.

4. Eyl K, Chapellat H, Chevalier P, Flaum C, WhittakerSJ, Jammes L, Becker AJ and Groves J: “High-Resolu-tion Density Logging Using a Three Detector Device,”paper SPE 28407, presented at the 69th SPE AnnualTechnical Conference and Exhibition, New Orleans,Louisiana, USA, September 25-28, 1994.

■■Dramatic effect of PLATFORM EXPRESS real-time speed correction (right). In the nonreservoir section of a West Texas well, off-depth log read-ings were related to sticking. Lack of speed correction can lead to incorrect logs, improper correlation and, possibly, undetected pay.

■■Real-time resolu-tion matched mea-surements, from theMiddle East. Thestandard laterologcurve appears atfar left and thehighest resolutionPLATFORM EXPRESSdata are presentedon the right. In thelaterolog-typeimage track on theright, light bandsare resistive anddark bands areconductive.

9Summer 1996

Invaded Zone Resistivity

HALS High-Resolution Laterolog

MDLT Dual Laterolog

0.005 50ohm-m

0.05 500

ohm-m5.0 50,000

HALS Standard-Resolution Laterolog

0.5 5000

1:100

HCAL

-180 180

Pad8 13

deg

X450

X500

Dep

th, f

t

X550

X580

X550

X580

Standard MicroSFL

Standard LLDAPI

in.

0

6

125

16

Standard LLS

ohm-m0.2 2.0

0.2

0.2

2.0

2.0Standard

Gamma Ray

Caliper

in.6 16

Caliper

API0 125

Speed-CorrectedGamma Ray

Speed-Corrected High-Resolution RXOohm-m0.2 2.0

0.2

0.2

2.0

2.0

Speed-Corrected High-Resolution LLD

Speed-Corrected High-Resolution LLS

Dep

th, f

t

Dep

th, f

t

PLATFORM EXPRESS

Zone

of in

tere

st

surface and corrected with an estimateddownhole temperature, can now be mea-sured downhole in real time by the induc-tion or laterolog component. The multipur-pose microresistivity sensor on the platformhas reintroduced, and sometimes intro-duced for the first time, microresistivitymeasurements in places where they werenot used routinely, providing new insightsinto formation properties (below).

The induction measurement provides logswith vertical resolution of 1, 2 and 4 ft, each

10 Oilfield Review

■■Finding elusive sands with the new focused microresistivity log.In Bakersfield, California, sands often elude detection withgamma ray and SP. The gamma ray measurement is often mis-leading because the arkosic sands are rich in radioactive potas-sium and, when steamed, become more radioactive as mobileradionuclides concentrate in them. The SP cannot find sandsbecause fresh water from steaming changes formation Rw, alter-ing the static SP deflection as water shifts between fresh and salty.

Historically, fewer than 10% of logging programs in the regionincluded a microlog or Rxo measurement. Estimation of sandcount relied on other methods, with mixed results. The newmicroresistivity log provides a more consistent answer as well asbeing available on every service run without additional tools inthe logging program. In the new microresistivity processing (tracklabeled µ Res), Rxo (left curve) and mudcake or standoff (right curve)are computed. The program then back-calculates micronormaland microinverse values from the microlog.

In this well, the microresistivity log is also used to calculate netpay and define shale barriers, which can be interpreted as hori-zontal, low-permeability layers that are critical in steam injectionstrategy. In addition, the microresistivity log, in combination withdeep-reading resistivity, is also used to distinguish movable fromimmovable (heavy) oil. If the deep water-saturation value (Sw)equals the shallow (Sxo), then the hydrocarbons are not movable.

Dep

th, f

t

X900

X1000

X1100

Correlation µ Res PermOilSatResistivity Porosity

articulated arms improve contact with theformation, which enhances tool response inrough boreholes (next page, top left andbottom left). A new, short-spacing detectorcrystal with a shallow depth of investigationand a high counting rate provides additionalmeasurements that result in reduced sensi-tivity to standoff and improved statistics inhard formations, yielding higher vertical res-olution (next page, right). In addition, thedevice also gives a rough estimate of mud-cake density and Pe.

A new microresistivity technology makesmeasurements—at three depths of investiga-tion—that are analyzed to evaluate flushedzone and mudcake properties—Rxo , Rmcand standoff—overcoming a limitation ofconventional microresistivity sensors, whichcan measure resistivity in the flushed zoneor mudcake, but not both (see “A New Lookat Microresistivity,” below). Improved focus-ing of this measurement helps increase Rxovertical resolution to 1 in.5 In addition, mudresistivity, typically taken with a mud cell at

A New Look at Microresistivity

The new focused microresistivity measurement

differs in four main respects from existing Rxo

measurements: electrodes are mounted on a stiff

pad that is not deformed by the borehole, making

for a more consistent standoff measurement; sur-

vey currents are independently focused in planes

parallel and perpendicular to the tool axis, reduc-

ing sensitivity to borehole geometry; the three

depths of investigation permit solving for mudcake

and formation properties more reliably via inde-

pendent equations of tool response; and sensors

are adjacent to the density sensors, so both mea-

surements sample the same formation volume at

nearly the same time. As a result of these fea-

tures, vertical resolution of raw measurements is

improved to less than 1 in. An Rxo value and esti-

mate of mudcake parameters are obtained through

inversion processing that simultaneously solves

for all the unknown variables—Rxo, Rmc and Hmc.1

In this way, positive curve separation is recorded

only when the program computes the presence of

mudcake in front of the pad. Through inversion

processing, raw measurements are corrected for

thick mudcakes. This measurement is insensitive

to thin mudcake and has a depth of investigation

1. Rmc is not quite an unknown. Its value is fixed by the Rmvalue obtained by the PLATFORM EXPRESS induction orlaterolog measurement.

Inversion processing is a simultaneous solution for anumber of unknowns with constraints defined by thephysics of the measurements. In the case of the newmicroresistivity log, there are three measurements ofmicroresistivity. Rather than run each through a series ofchart corrections, which leads to systematic, additiveerrors, the inversion program minimizes error on eachoutput. This results in a solution that not only is moreaccurate, but also has a quantifiable precision.

about two thirds that of MicroSFL measurements.

Therefore it is less affected by the noninvaded

zone and gives a truer Rxo value, and hence Sxo.

Right: Standoff

Left: Rxo

5. Eisenmann P, Gounot M-T, Juchereau B, Trouiller J-Cand Whittaker SJ: “Improved Rxo MeasurementsThrough Semi-Active Focusing,” paper SPE 28437,presented at the 69th SPE Annual Technical Confer-ence and Exhibition, New Orleans, Louisiana, USA,September 25-28, 1994.

Hinge joint

Force appliedat center ofskid

Hinge joint

Caliper

Litho-Density RHOB

PLATFORM EXPRESS Formation Density

Washout

■■Improving contact in rough boreholes.Hinge joints improve density-Rxo pad con-tact with the borehole wall and formationface, especially in rugose hole andwashouts. Better pad contact improvesmeasurement accuracy and interpretationin difficult boreholes.

■■Improved density measurement in roughhole. The conventional and new three-detector density measurements tracktogether in smooth hole, but the shorter, better articulated pad of the new measure-ment gives superior results where thecaliper indicates washouts (arrow). ThePLATFORM EXPRESS measurement also compen-sates for standoff of up to 1 in. Shown here isthe standard-resolution measurement.

RHOB>NPOR

6 16in.

Caliper

Dep

th, f

t

X230

X240

X250

2-in. Density

Neutron Porosity

2-in. PEF

API

Gamma Ray

g/cm3

1 11

0.6 0

1.7 2.70 150

■■Log-core compari-son, Bakersfield,California. In thiscomparison, thehigh-resolution density confirmsthat 2-in. streaksseen on the microre-sistivity log arelimey, which canact as vertical per-meability barriers.Locating thesestreaks helps theoperator identifywhere steam break-through, which cankill a producingwell, will not occurand where produc-ers can therefore beperforated closer tothe water leg. Limeystreaks visible in thecore at X234 ft andX242 ft correspondto density peaks atthose intervals.

11Summer 1996

with depths of investigation of 10, 20, 30,60 and 90 in.6 In addition, an integratedmud resistivity measurement allows foraccurate, real-time environmental correc-tions to be made.7

The azimuthal laterolog combines a duallaterolog array for standard deep- and shal-low-resistivity measurements with anazimuthal array of electrodes that makes deepand shallow resistivity measurements aroundthe borehole with 8- or 16-in. [40-cm] verti-cal resolution.8 The new azimuthal readingsare especially helpful for interpreting hori-zontal well logs and invasion profiles, evalu-ating fractures and other formation hetero-geneities, and for estimating both formationdip and resistivity of dipping beds (above).Like the induction sensor, the laterolog alsomeasures mud resistivity in real time anddownhole.

12 Oilfield Review

New tool physics and tool design haveled to better environmental correctionsmade in real time. For example, a newmeasurement of standoff in the microresis-tivity and density logs allows for improvedenvironmental corrections and log qualitycontrol.9 In addition, measurements ofmudcake Pe and bulk density permit calcu-lation of an environmentally corrected for-mation Pe for better response in bad holeconditions (next page, bottom left). Real-time environmental corrections to the den-sity log, using a temperature log, are prov-ing valuable in steamflood regions (nextpage, bottom right). Temperature-correcteddensity and neutron logs can more reliablydistinguish steam breakthrough from zonesthat are hot, but may still containproducible oil. Finally, measurements ofdownhole temperature, Rm and calipersallow for real-time correction with mea-sured, rather than estimated or derived,parameters of the borehole environment(page 15, left).

Log Quality ControlSince the dawn of well logging, the repeatrun has provided proof of satisfactory toolfunction. Now, PLATFORM EXPRESS log qualitycontrol (LQC) procedures are giving anincreasing number of operators confidenceto log without the time-honored repeat runand gain significant time savings and otheroperational efficiencies.

Real-time log quality indicators allowmonitoring of two categories of LQC data:hardware performance parameters, whichindicate tool function; and data validityparameters, which are geared to indicateenvironmental problems that may skewreadings. Functions are checked at everysampling interval, typically 6 in. [15 cm] orless. When any value falls outside a prede-fined limit, a solid square appears in theLQC tracks (next page, top). At the end ofthe log, an LQC summary reports the per-centage of the logged interval with LQCvalues outside the defined limits. This sum-mary provides a quick indicator of thedegree of confidence in overall log quality,and the flags show whether significantproblems arose in intervals critical enoughto warrant a repeat run. Not usually dis-played on the logs, but available to the fieldengineer, are diagnostics that zero in on thespecific failure. Five variables each aremeasured for nuclear and electrical mea-surements—two hardware parameters,three for data validity.

In the data validity category, one exampleis the quality parameters for Pe measure-ments. The Pe measurement is sensitive tobarite, and up to a point can be correctedfor the influence of barite. But when thecorrection exceeds a certain value, the flagappears, signaling data are of limited confi-

6. Barber T, Orban A, Hazen G, Long T, Schlein R,Alderman S and Seydoux J: “A Multiarray InductionTool Optimized for Efficient Wellsite Operation,”paper SPE 30583, presented at the 70th SPE AnnualTechnical Conference and Exhibition, Dallas, Texas,USA, October 22-25, 1995.

7. Barber TD and Rosthal RA: “Using a MultiarrayInduction Tool to Achieve High-Resolution Logs withMinimum Environmental Effects,” paper SPE 22725,presented at the 66th SPE Annual Technical Confer-ence and Exhibition, Dallas, Texas, USA, October 6-9, 1991.

8. Smits JW, Benimeli D, Dubourg I, Faivre O, Hoyle D,Tourillon V, Trouiller J-C and Anderson BI: “High Res-olution From a New Laterolog with Azimuthal Imag-ing,” paper SPE 30584, presented at the 70th SPEAnnual Technical Conference and Exhibition, Dallas,Texas, USA, October 22-25, 1995.

9. Eyl K et al, reference 4.

DEVI

1:1200

-1 9

Pad1AZ

Hole AZ

HCAL7 12in.

900 deg

FMI Dips

CORPOL Dips

900 deg

2 2000ohm-m

High-ResolutionShallow Resistivity

2 2000ohm-m

All

All

X200

X400

High-ResolutionDeep Resistivity

Dep

th, f

t

■■A PLATFORM EXPRESS first: Real-time resistivity-derived dip, from West Texas, USA. Thisstructural dip presentation compares PLATFORM EXPRESS laterolog and FMI measurements.Track 2 shows good agreement in dips derived from the two techniques. Changes in dipazimuth and magnitude at X200 and X230 ft are probably associated with faults orunconformities. The laterolog-derived image in track 3 is the second derivative of the logcurve. Color changes here correspond to inflection points on the log curve, which indi-cate bed boundaries and are used to compute dip. The laterolog-derived image in track4 is normalized to show bedding. Taken together, these two tracks help detect the struc-tural dip trend.

13Summer 1996

X50

X60

X40

0 150

SP

APIGamma Ray

AIT-H90

AIT-H60

AIT-H30

AIT-H20

RXOZ2 200

2 200

ohm-m

2 200

2 200

2 200

0.6 0m3/m3

NPOR

DPHZ

0 10

-50 450

1:240

HMNO

HMNO

HMIN

-80 20mV 2 200 0.6 0m3/m3

125 375mmHCAL

125 375mmBit Size

AIT-H10

kg/m3HDRA

PEF

m

ohm-m0 20

ohm-m0 20

■■Bad hole, good logs. Depth-matched and speed-corrected PLATFORM EXPRESS logs in thisCanadian well react vigorously to calcitic and shaly laminations, giving the operator aclearer understanding of the distribution of shale laminae and shale clasts, which isimportant in steam-injection strategy. Even the large breakout at X46 m does not dramatically distort density or Pe readings. Improved density response derives from tool articulation and a smaller pad.

■■Steam breakthrough or just a hot tamale?In the steamflooded fields of Bakersfield,California, a density-neutron crossover isoften associated with the high temperatureof steam breakthrough. However, crossoveris not always a reliable indicator of break-through. Conventional logs may mistake azone adjacent to steam for a zone wheresteam has broken through. PLATFORM EXPRESSdensity-neutron logs can be temperature-corrected in real time to show crossoveronly in zones with breakthrough. In wells of the Midway-Sunset field, use of this technique has yielded an additional 50 ftof pay, which otherwise would have beenplugged. The technique relies on a temper-ature sensor that has a four-fold improve-ment in response time compared to previ-ous technology.

■■Interpretation of PLATFORM EXPRESS log quality measurements, which are presented as green stripes. In some provinces, the completenessof LQC data has given operators the confidence to log many wells without repeat runs. In the density and resistivity standoff curves (lefttrack, right margin), if a threshold value is reached, a flag appears, indicating several causes—mud is too fresh for microresistivity mea-surements, barite is present in the mud or the density tool has been miscalibrated.

4350

4400

AIT borehole/formationdigital ratio

HGNSdeviation

Caliper

Gammaray

Densitystandoff

Resistivitystandoff

AIT signals

Dep

th, f

t

MCFL hardwareRXO processing

HAIT hardwareHAIT array (1-2)

HAIT array (3-4)HAIT array (5-6)HAIT array (7-8)

Resistivity Track

AccelerometerDensity detector

Neutron porosityDensity computationPe computation

Nuclear Track

Tool sticking here... ...probably related to this accelerometer flag

µ Res PermOilSatResistivity Porosity

Density-neutron

crossover

■■Resistivity signatures of tricky sands in the San Joaquin Valley. The PLATFORM EXPRESSinduction log can be presented at three vertical resolutions, from left, 1, 2 and 4 ft. The 4-ft scale can be useful for comparison with older logs, and shows how high tempera-ture—this interval measures 200°F [93°C]—affects resistivity readings. Between X472 andX474 ft, the small bump on the 4-ft log appears to be shale. At the 1-ft scale, however, itshows a 3-ft sand with potential pay, with a high gamma ray reading due to radioactiveelements concentrated in the formation from steaming. Below X480 ft, the 1-ft log revealslaminated sands that appear as a coarsening upward sequence.

X490

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AIT-H10 in.D

epth

, ft

10. Exponents m and n in the Archie formula relate oilsaturation in porous rock to the resistivity of the fullywater-saturated rock. The constants a and m relatethe measured resistivity of a fully saturated porousmedium to the water resistivity. Both constants arerelated to the nature of the connection between pore

dence. For resistivity measurements, LQCdiagnostics may indicate that the tool isworking fine, but that environmental condi-tions, for example, may be responsible foran aberrant reading. This would typically bethe case for the shallow-reading devices inwashed-out zones, where the borehole sig-nal would be larger than the formation sig-nal. In the realm of hardware LQC, a flagwill indicate, for instance, whether a densitydetector voltage is out of tolerance.

Case Study: Finding Bypassed Pay in BakersfieldTight margins are a way of life in the Mid-way-Sunset field of southern California, inone of the oldest, most productive basins inthe lower 48 states. Heavy oil (10 to 15°API) lies as shallow as a few hundred feet,but production usually requires costlysteamflooding. A typical well might produce20 to 30 barrels of oil per day (BOPD) [3.2to 4.8 m3/d] for several decades, with anexceptional producer reaching 50

14

spaces; a, often taken as 1, is called the cementationfactor, and m, the porosity exponent, reflects the tor-tuosity of the current flow through the rock pores.The saturation exponent, n, often taken as 2, isrelated to the wettability of the rock surface.

barrels/day [7.9 m3/d]. Santa Fe EnergyResources, which produces more than48,000 BOPD [635 m3/d] from three mainfields in the area, faces several technicalchallenges.

A major challenge is identifying oil leftbehind after steam injection, when conven-tional logs sometimes present ambiguousinterpretations. In a steamed zone, the den-sity-neutron log curves may cross overbecause the tools read the steam, a lightfraction of hydrocarbons released from theheat, or gases from in-situ combustion ofhydrocarbons. The gamma ray log readshigh because steaming causes migrationand concentration of radionuclides. Hightemperature lowers Rw , reducing apparenttrue resistivity—sometimes even in the pres-ence of hydrocarbons (above). The chal-lenge is finding oil that eludes detectionconventionally.

A critical step in addressing this problem iscorrecting logs—in this case, the neutron,but sometimes also the Rw—for the hightemperature. For the special needs of thisfield, the PLATFORM EXPRESS system was fittedwith a new contact temperature sensor,which measures temperature of the forma-

tion rather than the mud. It responds fourtimes faster than previous technologies,enabling Santa Fe Energy to acquire a high-resolution temperature measurement for atemperature-corrected neutron log (nextpage, left). A better fix on porosity yields amore accurate water saturation (Sw ). Aquicklook log with customized a, m and nvalues, and temperature-corrected neutronand Rw values goes into a real-time compu-tation of saturation.10 With this log, casingdecisions that used to take hours can nowbe made in minutes.

Better understanding of desaturation yieldsother dividends. It leads to more effectivesteaming strategies, such as better identifica-tion of thief zones or intervals receivinginsufficient steam. In addition, it improvescompletion strategies, like leaving slottedpipe in zones previously thought to bedepleted of hydrocarbons, and which wereformerly completed with blank pipe.

In diatomite formations of California’s SanJoaquin Valley, PLATFORM EXPRESS measure-ments have shed new light on possible pro-duction mechanisms. These diatomites aremassive, low-permeability formations thatmust be hydraulically fractured. Electricalimaging logs sometimes revealed high-resis-tivity streaks, which were not well under-stood. When PLATFORM EXPRESS microresistiv-ity and Rxo measurements were first run, themicroresistivity reported mudcake—not pre-viously observed—and the Rxo showedunusual spikes (next page, right). To look forpossible causes, the FMI Fullbore FormationMicroImager tool was run, which revealedmudcake and Rxo spikes in front of the high-resistivity streaks, suggesting that they arefractured zones. The PLATFORM EXPRESS den-sity measurement, presented with a 2-in.vertical resolution—the highest axial resolu-tion possible for a density measurement—indicated that the streaks are possibly cherty.This adds one more piece to the oil originsand distribution puzzle.

Santa Fe Energy has also ceased runningrepeat sections, due mainly to the combina-tion of PLATFORM EXPRESS log quality data andbetter tool reliability. The log quality displayprovides enough information about toolfunction and wellbore conditions to confirm

Oilfield Review

■■A new view of possible production mecha-nisms in San Joaquin Valley diatomites. AnFMI log reveals high-resistivity streaks thatare shown to be permeable by the PLATFORMEXPRESS microresistivity log (blue curve), andto have the high grain-density signature ofchert by the 2-in. vertical resolution densitylog (purple curve).

905

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■■Water saturation, with and without heatstroke. The PLATFORM EXPRESS water saturationdisplay (second track from right) shows a real-time Sw curve corrected for the effect of temperature on the neutron input. In the right track, the corrected neutron (left margin ofthe green area) is offset from the uncorrected by up to about one division (6 p.u.).

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measurement validity without repeat runs.Lost time due to hardware failure isapproaching 300 jobs per lost-time failure,nearly a ten-fold improvement over conven-tional technology. Given Santa Fe’s annual300-well logging program, eliminatingrepeat logs and reducing lost-time failurestranslates into significant savings. Santa Feestimates that the time savings allows morewells to be put on line, and the improvedpetrophysics provides better characteriza-tion of desaturated zones. Together, thesebenefits are expected to translate into anincrease in production of more than 22,000barrels [3180 m3] per year.

Summer 1996

Where It LeadsWith less than one year of commercial ser-vice, most operators are still in the hand-shake stage, getting to know PLATFORM

EXPRESS technology. For some, a significantstep is resolution-matching new logs toolder logs for easier comparison, and adapt-ing data bases to the new mnemonics. Formany, the easy availability of more compre-hensive wellsite answers is raising questionsabout long-standing formation evaluationpractices. “At first we thought: ‘We don'tneed microresistivity,’” said A.S. (Buddy)Wylie at Santa Fe Resources, “but we foundthat it could give us good additional value atonly an incrementally higher price.”

The immediate and most obvious rewardsare operational efficiencies. In the petro-physical realm, deeper, sharper reading andmore robust measurements are showingdetails sometimes not seen before, whosefull significance will unfold with theexpanding library of PLATFORM EXPRESS logsand with the growth of interpretation tech-niques to get the most from them. —JMK

15

16

Simulation Throughoutthe Life of a Reservoir

Gordon AdamsonReservoir Management Ltd.Aberdeen, Scotland

Martin CrickTexaco Ltd.London, England

Brian GaneBritish PetroleumAberdeen, Scotland

Omer GurpinarDenver, Colorado, USA

Jim HardimanHenley on Thames, England

Dave PontingAbingdon, England

For help in preparation of this article, thanks to BobArcher, Chip Corbett, Ivor Ellul, Roger Goodan and JimHonefenger, GeoQuest, Houston, Texas, USA; RandyArchibald, GeoQuest Reservoir Technologies, Henley onThames, England; Ian Beck, GeoQuest Reservoir Tech-nologies, Abingdon, England; George Besserer, PanCanadian Petroleum Limited, Calgary, Alberta,Canada; Kunal Dutta-Roy, Simulation Sciences Inc.,Brea, California, USA; and Sharon Wells, GeoQuestReservoir Technologies, Denver, Colorado.ECLIPSE, FloGrid, GRID, Open-ECLIPSE, PVT andRTView are marks of Schlumberger. NETOPT andPIPEPHASE are marks of Simulation Sciences Inc.1. Peaceman DW: “A Personal Retrospection of Reser-

voir Simulation,” Proceedings of the First and SecondInternational Forum on Reservoir Simulation, Alpbach,Austria, September 12-16, 1988 and September 4-8,1989.

2. Wycoff RD, Botset HG and Muskat M: “The Mechan-ics of Porous Flow Applied to Water-flooding Prob-lems,” Transactions of the AIME 103 (1933): 219-249.Muskat M and Wyckoff RD: “An Approximate Theoryof Water-Coning in Oil Production,” Transactions ofthe AIME 114 (1935): 144-163.

3. Darcy’s law states that fluid flow velocity is propor-tional to pressure gradient and permeability, andinversely proportional to viscosity.

4. Coats KH: “Use and Misuse of Reservoir SimulationModels,” SPE Reprint Series No. 11 Numerical Simu-lation. Dallas, Texas, USA: Society of Petroleum Engi-neers (1973): 183-190.

Simulation is one of the most powerful tools for guiding reservoir

management decisions. From planning early production wells and

designing surface facilities to diagnosing problems with enhanced

recovery techniques, reservoir simulators allow engineers to

predict and visualize fluid flow more efficiently than ever before.

Reservoir simulators were first built as diag-nostic tools for understanding reservoirs thatsurprised engineers or misbehaved afteryears of production. The earliest simulatorswere physical models, such as sandboxeswith clear glass sides for viewing fluid flow,and analog devices that modeled fluid flowwith electrical current flow.1 These models,first documented in the 1930s, were con-structed by researchers hoping to under-stand water coning and breakthrough inhomogeneous reservoirs that were undergo-ing waterflood.2

Some things haven’t changed since the1930s. Today’s reservoir simulators generallysolve the same equations studied 60 yearsago—material balance and Darcy’s law.3But other aspects of simulation havechanged dramatically. With the advent ofdigital computers in the 1960s, reservoirmodeling advanced from tanks filled withsand or electrolytes to numerical simulators.In numerical simulators, the reservoir is rep-resented by a series of interconnectedblocks, and the flow between blocks issolved numerically. In the early days, com-puters were small and had little memory,limiting the number of blocks that could beused. This required simplification of thereservoir model and allowed simulation toproceed with a relatively small amount ofinput data.

As computer power increased, engineerscreated bigger, more geologically realisticmodels requiring much greater data input.This demand has been met by the creationof increasingly complex and efficient simu-lation programs coupled with user-friendly

data preparation and result-analysis pack-ages. Today, desktop computers may have5000 times the memory and run about 200times faster than early supercomputers.However, the most significant gain has notbeen in absolute speed, but speed at a mod-erate price. Computational efficiency hasreached a stage that allows powerful simula-tors to be run frequently.

Numerical simulation has become a reser-voir management tool for all stages in the lifeof the reservoir. No longer just for comparingperformance of reservoirs under differentproduction schemes or trouble-shootingwhen recovery methods come underscrutiny, simulations are also run when plan-ning field development or designing mea-surement campaigns. In the last 10 years,with the development of computer-aidedgeological and geostatistical modeling, reser-voir simulators now help to test the validityof the reservoir models themselves. And sim-ulation results are increasingly used to guidedecisions on investing in the construction oroverhaul of expensive surface facilities.

Motivation for SimulationA numerical simulator containing the rightinformation and in the hands of a skilledengineer can imitate the behavior of a reser-voir. A simulator can predict productionunder current operating conditions, or thereaction of the reservoir to changes in con-ditions, such as increasing production rate;production from more or different wells;response to injection of water, steam, acid

Oilfield Review

Summer 1996

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grid

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Core plugs Whole cores

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Well logs Well testing

Outcrop studies 3D Seismic data

Geological expertiseLarge-scale structure

Small-scale structure

Simulation model Static reservoir model

Execution model

1st generation geomodel

■■Creating models for input to reservoir simulators. The first-generation geomodel is cre-ated through the combined efforts of geologists, geophysicists, petrophysicists andreservoir engineers. Reservoir properties are then upscaled to produce the static reser-voir model. Optimizing the grid and calibrating with dynamic data yield the simulationmodel. Finally, input from surface facilities analysis and risk calculations results in anexecution model that can guide reservoir management decisions.

or foam; the effect of subsidence; and pro-duction from horizontal wells of differentlengths and orientations.

Reservoir simulation can be performed byoil company reservoir engineers or by engi-neering consultant contractors. Some con-tractors specialize in engineering consulting,while others offer a full range of oilfield ser-vices. In either case, the simulator is a toolthat allows the engineer to answer questionsand offer recommendations for improvingoperating practice.

To make simulation worthwhile, there mustbe a well-posed question of economicimportance: Where should wells be locatedto maximize incremental recovery per dollarof additional investment? How many wellsare required to produce enough gas to meeta contractual deliverability schedule? Shouldoil be recovered by natural depletion orwater injection? What is the optimum lengthof a horizontal well? Is carbon dioxide [CO2]injection feasible? Should we keep this reser-voir alive? As observed by K.H. Coats whileat the University of Texas at Austin, USA,“The complexity of the questions beingasked, and the amount and reliability of thedata available, must determine the sophisti-cation of the system to be used.”4 In allcases, a simulation study should result inrecommendations for intervention. This mayinclude a new strategy for data acquisition,or an infill drilling plan with the number,location and direction of wells and a com-pletion strategy for each well.

How a Simulator WorksThe function of reservoir simulation is tohelp engineers understand the production-pressure behavior of a reservoir and conse-quently predict production rates as a func-tion of time. The future productionschedule, when expressed in terms of rev-enues and compared with costs and invest-ments, helps managers determine both eco-nomically recoverable reserves and the limitof profitable production.

Once the goal of simulation is determined,the next step is to describe the reservoir interms of the volume of oil or gas in place,the amount that is recoverable and the rateat which it will be recovered. To estimaterecoverable reserves, a model of the reser-voir framework, including faults and layersand their associated properties, must beconstructed. This so-called static model iscreated through the combined efforts ofgeologists, geophysicists, petrophysicists andreservoir engineers (left). Much of the multi-billion-dollar business of oilfield services iscentered on obtaining information that

17

Local Grid Refinement

Block-Centered Geometry

Corner-Point Geometry

6200

5800

6600

7000

7400

6200

5800

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0 2000 4000 6000 8000

0 2000 4000 6000 8000

■■Block-centeredand corner-pointgeometries. Block-centered geometryfeatures flat-topped rectangularblocks that matchthe mathematicalmodels behind thesimulator. Corner-point geometrymodifies the recti-linear grid so thatit conforms toimportant reservoirboundaries. Three-dimensional gridsare constructedfrom a 2D grid bylaying it on the topsurface of thereservoir and pro-jecting the gridvertically or alongfault planes ontolower layers.

■■Local grid refine-ment (LGR). Localgrid refinementallows engineers todescribe selectedregions of the reser-voir in extra detail.Radial refined gridsare often usedaround wellbores toexamine coning orother phenomenaresulting from rapidvariation in proper-ties away from thewell. Refined gridsare also one way totreat property varia-tions near faults.

eventually feeds reservoir simulators, lead-ing to better reservoir development andmanagement decisions.5

The simulator itself computes fluid flowthroughout the reservoir. The principlesunderlying simulation are simple. First, thefundamental fluid-flow equations areexpressed in partial differential form foreach fluid phase present. These partial dif-ferential equations are obtained from theconventional equations describing reservoirfluid behavior, such as the continuity equa-tion, the equation of flow and the equationof state. The continuity equation expressesthe conservation of mass. For most reser-voirs, the equation of flow is Darcy’s law.For high rates of flow, such as in gas reser-voirs, Darcy’s law equations are modified toinclude turbulence terms. The equation ofstate describes the pressure-volume or pres-sure-density relationship of the various flu-ids present. For each phase, the three equa-tions are then combined into a single partialdifferential equation. Next, these partial dif-ferential equations are written in finite-dif-ference form, in which the reservoir volumeis treated as a numbered collection ofblocks and the reservoir production periodis divided into a number of time steps.Mathematically speaking, the problem isdiscretized in both space and time.

Examples of simulators that solve thisproblem under a variety of conditions arefound in the ECLIPSE family of simulators.These simulators fall into two main cate-gories. In the first category are three-phaseblack-oil simulators, for reservoirs compris-ing water, gas and oil. The gas may moveinto or out of solution with the oil. The sec-ond category contains compositional andthermal simulators, for reservoirs requiringmore detailed description of fluid composi-tion. A compositional description couldencompass the amounts and properties ofhexanes, pentanes, butanes, benzenes,asphaltenes and other hydrocarbon compo-nents, and might be used when the fluidcomposition changes during the life of thereservoir. A thermal simulator would beadvised if changes in temperature—eitherwith location or with time—modified thefluid composition of the reservoir. Such adescription could come into play in the caseof steam injection, or water injection into adeep, hot reservoir.

18 Oilfield Review

5. For specific examples: Bunn G, Cao Minh C, Roesten-burg J and Wittman M: “Indonesia’s Jene Field: AReservoir Simulation Case Study,” Oilfield Review 1,no. 2 (July 1989): 4-14.Briggs P, Corrigan T, Fetkovich M, Gouilloud M, LoTien-when, Paulsson B, Saleri N, Warrender J andWeber K: “Trends in Reservoir Management,”OilfieldReview 4, no. 1 (January 1992): 8-24.Corbett P, Corvi P, Ehlig-Economides C, Guérillot D,Haldorsen H, Heffer K, Hewitt T, King P, Le Nir I,Lewis J, Montadert L, Pickup G, Ravenne C, RingroseP, Ronen S, Schultz P, Tyson S and Verly G: “ReservoirCharacterization Using Expert Knowledge, Data andStatistics,”Oilfield Review 4, no. 1 (January 1992): 25-39.Al-Rabah AK, Bansal PP, Breitenback EA, HallenbeckLD, Meehan DN, Saleri NG and Wittman M: “Explor-ing the Role of Reservoir Simulation,” Oilfield Review2, no. 2 (April 1990): 18-30.

6. For more on local grid refinement: Heinemann ZEand von Hantelmann G: “Using Local Grid Refine-ment in a Multiple-Application Reservoir Simulator,”paper SPE 12255, presented at the Reservoir Simula-tion Symposium, San Francisco, California, USA,November 15-18, 1983.Forsyth PA and Sammon PH: “Local Mesh Refinementand Modelling for Faults and Pinchouts,” paper SPE13524, presented at the Reservoir Simulation Sympo-sium, Dallas, Texas, USA, February 10-13, 1985.

7. Net-to-gross ratio, sometimes called just net to gross(NTG), is the ratio of the thickness of pay to the totalthickness of the reservoir interval.

8. For examples of the technique: Schultz PS, Ronen S,Hattori M, Mantran P and Corbett C: “Seismic-GuidedEstimation of Log Properties,” The Leading Edge 13,no. 7 (July 1994): 770-776.Caamano E, Corbett C, Dickerman K, Douglas D, GirR, Martono D, Mathieu G, Nicholson B, Novias K,Padmono J, Schultz P, Suroso S, Thornton M and YanZ: “Integrated Reservoir Interpretation,” OilfieldReview 6, no. 3 (July 1994): 50-64.

9. Thibeau S, Barker JW and Souillard P: “DynamicalUpscaling Techniques Applied to CompositionalFlows,” paper SPE 29128, presented at the 13th SPE

These and all other commercial reservoirsimulators envision a reservoir divided intoa number of individual blocks, called gridblocks. Each block corresponds to a volumein the reservoir, and must contain rock andfluid properties representative of the reser-voir at that location. The simulator modelsthe flow of mobile fluid through the walls ofthe blocks by solving the fluid-flow equa-tions at each block face. Parametersrequired for the solution include permeabil-ity, layer thickness, porosity, fluid content,elevation and pressure. The fluids areassigned a viscosity, compressibility, solu-tion gas/oil ratio and density. The rock isassigned a value for compressibility, capil-lary pressure and a relative permeabilityrelationship.

Creating the grid and assigning propertiesto each grid block are time-consuming tasks.The framework of the reservoir, including itsstructure and depth, its layer boundaries andfault positions and throws, is obtained fromseismic and well log data. The well-bred gridrespects the framework geometry as much aspossible. Traditionally, reservoir simulationgrid blocks are rectilinear with flat, horizon-tal tops in an arrangement called block-cen-tered geometry (previous page, top). Thisconfiguration ensures that the grids remainorthogonal and exactly match the mathemat-ical models used in the simulators.

However, this approach does not easilyrepresent structural and stratigraphic com-plexities such as nonvertical faults, pin-chouts or erosional surfaces using purelyrectangular blocks. The 1983 introductionof corner-point geometry in the ECLIPSEsimulator overcame these problems. In acorner-point grid, the corners need not beorthogonal. In modeling a faulted reservoir,for example, engineers have the flexibility tochoose between an orthogonal areal gridwith the fault positions projected onto thegrid or a flexible grid to exactly honor thepositions of important faults. Three-dimen-sional (3D) grids are constructed from anareal, or 2D, grid by laying it on the top sur-face of the reservoir and projecting it verti-cally or along fault planes onto lower layers.

Engineers’ requirements for more detail inthe model, particularly to examine coningand near-wellbore effects, has led to theconcept of local grid refinement (LGR) (pre-vious page, bottom). This allows parts of themodel to be represented by a large numberof small grid blocks or by implanting radial

Summer 1996

Symposium on Reservoir Simulation, San Antonio,Texas, USA, February 12-15, 1995.

grids around wells in a larger Cartesiangrid.6 Locally refined grids also captureextra detail in other areas where reservoirproperties vary rapidly with distance, suchas near faults. And LGR, combined with gridcoarsening outside the region of interest,allows engineers to retain fine-scale prop-erty variation without surpassing computerspace limitations. The interactive GRID pro-gram was designed to help construct thecomplex reservoir grid efficiently (see“Developments in Gridding,” page 21).

Once the grid has been constructed, thenext step is to assign rock and fluid proper-ties from the reservoir framework model toeach grid block. Populating the grid withproperties is another time-consuming anddifficult task. Each grid block, typically afew hundred square meters areally by tensof meters thick, has to be assigned a singlevalue for each of the reservoir properties,including fluid viscosity, relative permeabil-ity, saturation, pressure, permeability, poros-ity and net-to-gross ratio.7 Log measure-ments made in wells yield high-densitydata, typically every 6 in. [15 cm], but pro-vide little information between wells. Datafrom cores may provide high-density“ground truth,” but these represent perhapsone part in 5 billion of the volume of thereservoir. Surface seismic reflections coverthe reservoir volume and more, but do nottranslate directly into the desired rock andfluid properties. How are these disparatedata sets merged?

Two processes are required: extrapolatingthe well data into the interwell reservoir vol-ume, then upscaling the fine-scale data tothe scale of a simulation grid block. Tradi-tionally log or core data were upscaled, oraveraged, over lithological units at the wells.Then these data were interpolated andextrapolated through the reservoir and mapsproduced for each layer—formerly a hand-drafting exercise by geologists. The mapswould be passed to the reservoir engineerwho would then generate grids, run prelimi-nary simulations on a series of grid sizes,and attempt further upscaling based on thereservoir flow characteristics.

In recent years, the process has beenreversed. The current trend is to use com-puter programs to build 3D geological mod-els bounded by seismic data, and to popu-late the models using geostatistical ordeterministic methods to distribute log andcore data.8

Scaling core and log properties up to grid-block scales is still a challenging task. Someproperties, such as porosity, are consideredsimple to upscale, following an arithmetic

averaging law. Others, such as permeability,are more difficult to average. And relativepermeabilities—different permeabilities fordifferent fluid phases—remain the most dif-ficult problem in upscaling. There is no uni-versally accepted method for upscaling, andit is an area of active research.9

After the model has been finalized, thesimulator requires boundary conditions toestablish the initial conditions for fluidbehavior at the beginning of the simulation.Then, for a given time later, known as thetime step, the simulator calculates new pres-sures and saturation distributions that indi-cate the flow rates for each of the mobilephases. This process is repeated for a num-ber of time steps, and in this manner bothflow rates and pressure histories are calcu-lated for each point—especially the pointscorresponding to wells—in the system.

But even with the best possible model,uncertainty remains. One of the biggest jobs

19

20 Oilfield Review

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■■Visualizing the reservoir model in 3D. Visualization is a reliable means of checkingreservoir models before input to a simulator. Inconsistencies in model parameters may be flagged and corrected. After simulation, results may also be viewed, allowingfaster evaluation of comparative simulation runs and providing insight into recoverybehavior. In this example reservoir pressure is color-coded to show regions of high and low pressure.

■■Texaco Erskine Project in the North SeaCentral Graben region. The high-tempera-ture, high-pressure condensate field isdue to go on production in 1997.

6250.13Pressure, psi

8674.00

RTView 96A

of a simulator is to evaluate the implicationsof uncertainty in the static reservoir model.Sometimes uncertainty or error is intro-duced through low data quality. Anothersource of error arises because laboratory,logging and geophysical experiments maynot directly measure the property of interest,or at the right scale, and so some otherproperty is measured and transformed insome way that adds uncertainty. There isalso uncertainty in how a property variesbetween measurement points. Many reser-voir descriptions rely on core sample mea-surements for rock and fluid property infor-mation. This information is uncertainlyextended through the reservoir volume, usu-ally in some geostatistical or deterministicfashion, guided by seismically derived sur-faces or other geological constraints.

One way to reduce uncertainty is to spotinconsistencies in the properties of the reser-voir model before simulation. Three-dimen-sional visualization software, such as theRTView application, helps engineers bemore efficient in finding inconsistencies byallowing them to view the reservoir model in3D. Results of simulation runs may also beviewed, allowing faster evaluation of simula-tion runs and providing immediate insightinto recovery behavior and physical pro-cesses occurring in the reservoir (above).

A simulation run itself can also helpreduce uncertainty. Outside the oil industry,simulators are used to determine the reac-tion of a known environment to externallyapplied perturbations. An example is a flightsimulator that tests varying visibility condi-tions. Although a reservoir environment islargely unknown, simulators can helpimprove the description. In a process knownas history matching, reservoir production issimulated based on the existing, thoughuncertain, reservoir description. Thatdescription is adjusted iteratively until thesimulator is able to reproduce the observedpressures and multiphase flow resultingfrom applied perturbations—that is, theknown production and injection. If the pro-duction history can be matched, the engi-neer has greater confidence that the reser-voir description will be a useful, predictivetool. The history-matching process is time-consuming and requires considerable skilland insight, but is a necessary prerequisiteto the successful prediction of continuedreservoir performance.

These new techniques and programs forloading data, computing simulations andviewing results are allowing engineers to usesimulators to guide reservoir managementdecisions throughout the life of many fields.The following case studies highlight some ofthe uses of simulators in four different stagesof reservoir maturity.

Preproduction PlanningAn example of early use of simulationcomes from the Texaco Erskine Project inthe North Sea Central Graben region(below). The Erskine field comprises fourhigh-pressure, high-temperature (HPHT)condensate reservoirs, and will be the firstHPHT field in the North Sea to come online when production commences in 1997.

Production will be from an unmannedplatform, with a multiphase pipeline to theAmoco Lomond Platform for separation.Gas will be exported via the Central AreaTransmission System (CATS) pipeline, andliquids via the Forties pipeline. Initial pro-duction with be from three wells, with threemore to be added. The production mecha-nism will be natural depletion, with no gasrecycling. Other operators in the region whohave similar reservoirs to develop arewatching how Texaco handles the hostile,overpressured field.

Simulation was selected as a way topredict production of gas for drawing updeliverability contracts—contracts promis-ing delivery of designated volumes of gas ata specified time. The main challenge in sim-ulating these reservoirs is accounting forboth the permeability reduction due to rockcompaction and the productivity loss due tocondensate banking—explained below—inthe near-wellbore region of the formationwhen the reservoir pressure falls below thedewpoint pressure.10

■■A perpendicular bisector (PEBI) grid showing localgrid refinement around wells. Grid blocks may havea variety of shapes and can fit any reservoir geome-try. The smoother grid-block shape also gives amore accurate simulation solution because there isless chance of choosing the wrong grid orientation.

21Summer 1996

10. Crick M: “Compositional Simulation for HPHT GasCondensate Reservoirs: Follow-up,” presented at theSecond ECLIPSE International Forum, Houston,Texas, USA, April 15-19, 1996.Hsu HH, Ponting DK and Wood L: “Field-WideCompositional Simulation for HPHT Gas Conden-sate Reservoirs Using an Adaptive Implicit Method,”paper SPE 29948, presented at the InternationalMeeting on Petroleum Engineering, Beijing, China,November 14-17, 1995.

41 Water saturation % 100

Perpendicular Bisector (PEBI) Grid

Because of overpressure conditions in thereservoir, the rock is expected to compactwith depressurization. This means the rockis expected to decrease its porosity andeffective permeability as production pro-gresses. To quantify these effects, laboratoryexperiments were conducted on rock sam-ples. The experiments showed that at theassumed well abandonment pressure of4000 psi, permeability would be reduced byabout 33% from the initial value, whileporosity would be negligibly reduced.

Modeling flow in condensate reservoirsrequires additional considerations. As pres-sure drops around the well, condensation,or dropout, occurs and liquid forms. The liq-uid saturation increases—in what is calledcondensate banking—until it is greatenough to overcome capillary trappingforces and the liquid becomes mobile. Butuntil the liquid becomes mobile, the pres-ence of immobile liquid reduces the relativepermeability to gas, resulting in a loss inproductivity. The rapid change in fluid satu-ration away from the well requires a finegrid to accurately model reservoir proper-ties. The ECLIPSE compositional simulatormodeled the regions around the wells witha refined radial grid, and the remainder witha Cartesian grid.

In addition, condensate yields varybetween the four different reservoirs, soeach reservoir fluid was represented by itsown equation of state. The local grid refine-ment and multiple equation of state capabil-ities were added to the ECLIPSE simulatorfor this project, and now form part of thecommercial package.

The simulation was used to conductuncertainty analysis for risk management.To maximize revenues, the tactic is to maxi-mize gas rates without being penalized forcoming up short. To understand the risksbehind promising a given gas rate, it isdesirable to understand the sensitivity of thesimulation results to each important inputparameter. In this case, repeated simula-tions indicated that the parameters with the

Developments in Gridding

Since the first grids were built, the variety, range

and resolution of oilfield measurements have

increased, and computer power and efficiency

have grown. To take advantage of these develop-

ments, reservoir engineers require better and

more comprehensive simulation software tools.

Modern 3D seismic acquisition, processing and

interpretation techniques have resulted in more

reliable and higher-resolution definition of faults

and erosional surfaces. The engineer wants to

represent the full complexity of nonvertical faults,

curving or listric faults, and faults that intersect or

truncate against one another. Another develop-

ment that requires more complex models is the

increasing use of high-angle and horizontal wells

and multilateral wells. These requirements

stretch the traditional gridding programs based on

corner-point geometry—such as the GeoQuest

GRID program—to the limit.

This has led to the development of new gridding

software techniques such as the FloGrid utility,

which will produce grids that conform to the reser-

voir framework as defined by fault surfaces and

lithological boundaries. Unstructured perpendicu-

lar bisector (PEBI) and tetrahedral grid systems

are being developed and included in gridding and

simulation programs (above right). “Blocks” in a

PEBI grid may have a variety of shapes, and they

may be arranged to fit any reservoir geometry.

The smoother gridblock shape gives a more accu-

rate simulation solution because there is less

chance of choosing the wrong grid orientation—

a potential problem with traditional grids. A PEBI

grid also allows flow in more directions from a

given grid block, important in the modeling of hor-

izontal wells, gas injection schemes or the inter-

action of wells in an interference test. These grids

are also being used as a basis for a new genera-

tion of upscaling techniques.

A further gridding development is the linking of

well test analysis with simulator programs to give

the engineer a greater range of numerical reser-

voir models than exist in analytical models.

Unstructured PEBI grids are of great benefit in

these situations, allowing the radial components of

flow into the wellbore to be combined with linear

or planar features such as the trajectory of a hori-

zontal well or a fault plane. Simulations run with

PEBI grids tend to take longer than those run on

structured grids, but the ability to capture the

structural complexity of the reservoir’s flow units

outweighs the need for speed. A compromise can

be reached by building a structured grid in the geo-

logically simple parts of the reservoir, and splicing

in an unstructured grid when geologic complexity

requires more flexibly shaped grid blocks.

Cumulative Production

ParametricMethod

ParametricMethod

Monte CarloAnalysis

Sensitivities

InitialDeliverability Distribution

Normalized Average Profile

Reserves Distribution

Probabilistic Production Profile

Deliverability

Predictedproduction

Del

iver

abilit

y

■■Schematic of deliverability and cumulative production computed for best- and worst-case scenarios. The sensitivity profiles (left)represent curves for best and worst cases, such as the lowest and highest permeability, lowest and highest compaction and all otherparameters mentioned above. Not all curves were plotted because of space constraints. All the sensitivities were combined througha parametric method modified for oilfield application. (From Smith et al, reference 11.) A normalized average profile (center) wascombined with initial deliverability and reserves distributions in a Monte Carlo method to give a probabilistic—90% confidence—pro-duction profile (right). The upper curve is the deliverability and the lower curve is predicted production. The cyclic nature of the pro-duction curve reflects the alternation between summer and winter demand for gas.

22 Oilfield Review

■■Sensitivity of Erskine simulation results to input parameters. Repeatedsimulations indicate parameters that have the most influence on simula-tion results. Quantifying the uncertainty in the most sensitive parametersis an important step toward quantifying project risk. Additional simula-tions were run with the high, low and middle values of each parameter,forming input sensitivities for the risk analysis shown below.

Gas in place

Permeability

Pentlandcontinuity

Compaction

Criticalcondensate

saturation

Trapped gassaturation

Well skinfactor

Faulttransmissibility

-20 -15 -10 -5 0 5 10 15 20

Percentage Changes in Reserves

most influence on the results included gasin place, permeability and compaction(left).

Deliverability and cumulative productiondistributions were calculated from the sensi-tivity results using the parametric methoddeveloped for oilfield applications by P.J.Smith and coworkers at British Petroleum.11

A normalized average profile was combinedwith these distributions in a Monte Carlosimulator to give a probabalistic productionprofile (below).

The results of the risk analysis showed theeffects of different production scenarios onthe level of confidence in ability to delivervarious possible contracted rates of gas overthe initial plateau period. (next page,bottom). The required 90% confidencelevel for a three-year plateau period wasachieved by modifying the production ratein the first year, adding a contingency wellin the third year, and commingling produc-tion in one well between the main Erskinereservoir and the smaller but higher-perme-ability Kimmeridge reservoir.

As a result, Texaco has modified produc-tion plans, which now call for a lower pro-duction rate in the first year than in subse-

23Summer 1996

Confidence levels, %

1 2 3 4

90/90/90 None 4.5 75 75 75 40 0.707 0.898 1.139

80/90/90 None 4.5 85 75 75 40 0.699 0.889 1.119

90/90/90 4.5 85 85 75 45 0.738 0.937 1.176

80/90/90 Erskine andKimmeridge in E1

4.5 90 90 80 55 0.738 0.932 1.170

90/90/90 Erskine andPentland in E1

4.5 70 70 65 30 0.682 0.858 1.082

90/90/90 None 4.5 65 3095 95 0.704 0.892 1.119

90/90/90 None 5.5 3095 95 70 0.685 0.863 1.091

Erskine andKimmeridge in E1

80/90/90Extra wellin year 3

4.5 90 90 95 85 0.789 1.000 1.264

3

3

3

3

3

4

3

3

Erskine andKimmeridge in E1

Normalized reserves

90 50 10

Yearly rate,MMscf/D

Commingling Tubingsize, in.

Numberof wells Year Confidence level, %

■■Results of riskanalysis rankingsome of the simu-lated productionscenarios. Therequired 90% confidence level(bottom line) wasachieved by reduc-ing the productionrate in the first year,adding a well inthe third year andcommingling pro-duction from theKimmeridge and Erskine reservoirs.

N

BraePiperClaymore

BuchanBeatrice

Montrose

Britannia

Forties

Fulmar

Aberdeen Erskine

Lomond

Charlie

Delta

Bravo

Alpha

Echo

Forties field

U K

■■The Forties field inthe North Sea, oper-ated by BP with fiveplatforms and 103wells.

11. Smith PJ, Hendry DJ and Crowther AR: “The Quan-tification and Management of Uncertainty inReserves,” paper SPE 26056, presented at the SPEWestern Regional Meeting, Anchorage, Alaska,USA, May 26-28, 1993. ■■Production in the Forties field since 1975.

Pro

duct

ion,

103

B/D

0

100

200

300

400

500

600

1975 1980 1985 1990 1995 2000 2004

Oil production Water production

Year

Currentproduction

quent years. Risk analysis suggested anadditional well in the third year, so platformconstruction has allowed a slot for a contin-gency well. In addition, production from theErskine and Kimmeridge reservoirs will alsobe commingled.

Infill DrillingInfill drilling is an expensive stage in the lifeof a reservoir. Simulation, in conjunctionwith other tools, can help guide the place-ment of wells and minimize their number.British Petroleum has harnessed simulationalong with new reservoir description to opti-mize infill drilling in the Forties field in theNorth Sea (right).

The Forties field was discovered in 1970,and produced its first oil in 1975 (middle).Current production is from five platforms,with 78 producers and 25 peripheral injec-tors. Estimated recovery of the 4.2 billionstock tank barrels (STB) of original oil inplace (OOIP) is 60%, or 90% of the mov-able oil.

The field is characterized by high perme-ability, high net-to-gross (NTG) pay thick-ness and a strong aquifer. A few years agothe Forties was considered to be essentiallya homogeneous reservoir. But early waterbreakthrough and water fingering indicateda greater level of heterogeneity thanexpected, and suggested the need for morewells to be drilled to reach bypassed zones.To understand the potential of infill drillingin the field, a simulation study was con-ducted, including careful reinterpretation ofexisting 3D seismic data and a new reser-

300-m Grid

50-m Grid

GeostatisticalModel

24 Oilfield Review

■■Steps in the simu-lation study of theForties Alpha plat-form area. Simula-tion with a coarsefull-field model(top) identifiedregions that wouldbenefit from infillwells. Once aregion was identi-fied as a possibleinfill well location,the location wasselected for a newsimulation studywith local gridrefinement (middle)spotlighting thevolume of interest.Reservoir proper-ties were dis-tributed in the LGRgrid based on ageostatisticalmodel (bottom) ofthe turbidite sand-stones.

Shale Water Oil

Prediction Actual

FA31ST FA31ST

■■Fluid and formation distributions predicted (left) and encountered (right) at the FortiesAlpha 31 sidetrack (FA31ST) location. The predicted distribution closely resembled thelayering encountered, and predicted oil production matched the current rate.

voir characterization to describe the hetero-geneities encountered in the turbidite sand-stone reservoir.

Simulation with a coarse full-field modelallowed identification of regions that mightbenefit from infill wells, but the results werenot refined enough for detailed well place-ment. Once a region was identified as con-taining possible infill well locations, otheraspects were considered, such as: water cutand production of surrounding wells; inter-ference tests confirming continuity or lackthereof with other layers; and reinterpreta-tion of 3D seismic data for channel identifi-cation—prospective locations tend to bealong submarine channel margins, wherethere is lower vertical permeability and soless efficient sweep.

Having passed these tests, the area wastapped for a new simulation study with localgrid refinement spotlighting the volume ofinterest (below right). The refined grid blocksize was about 50 by 50 m [164 ft by 164 ft]in area by 8 m [26 ft] in depth. Reservoirproperties were distributed in the LGR gridbased on a geostatistical model. Then theflow in the LGR grid was simulated with theECLIPSE black-oil simulator and checkedagainst the production history from wells inthe grid. The property distribution wasmodified and simulation rerun. This processwas repeated until a history match wasobtained, with only six iterations required.

The final simulation based on the refinedgrid predicted a fluid distribution at the For-ties Alpha 31 sidetrack (FA31ST) location(above right). The predicted fluid distribu-tion closely resembled that encountered andthe predicted oil production matched thecurrent rate. However, the predicted net-to-gross rock volume of the upper zone wasoptimistic relative to measured values.Lessons learned from this work have beenfed back into subsequent studies with, forexample, seismic attributes helping to char-acterize the NTG variation in the reservoir.Simulation played a similar role in assessingthe potential for infill drilling around theother platforms.

R.14 R.13 R.12W2

T.7

T.6

T.5

S a s k a t c h e w a n

Saskatoon

Yorkton

Regina

Moose Jaw

SwiftCurrent

Weyburn Unit

U n i t e d S t a t e s

C a n a d a

■■Weyburn field of southeastern Saskatchewan, Canada. Discov-ered in 1955, the Weyburn field has produced 314 million STB, or28% of the unit’s original oil in place.

Density Porosity

Neutron PorosityGamma Ray

0 150 45 -15%API

Producer CO2 Injection

Planning Enhanced Oil RecoveryIn an example of simulation later in reser-voir life, PanCanadian Petroleum Limited isrelying on simulation to examine the feasi-bility of CO2 injection in Unit 1 in the Wey-burn field of Saskatchewan, Canada(right).12 This field was discovered in 1955and put on waterflood in 1964. By 1994,recovery had reached 314 million STB, or28% of the unit’s original oil in place. Ulti-mate waterflood recovery is expected to be348 million STB, or 31%, leaving a largetarget for enhanced recovery methods. Anopportunity to take advantage of onemethod, gravity segregation via CO2 injec-tion, is presented by the division of thereservoir into swept and unswept layers.Carbon dioxide injected into the lower,more permeable formation has the potentialto contact large amounts of unswept oil inthe tight upper formation since CO2 is 30%less dense than the reservoir fluids at theexpected operating pressures (below right).

Evaluating the feasibility of CO2 injectionproceeded in stages. First, using the Geo-Quest fluid PVT simulation software, a nine-component equation of state was developedthat reproduced the behavior of the oil-CO2

system. The equation of state also had topredict the development of dynamic misci-bility in flow simulations while still repre-senting the physical properties of the oil-CO2 mixtures. The equation was validatedby comparison of simulated and laboratoryfloods on cores.

Second, general performance parameterswere established for the formations to beswept. These included CO2 slug size, awater-alternating-gas injection strategy, CO2

start-up pressure and post-CO2 blow-downpressure.13 Then various orientations ofinjectors, producers and horizontal wellswere tested with the ECLIPSE compositional

25Summer 1996

12. Burkett D, Besserer G and Gurpinar O: “Design ofWeyburn CO2 Injection Project,” presented at theSecond ECLIPSE International Forum, Houston,Texas, USA, April 15-19, 1996.

13. Blow-down pressure is the average field pressuremaintained after CO2 injection is stopped. Usuallythis is lower than during CO2 injection to maximizeoil recovery due to expansion of CO2.

Marly

Vuggy

Unswept Zone

SweptZone

5 m

■■Division of the reservoir into swept and unswept layers, openingthe opportunity for gravity segregation of injected CO2. Carbondioxide (blue arrows) injected into the lower, more permeable for-mation will rise to displace the oil (green arrows) remaining in thetight, unswept upper formation.

26

k max

kmin

Weyburn Unit

40-acrevertical infill

Original80-acre infill

60-acrevertical infill

Horizontalsidetrack

■■A Weyburninverted nine-spotpattern showingvertical and horizontal infill well locations and directions ofmaximum andminimum perme-abilities (kmax,kmin). Various orientations ofinjectors, produc-ers and horizontalwells were testedwith the ECLIPSEcompositional simulator to determine optimalorientations andspacings.

■■Reservoir link with surface facility. Integrating surface network simulators with reservoir simulators will allow production managersto optimize flow and fine-tune field planning.

simulator (left ).14 Each original nine-spotpattern was found to require two symmetri-cally positioned horizontal wells in theupper zone to take advantage of the CO2

segregation process. Results of the paramet-ric pattern studies, using a 30% pore vol-ume CO2 slug, indicated ultimate recoverywithout any new horizontal wells to be anestimated 37% of OOIP. By adding twohorizontal wells in each injection pattern,simulation predicted incremental recoveryof 7.2%.

On the SurfaceOnce hydrocarbons have made it up thewellbore, most reservoir engineers considertheir job done. But tracking fluid movementthrough a complex surface network withchokes, valves, pumps, pipelines, separatorsand compressors remains a daunting task.Optimizing flow through the surface net-work allows production managers to mini-mize capital investment in surface facilitiesand fine-tune field planning.

Reservoir simulators are not designed tosolve for fluid flow all the way through thesurface-gathering facility, but they can beintegrated with network simulators built forthis purpose. An example of such a networksimulator is the Simulation SciencesPIPEPHASE system. The PIPEPHASE simula-

Oilfield Review

14. Mullane TJ, Churcher PL, Tottrup P and EdmundsAC: “Actual Versus Predicted Horizontal Well Performance, Weyburn Unit, S.E. Saskatchewan,”Journal of Canadian Petroleum Technology 35, no. 3(March 1996): 24-30.

15. Dutta-Roy K: “Surface Facility Link: Production Plan-ning with Open-ECLIPSE and PIPEPHASE,” pre-sented at the Second ECLIPSE International Forum,Houston, Texas, USA, April 15-19, 1996.

■■Speeding up simulation withparallel processors. For a typicalsimulation, the 16-processor runis more than 10 times faster thana single-processor run.

Run

tim

e, s

ec

Number of processors1 2 4 8 16

Simulation Speedup with Parallel Processors

0

500

1000

1500

2000

2500

tor, based on a pressure-balance techniquedeveloped originally at Chevron in the1980s, has been adapted to handle large,field-wide, multiphase flow networks,including wells, flowlines and associatedsurface facilities. Through a joint projectbetween GeoQuest Reservoir Technologiesand Simulation Sciences, the PIPEPHASEsimulator and the NETOPT production opti-mizer are being integrated with the Open-ECLIPSE system to provide a way to simulatefluid flow seamlessly from reservoir throughsurface network (previous page, top).15 Inte-gration is achieved through an iterative algo-rithm that minimizes the differencesbetween the well flow rates calculated bythe two simulators from a given set of flow-ing well pressures.

The recent focus on integrated reservoirmanagement teams is a major step in thedirection of integrated reservoir and surfacenetwork simulation. But the emphasis hasbeen on integration at the upstream end.The next step is to focus at the productionand surface facilities end.

Traditionally, the integrated study has beenapproached along two independent paths.For a project involving pressure mainte-nance through water injection, for example,the impact on the reservoir has been studiedin isolation. The reservoir simulation is car-ried out with a simplified well model:hydraulic behavior of injection or produc-tion wells is approximated through flowtables derived from single-well analysis. Asecond study is typically performed by thefacilities engineering group to evaluate theimpact of the injection water requirementson the surface facilities. The reservoirbehavior at the well is incorporated throughan injectivity index relating injection rate topressure drop at the formation.

A limitation of this divided approach isthat it ignores the true interaction betweenthe elements of the surface network, theproduction and injection wells, and thereservoir. The results of a truly integratedstudy could be quite different.

The iterative approach to integrating thePIPEPHASE and ECLIPSE systems, while rig-orous, may be limited by convergenceissues in more complex applications. Thetruly integrated solution, with the surfaceand reservoir equations solved simultane-ously, is expected to require a large effort,since significant restructuring will beneeded in both simulators. One promisingapproach is to initially develop a simple sin-gle-phase application for a gas field. Theexperiences developed in this effort couldthen be extended to address the larger prob-lem of multiphase fluids.

Summer 1996

The Next StepThe future of reservoir simulators may paral-lel developments in other oilfield technolo-gies that provide a view of fluid and rockbehavior in the subsurface. For example, theseismic industry, operating on a similarphysical scale and on equally staggeringamounts of data, has turned to massivelyparallel processors (MPPs) for data process-ing and to high-performance graphics work-stations for visualization of the results.

Simulation computer codes are being pre-pared for implementation on MPPs, but theswitch cannot be made quickly. A simulatortypically solves the fluid-flow equations onegrid block at a time. The solution does notnecessarily benefit by processing severalsteps in parallel.

For a typical simulation, doubling thenumber of processors cuts simulation timealmost in half, and increasing to 16 proces-sors reduces the time to one-tenth (above).Departure from ideal speed gains—16 timesfaster for 16 processors—is due to three fac-tors. First, the parallel linear equation solu-tion method is less efficient than the non-parallel solution. Second, it takes time toassemble and transfer data between pro-cesses. And third, load balancing betweenprocessors is uneven: some parts of thereservoir are easier to solve than others, butthe simulation must wait for the slowest.Also, the high cost of MPPs targets them forsharing within departments or companies,so one user is less likely to get sole access.

Early tests on parallelized versions of theECLIPSE simulator indicate that gains inspeed depend on the complexity of thereservoir model. A North Sea case with two-

phase flow of oil and water in a relativelysimple reservoir with 50,000 grid blocksexhibited a four-fold speed up using eightprocessors, and even greater gains for biggermodels. But three-phase flow simulation ina 1.2-million block model filled randomlywith geostatistically derived data with highlyvariable permeability showed less dramaticimprovement.

One application of simulators that willundoubtedly benefit from implementationon MPPs is that of testing multiple scenar-ios. Simulation results are most valuable in acomparative sense. Comparisons can bemade of the production behavior of differentreservoir models to gain understanding ofsensitivity to input parameters. Or differentproduction scenarios may be tested on asingle reservoir model. Running such simu-lations simultaneously will save time andallow comparisons to be made efficiently.

In the family of tools designed to help oilcompanies make effective use of expensive,hard-won data, simulation plays a key rolein making sense of data acquired throughdifferent physical experiments, at differenttimes, at different spatial scales. Simulationis one of the few tools available for under-standing the changes a reservoir experiencesthroughout its life. Used together with othermeasurements, simulation reinforces con-clusions based on other methods and leadsto a higher degree of confidence in ourunderstanding of the reservoir. —LS

27

28

The Many Facets of Pulsed Neutron Cased-Hole Logging

Ivanna AlbertinHarold DarlingMehrzad MahdaviRon PlasekSugar Land, Texas, USA

Italo CedeñoCity Investing Company Ltd.Quito, Ecuador

Jim HemingwayPeter RichterBakersfield, California, USA

Marvin MarkleyBogota, Colombia

Jean-Rémy OlesenBeijing, China

Brad RoscoeRidgefield, Connecticut, USA

Wenchong Zeng Shengli Petroleum Administration BureauChina National Petroleum CorporationChina

■■The multipurposeRST service. Car-bon-oxygen ratio,inelastic and capture spectra,sigma, boreholeholdup, porosity,water and oilvelocities, andborehole salinityare some of themeasurements thatcan be made withRST equipment.

For help in preparation of this article, thanks to DarrelCannon, Wireline &Testing, Sugar Land, Texas; EfrainCruz, GeoQuest, Quito, Ecuador; Steve Garcia, GeoQuest, Bakersfield, California, USA; Michael Herronand Susan Herron, Schlumberger-Doll Research, Ridge-field, Connecticut, USA; Chris Lenn and Colin Whittaker,Schlumberger Cambridge Research, Cambridge, Eng-land; and Chris Ovens, GeoQuest, Aberdeen, Scotland.In this article, CNL (Compensated Neutron Log), CPLT(Combinable Production Logging Tool), ELAN (ElementalLog Analysis), FloView, FloView Plus, FMI (Fullbore Formation MicroImager), Phasor (Phasor Induction SFL),RST (Reservoir Saturation Tool), SpectroLith, TDT (Thermal Decay Time) and WFL (Water Flow Log) aremarks of Schlumberger.1. For a detailed description of the RST tool hardware

and the latest scintillation detector technology:Adolph B, Stoller C, Brady J, Flaum C, Melcher C,Roscoe B, Vittachi A and Schnorr D: “Saturation Monitoring With the RST Reservoir Saturation Tool,”Oilfield Review 6, no. 1 (January 1994): 29-39.Sigma is a measure of the decay rate of thermal neu-trons as they are captured.

2. Holdup is a measure of the volumetric percentage ofeach phase in the borehole. Water holdup plus oilholdup plus gas holdup equals unity. Flow rate equalsholdup multiplied by area and by velocity.

Advanced neutron generator design and fast, efficient gamma ray

detectors combine to make a reservoir saturation tool that is capable

of detailed formation evaluation through casing and more. Lithology

determination, reservoir saturations and flow profiles are some of the

comprehensive answers provided by this multipurpose tool.

To manage existing fields as effectively andefficiently as possible, reservoir engineersmonitor movement of formation fluidswithin the reservoir as well as productionfrom individual wells. Pressure measure-ments play a vital role in reservoir manage-ment. However, these data need to be aug-mented by other measurements to detectfluid movement within the producing welland the surrounding formation. Onerecently introduced cased-hole logging tool,the RST Reservoir Saturation Tool, providesabundant single-well data to help reservoirengineers locate bypassed oil and detectwaterflood fronts, fine-tune formation evalu-ation and monitor production profiles.

A Multipurpose ServiceThe RST service was introduced in June,1992 with a through-tubing pulsed neutrontool capable of providing both carbon-oxy-gen ratio (C/O) and sigma reservoir satura-tion measurements.1 Interpretation of eithermeasurement, under suitable formation andborehole conditions, provides quantitativeoil saturation. The high-yield neutron gener-ator and high-efficiency dual-detector sys-tem provide higher gamma ray count rates,and hence better statistics, than previousgenerations of pulsed neutron devices. Thishas led to the development of many otherapplications, including spectroscopy mea-

Oilfield Review

Precise

Alpha processing

Imprecise

Accurate Inaccurate

Yields

Windows ■■Accuracy and precision. Alpha processing combinesthe accuracy of theelemental yieldscomputation of oilvolume (bottom left)with the precision ofthe windowsapproach (top right).The result is an oilvolume that is bothaccurate and pre-cise (top left).

■■Water saturation, Sw, and borehole oil holdup, Yo, crossplot. Far car-bon-oxygen ratio (FCOR) is more influenced by formation carbon, andnear carbon-oxygen ratio (NCOR) is more influenced by borehole car-bon. A crossplot of FCOR versus NCOR (crosses) can, therefore, be usedto determine water saturation and borehole oil holdup. Overlying thecrossplot is a quadrilateral whose end points are determined from anextensive data base that depends on environmental inputs such aslithology, casing size and hydrocarbon carbon density. The cornerscorrespond to 0 and 100 % Sw and 0 and 100 % Yo. Interpolation pro-vides Sw and Yo at each depth.

-0.1 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

Near carbon/oxygen ratio

Far

carb

on/o

xyge

n ra

tio

0.5

0.4

0.3

0.2

0.1

0.0

-0.1

x

xxxxxxxxxxx

xxxxxx

xxxxx

Sw=0%, Yo=0%

Sw=100%, Yo=0%

Sw=100%, Yo=100%

Sw=0%, Yo=100%

surements, accurate time-lapse reservoirmonitoring and evaluation in difficult log-ging environments such as variable forma-tion water resistivity and complex lithology.

Other features of the tool design allowseveral auxiliary measurements such asborehole salinity and thermal neutronporosity. The tool comes in twodiameters—the 111/16-in. RST-A tool and21/2-in. RST-B tool. Both use the same typeof neutron generator, detectors and electron-ics. However, the larger diameter RST-B toolincorporates shielding to focus the neardetector towards the borehole and the fardetector towards the formation, allowinglogging in flowing and unknown boreholefluids and also providing a borehole holdupmeasurement.2 More recent applications forthe RST-A tool include WFL Water Flow Logmeasurements and separate oil and waterphase velocities in horizontal wells—PhaseVelocity Log (PVL) measurements.

Essentially the RST service provides threetypes of measurements:• reservoir saturation from C/O or sigma

measurements• lithology and elemental yields from

analysis of inelastic and capture gammaray spectra

• borehole fluid dynamics from holdup,WFL and PVL measurements.This article summarizes the many facets of

RST logging and reviews several examples.

Reservoir SaturationReservoir saturation is derived from C/O orinferred from sigma measurements (see “Sat-uration Monitoring, South American Style,”next page). Inelastic gamma ray spectra areused to determine the relative concentrationof carbon and oxygen in the formation. Ahigh C/O indicates oil-bearing formations; alow ratio indicates water-bearing forma-tions. Sigma is derived from the rate of cap-ture of thermal neutrons—mainly by chlo-rine—and is measured using capturegamma rays. Saline water has a high valueof sigma, and fresh water and hydrocarbonhave low values of sigma. As long as forma-tion water salinity is high, constant andknown, water saturation Sw may then becalculated.

Carbon-oxygen—Carbon-oxygen ratio ismeasured in two ways. A ratio (C/Oyields) isobtained from full spectral analysis of car-bon and oxygen elemental yields. A secondC/O (C/Owindows) is obtained by placingbroad windows over the carbon and oxygenspectral peak regions of the inelastic spec-trum. The C/Oyields is the more accurate ofthe two ratios, but lower count rates and,therefore, poorer statistics make it less pre-

Summer 1996

cise than the C/Owindows. Conversely,C/Owindows is often less accurate but has bet-ter statistics and so is more precise. Eachratio is first transformed to give an oil vol-ume, and then the two oil volumes arecombined using an alpha processingmethod to give a final oil volume with goodaccuracy and good precision (top ). Thetransforms of C/O ratio to volume of oil usean extensive data base covering multiplecombinations of lithology, porosity, holesize, casing size and weight, as well as a

correction for the carbon density of thehydrocarbon phase.

Carbon-oxygen ratios are generated forthe near and far detectors. These two ratiosare used to give water saturation and bore-hole oil holdup (above).

Sigma—Sigma is a measure of how fastthermal neutrons are captured, a processtypically dominated by chlorine. Henceformation sigma may be considered a mea-

29

3

Saturation Monitoring, South American Style

7750

7700

Sw RST<<SwOHSw RST<<Sw OH

Lith.inelastic

RST

Depth,ft

Sand

M-1 sand

ClayLime Combined Model

0 p.u. 100Fluid Analysis

50 p.u. 100Far C/R

0 0.25

Near C/R-0.10 -0.15

Near C/RFar C/R

GR 10 API 110

SP from OH120 mV 30

Sigma 0 c.u. 30

Caliper6 in. 16

100 0p.u.

TotalPorosity

Sw from the RST

100 p.u. 0

25 0p.u.

WaterOil

Bound waterCalciteCoalSilt

QuartzClay

WaterOil

Bound water

Fanny field, situated among the oil fields east of

the Andes mountains, in the Oriente basin,

Ecuador, was discovered in 1972 and is presently

operated by City Investing Company Ltd. (below). Differential compaction of sands and shale

probably created the structural high that forms

the field. Primary production is from the M-1

sandstones of the Upper Cretaceous Napo with

secondary production from the Lower U sand-

stones of the Lower Cretaceous Napo.

There are six wells in Fanny field and these are

coupled to three others from the adjoining 18B

field drilled by the national oil company of

Ecuador, PetroProduction. Total output is 4000

BOPD of 22.2° API oil with a fluctuating water cut

of between 37% and 91%. Production is by

hydraulic pump.

Fanny-1 was completed as a commingled pro-

ducer in 1978 and after 18 years it was still pro-

ducing about 150 BOPD with 90% water cut from

two zones in the M-1 sand body. The high water

cut prompted City Investing to investigate.

A 111/16-in. RST-A tool was run with the well shut-

in to record carbon-oxygen ratio, formation

sigma, borehole sigma, thermal neutron porosity

and borehole salinity measurements.

0 Oilfield Review

■■Fanny-1 RST log results. ELAN Elemental Log Analysis interpretation of Sw and lithology (track 3) shows theoriginal openhole water saturation. Since then the oil-water contact has risen to 7752 ft (track 2) shown by theRST Sw of nearly 100% through the bottom section of the M-1 sand. The high carbon-oxygen ratio from 7702to 7709 ft is a coal seam. Very little of M-1 above the oil-water contact is depleted and the Lower U sand alsoshows high hydrocarbon saturation.

South America

Quito

Tigre

Tumaco

Tiputini

EsmeraldasBalao

Fanny

E C U A D O R 8400

Lower U sand

■■Fanny field location.

Formation sigma and thermal neutron porosity

improved on the original formation evaluation by

providing a better estimation of shale volume in

the silty, sometimes radioactive, sandstones,

and also more accurate lithology identification.

The final interpretation showed that high water

production was caused by a rise in the oil-water

contact to 7752 ft [2363m] (above). It also

showed that other sections of the M-1 sand were

still at original water saturation and identified

two virgin oil zones.

Tests on the interval 7710 to 7720 ft [2350 to

2353 m] confirmed the RST results with a produc-

tion rate of 900 BOPD at only 10% water cut. The

two new zones were also tested and they pro-

duced 1300 BOPD at 4% water cut.

The old perforations were cement squeezed

and the well, reperforated and recompleted, is

now producing 1000 BOPD with low water cut—

a sixfold production increase.

Bound Water

Irreducible Water

K-Feldspar

Quartz

Clay

Gamma Ray

Depth,ft

Formation Water

Phasor Oil Volume

Steam/Air 1993

Steam/Air 1995

SO from Core

0 p.u. 100

Porosity from Core

100 p.u. 0

X100

SW (11/7/93)100 p.u. 0-90 mV 120

DCAL-10 in. 0

DIT-E SO (11/7/93)0 p.u. 100

RST SO (11/27/93)0 p.u. 100

RST SO (4/16/94)0 p.u. 100

RST SO (1/30/96)0 p.u. 100

0 API 300

SP

sure of the chlorine content or salinity ofthe formation, and tracks openhole resistiv-ity curves.

The raw sigma measurement contains con-tributions from the borehole as well as theformation. To isolate the formation sigma,the neutron generator is pulsed in a dualburst pattern: a short burst followed by along burst. Near-detector measurements arestrongly influenced by the borehole environ-ment and hence borehole sigma— espe-cially for the short neutron burst measure-ment. Far-detector measurements areinfluenced more by formation sigma—espe-cially the long neutron burst measurement.

Raw sigma measurements are also affectedby neutron diffusion and environmentalvariables related to the borehole, casing,cement and formation. At the heart of thecorrection process for these effects is a database detailing thousands of combinations ofborehole sizes, casing types, formations ofdiffering porosity and lithology, and bore-hole and formation salinities. Instead of try-ing to define the response to these variablesby a single set of equations with fixedparameters, a dynamic parameterizationalgorithm uses the data base to compute thecorrected response in real-time, duringacquisition (see “The Sigma Data Base,”next page).3

Time-lapse—Once carbon-oxygen mea-surements or sigma measurements havebeen interpreted to produce saturation logs,these measurements may be repeated later tomonitor reservoir fluid movement such asoil-water contacts, secondary recovery pro-cesses or hydrocarbon depletion (right ).Good precision is important for time-lapse

(continued on page 34)

31Summer 1996

3. For more on the dynamic parameterization algorithmapproach:Plasek RE, Adolph RA, Stoller C, Willis DJ and BordonEE: “Improved Pulsed Neutron Capture Logging WithSlim Carbon-Oxygen Tools: Methodology,” paper SPE30598, presented at the 70th SPE Annual TechnicalConference and Exhibition, Dallas, Texas, USA, Octo-ber 22-25, 1995.

■■Time-lapse logging in California. This logis from a well in the middle of a field that isproduced by heating the oil in place withsteam. Steam takes a narrow path fromone wellbore to another and will, therefore,not flush out all the heavy oil. After sometime, the steam needs to be redirected toproduce bypassed oil. RST time-lapse dataare used to monitor steam location andchanges in oil saturation.

There has been little change in oil satura-tion of the upper intervals X100 to X190 ft(track 2). The lower interval, X200 to X270ft, shows some oil movement. Steam hasbeen turned off in the zone X195 to X205 ftwhich has resaturated with water (track 3).

X200

X300

The Sigma Data Base

■■The SchlumbergerEnvironmental EffectsCalibration Facility,Houston, Texas, USA.Over 4000 measure-ments were made inmore than thirty forma-tions of differing lithol-ogy and porosity, withdifferent combinationsof formation salinities,borehole salinities, andcompletions to producethe sigma data base.

■■EUROPA facility, Aberdeen, Scotland.

32 Oilfield Review

1. Plasek RE et al, reference 3, main text.2. McKeon DC and Scott HD: “SNUPAR—A Nuclear

Parameter Code for Nuclear Geophysics Applications,”Nuclear Physics 2, no. 4 (1988): 215-230.

Diffusion, borehole and lithology effects must be

considered when transforming raw pulsed neu-

tron capture measurements to actual physical

quantities. These effects are difficult to account

for in direct analytical approaches across the

entire range of oilfield conditions. Therefore, an

extensive data base of laboratory measurements

is used to correct for these effects in real time.1

Over several years, the data base was acquired

for the RST-A, RST-B and TDT-P logging tools at

the Schlumberger Environmental Effects Calibra-

tion Facility (EECF), Houston, Texas (above andright). This enables raw tool measurements to be

referenced to calibrated values of formation

sigma, borehole salinity and formation porosity

for a variety of environmental conditions. Each

tool was run in over 30 formations of different

lithologies and porosities. Formation and bore-

hole fluid salinities were varied and different

completions were introduced into the borehole

representing different casing sizes and cement

thicknesses.

Altogether more than 1000 formation-borehole

combinations were measured for each tool. Mod-

eling was used to extend the range of available

sandstone formations. To date, the data base con-

tains over 4000 points.

The sigma values of the database formations

are calculated classically

∑ = (1-Φ) ∑ ma + Φ Sfl∑ fl

where Φ is the formation porosity, ∑ ma is

matrix sigma, Sfl is the formation fluid saturation

and ∑ fl is fluid sigma.

Porosity of the EECF tank formations was deter-

mined by carefully measuring all weights and vol-

umes of the rocks, fluids and tanks used. CNL

Compensated Neutron Log measurements veri-

fied the porosity values and the homogeneity of

the formations.

Matrix sigma values were determined by gross

macroscopic cross-section measurements pro-

vided by commercial reactor facilities and by pro-

cessing complete elemental analyses through

Schlumberger Nuclear Parameter (SNUPAR)

cross-section tables.2

Water salinity was determined by a calibrated

titration procedure and then converted into fluid

sigma again using SNUPAR cross-section tables.

Algorithm—RST Sigma Processing

A three-step sequence is performed to translate

raw log measurements into borehole salinity,

porosity, corrected near and far sigma and forma-

tion sigma (next page, top).The first step is to correct the near and far

detector time-decay spectra for losses in the

detection and counting system, and for back-

33Summer 1996

STEP 3

STEP 1Correction to Spectra

Counting loss correctionsBackground adaptive filtering

Background subtraction

STEP 2

Transform from Apparent toCorrected Quantities

ExternalKnowledge(Optional)Porosity

Borehole salinity

ToolCalibration

Near/far ratio

Data Base

InputTime decay spectra

Compute Apparent QuantitiesNear apparent borehole sigma SBNAFar apparent formation sigma SFFANear/far capture count rate ratio TRAT

EnvironmentalParametersBorehole size

Casing size/weightLithology

OutputsBorehole salinity BSAL SIBFPorosity TPHICorrected near and far sigma SFNC SFFCFormation sigma SIGM

0

0

5

10

15

20

25

30

35

Assigned sigma, c.u.

Mea

sure

d si

gma,

c.u

.

LimestoneSandstoneDolomite

60

Mea

sure

d si

gma,

c.u

.

Assigned sigma, c.u.50403020100

60

50

40

30

20

10

0

-1.5 0.0 1.5Deviation from assignedsigma, c.u.

5 10 15 20 25 30 35Sigma, c.u.

250

200

150

100

50

00 10 20 30 40 50

Bor

ehol

e sa

linity

, kpp

m N

aCl

41 p.u.18 p.u. 0 p.u.

■■Processing accuracy. Benchmark measurements were made to assess the accuracy of the algorithm in computing formation and borehole sigma, porosity and bore-hole salinity. Sigma measured with the RST-A tool versus assigned database sigma (left) shows average errors are small—0.22 c.u. Sigma measured at the EUROPAfacility in Aberdeen (middle) again shows excellent agreement with the assigned values. Comparison of RST-A tool sigma (right) versus borehole salinity shows that corrected sigma is independent of borehole salinity—vital for time-lapse surveys or log-inject-log operations. In the crossover region (shaded area), formation sigmaapproaches or even exceeds borehole sigma. Historically, pulsed neutron capture tools erroneously identify the borehole decay as formation sigma and formation decayas borehole sigma in this region. However, the RST dynamic parameterization method solves this long-standing problem, correctly distinguishing between formation andborehole sigma components.

■■Simplified RST sigma processing.

ground radiation. Typically the background is

averaged to improve statistics.

The next step is to generate the apparent quan-

tities from the spectra, such as near and far

apparent formation sigmas. These quantities are

not environmentally corrected.

The third step is to apply transforms and envi-

ronmental corrections to the apparent tool quanti-

ties to arrive at borehole salinity, porosity and

formation sigma. The technique uses dynamic

database parameterization that handles both the

transformation and environmental corrections.

Accuracy

A series of benchmark measurements has been

made to assess the accuracy of the algorithm

used with the data base to compute borehole

salinity, porosity and formation sigma (below).These benchmark measurements include repro-

cessing the entire data base as well as logging in

industry standard facilities such as the EUROPA

sigma facility in Aberdeen, Scotland (previouspage, top right) and the API porosity test pit,

at the University of Houston, in Texas.

Database points were reprocessed with the

dynamic parameterization algorithm and the

results were compared with the assigned values.

34 Oilfield Review

Per

mea

bilit

y, m

d

Dispersed clay, %0 0. 2 0.4

500

400

300

200

100

0

60030 p.u.

20 p.u.

10 p.u.

20 p.u. 15% Calcite

4. For more details on time-lapse monitoring see sec-tions on precision and auxiliary measurements: Plasek RE et al, reference 3.

5. Herron M: “Estimating the Intrinsic Permeability ofClastic Sediments from Geochemical Data,” Transac-tions of the SPWLA 28th Annual Logging Symposium,London, England, June 29-July 2, 1987, paper HH.

6. Roscoe B, Grau J, Cao Minh C and Freeman D: “Non-Conventional Applications of Through-TubingCarbon-Oxygen Logging Tools,” Transactions of theSPWLA 36th Annual Logging Symposium, Paris,France, June 26-29, 1995, paper QQ.

■■Effect of clay andcalcite on perme-ability. A smallpercentage of clayhas a dramaticeffect on perme-ability. Calcite alsoreduces perme-ability. So to deter-mine a well’s pro-ducibility or thecause of any for-mation damage, itis important tounderstand themineralogy.

3. For examples of repeatability—precision—see: Plasek et al, reference 3, main text.

7. Herron SL and Herron MM: “Quantitative Lithology:An Application for Open and Cased Hole Spec-troscopy,” Transactions of the SPWLA 37th AnnualLogging Symposium, New Orleans, Louisiana, USA,June 16-19, 1996, paper E.

8. See Roscoe B et al, reference 6.

techniques, which by definition look at dif-ferences from one log to another over aperiod of several months. RST data can begathered at logging speeds nearly three timesthose of previous-generation tools for thesame precision.4

LithologyAssessing reservoir deliverability andenhancing zone productivity rely on a thor-ough understanding of the rock matrix. Forexample, clay content dramatically affectspermeability (above ).5 Elemental yieldsderived from RST spectroscopy measure-ments provide the input to determine clayand other mineral content and henceimprove understanding of the rock matrix.

Elemental yields—Neutrons interact withthe formation in several ways. Inelastic andcapture interactions produce spontaneousrelease of gamma radiation at energy levelsthat depend on the elements involved. Mea-surement of the gamma ray spectra pro-duced by these interactions can then beused to quantify the abundance of elementsin the formation. Elemental yields are oftenused in various combinations or ratios to aidcomplex lithology interpretation, to deter-mine shale volume or to augment incom-plete openhole data (see “Making Full Useof RST Data in China,” page 36).

At high neutron energies, inelastic interac-tions dominate. After a few collisions, neu-tron energy is reduced below the thresholdfor inelastic events. The probability of aninelastic interaction occurring is also rea-sonably constant for all major elements.

As neutrons slow to thermal energy levels,capture interactions dominate. Some ele-ments are more likely to capture neutronsthan others and so contribute more to thecapture gamma ray spectrum.

Inelastic and capture gamma ray spectraare recorded by opening counting windowsat the appropriate time after a neutron burstfrom the RST neutron generator. Tool designallows not only for much higher gamma raycount rates than previous generation tools,but also for gain stabilization that enableslower gamma ray energy levels to berecorded for both inelastic and capturemeasurements. A major advantage of this isthe inclusion of the inelastic gamma raypeaks on the spectrum at 1.37 MeV formagnesium and at 1.24 MeV and 1.33 MeVfor iron.6

A library of standard elemental spectra,measured in the laboratory for each type oftool, is used to determine individual ele-mental contributions (next page).

SpectroLith interpretation—SpectroLithprocessing is a quantitative mineral-based

The algorithm does exceptionally well in match-

ing the assigned values. For example, the aver-

age errors for formation sigma were 0.22 capture

units (c.u.) for the RST-A tool and 0.20 c.u. for

the RST-B tool.

The EUROPA facility is an independent sigma

calibration facility partially funded by the UK

Atomic Energy Authority with major support from

a consortium of 15 oil companies and govern-

ment agencies. The RST-A tool was run in all the

openhole formations and several cased-hole for-

mations. A smaller number of measurements

were made with the RST-B tool. Both tools read

the true formation sigma over a wide range of

lithologies, porosities, formation and borehole

fluids, borehole sizes and completions. Even in

the difficult crossover region, where formation

sigma approaches or exceeds borehole sigma,

the errors are small and the tool does not lock on

to the wrong sigma component.

Both EUROPA and the University of Houston API

pits were used to check porosity readings. The

agreement between the two sets of porosities

was excellent.

Precision

Key to time-lapse monitoring techniques is

repeatability or precision. Time-lapse uses differ-

ences in measured quantities to monitor, for

example, the progress of waterflooding, the

expansion of gas caps and the depletion of reser-

voirs. The RST tool has been benchmarked to log

nearly three times faster than previous genera-

tion tools for the same level of precision.3

Iron

ChlorineSilicon

Titanium

Calcium

Sulfur

HydrogenGadolinium

Oxygen

Inelastic Spectra

Capture Spectra

Silicon

Iron

Calcium

Magnesium

SulfurBackground

Carbon

Energy, MeV1 2 3 4 5 6 7 8

Rel

ativ

e co

unts

1 2 3 4 5 6 7 8Energy, MeV

Rel

ativ

e co

unts

35Summer 1996

■■Elemental stan-dards for the RST-Atool. Lower gammaray energy levelsare recorded by theRST tools than byprevious generationpulsed neutron tools.This allows mea-surement of elemen-tal contributionsfrom elements suchas magnesium andiron. Elementalyields are processedfrom standard spec-tra obtained usinglaboratory measure-ments. Shown arethe standards forinelastic (top) andcapture (bottom)spectra for the1 11/16-in. RST-A tool.

lithology interpretation derived from elemen-tal yields. Traditional lithology interpretationrelied on measurements of elements such asaluminum and potassium to determine claycontent. Aluminum, especially, is difficult tomeasure and requires a combination of log-ging tools; the interpretation is also complex.

A recent detailed study of cores showedthat a linear relationship exists between alu-

minum and total clay concentration. Ofmore importance, it also showed that sili-con, calcium and iron can be used to pro-duce an accurate estimation of clay withoutknowledge of the aluminum concentration.7The concentrations of these three elementscan be obtained from RST spectroscopymeasurements.

In addition, carbonate concentrations—defined as calcite plus dolomite—can bedetermined from the calcium concentration

alone with the remainder of the formationbeing composed of quartz, feldspar andmica minerals.

SpectroLith interpretation involves threesteps:• production of elemental yields from

gamma ray spectra• transformation of yields into concentra-

tion logs• conversion of concentration logs into

fractions of clay, carbonate and frame-work minerals.

Borehole FluidThe producing wellbore environment mayinclude a combination of oil, water and gasphases in the borehole as well as flowbehind casing. Borehole fluid interpretationis primarily based on fluid velocities andborehole holdup. The RST equipmentmakes these measurements using severalindependent methods, with enough redun-dancy to provide a quality control crosscheck:• The WFL Water Flow Log measures water

velocity and water flow rate using theprinciple of oxygen activation. Thismethod detects water flowing inside andoutside pipe, and in up and down flow.

• The Phase Velocity Log (PVL) measuresoil and water velocities separately byinjecting a marker fluid, which mixes andtravels with the specified phase. Thismethod may be applied to up and downflow, but only fluids in the pipe aremarked and therefore detected.

• Two-phase—oil and water—boreholeholdup may be measured in continuouslogging mode with the RST-B tool.8

• Three-phase—oil, water and gas—bore-hole holdup is currently an RST-A stationmeasurement based on a combination ofC/O and inelastic count rate ratio data.

• Borehole salinity is one of the computa-tions made as part of the sigma and poros-ity log and may be used to compute aborehole water holdup with either theRST-A or the RST-B tool.

(continued on page 39)

36 Oilfield Review

■■Location of Gu Dao and Sheng Tuo fields.

Making Full Use of RST Data in China

C H I N A

Hong Kong

TAIWAN

Shanghai

Qingdao

M O N G O L I A

Beijing

Sheng Tuo Gu Dao

Beijing

Shengli Complex

Bo Hai Gulf

1. Olesen J-R, Chen Y, Zeng W, Zhu L and Zhang Z:“Remaining Oil Saturation Evaluation in Water FloodedFields Under Variable Formation Water Resistivity,” to bepresented at the 1996 International Symposium on WellLogging Techniques for Oilfield Development, Beijing,Peoples Republic of China, September 17-21, 1996.

Gu Dao and Sheng Tuo are typical of the Shengli

complex of oil fields about 200 km [125 miles]

southeast of Beijing near the Bo Hai Gulf, China

(right).1 Both fields have a similar deltaic deposi-

tional environment, with alternating sand-shale

sequences. Thin, tight, calcareous streaks within

the depositional sequences are common. Reser-

voir layer thickness varies from more than 10 m

[31.2 ft] to less than 1 m [3.1 ft] and each layer is

produced separately.

For more than 30 years, many of these eastern

Chinese oil fields have been under water injec-

tion to maintain pressure and improve sweep of

the heavy hydrocarbons. The water injection pro-

gram uses a mix of the low-salinity connate water

and fresh surface water, which has resulted in

variable and unknown water resistivity in many

reservoirs.

In order to efficiently manage the waterflood

enhanced oil recovery program and maximize oil

recovery, it is essential to know the waterflood

sweep efficiency, determine residual or remain-

ing oil saturation, and pinpoint zones bypassed

by the recovery scheme.

Hydrocarbon saturation evaluation from open-

hole resistivity logs, run in newly drilled infill

wells, is difficult because the formation water

resistivity is variable and most of the time

unknown. Reservoir saturation monitoring with

sigma measurements is impractical, as there is

little contrast between the oil and water sigmas

and, in any case, the water sigma is unknown.

These constraints leave carbon-oxygen measure-

ments as the only viable option.

The Shengli oilfield operators—Shengli

Petroleum Administration Bureau, China National

Petroleum Corporation (SPAB-CNPC)—decided to

run the 21/2-in. RST-B tool for many reasons:

•The shielded dual-detector system alleviates

the effect of a changing or unknown borehole

oil holdup, as well as the effect of waxy

deposits on the casing.

•Through-tubing logging, while the well was

flowing, avoids formation damage and also

increases operational efficiency in a multiwell

campaign.

•The 51/2-in. casing inside 81/2-in. borehole

completion produces a thick cement sheath

that reduces measurement sensitivity. The RST

tool has a high-energy, high-yield neutron gen-

erator and an efficient detection system that

provide better statistics in thick cement than

the previous-generation pulsed neutron tools.

• An additional pass in sigma mode provides

data useful to accurately evaluate shaliness,

especially in wells with scarce openhole data.

• Measurements such as neutron porosity and

count rates can also be recorded to aid inter-

pretation when gas is present.

Evaluation with Scarce Openhole Data

Key to the interpretation of carbon-oxygen data is

a knowledge of lithology to account for matrix

carbon, and effective porosity to calculate oil sat-

uration. A typical Sheng Tuo well illustrates the

benefits of additional data provided by the RST

tool (next page). For this well the openhole data

were limited to sonic and gamma ray logs.

Sonic and gamma ray data do not provide

enough lithology information to account for matrix

carbon. For example, carbonates cannot be distin-

guished from tight siliclastic streaks. Sonic-

derived porosity may also be inaccurate if lithol-

ogy and formation fluids are unknown, and also, if

the sands are unconsolidated and the compaction

factor is unknown. The gamma ray curve alone is

unsuitable for accurate shale volume evaluation

because the reservoir sands are rich in micas and

feldspars—both radioactive minerals.

To augment the limited openhole data, an RST

sigma-mode pass provided sigma for shale vol-

ume estimation and thermal neutron porosity

(TPHI) for effective porosity evaluation. The

inelastic-capture data were analyzed in detail not

only for the carbon-oxygen ratio (C/O), but also for

elemental yields to provide other ratios. For exam-

ple, the ratio of iron to silicon (IIR) is indicative of

shale volume if kaolinite and heavy minerals are

not present; the ratio of silicon to silicon-plus-cal-

cium (LIR) may be used as a lithology indicator;

and the ratio of chlorine to hydrogen (SIR) gives a

formation salinity indicator.

The initial volume of oil was computed from the

openhole resistivity data in 1994 assuming that all

sands were at connate water resistivity. The 1995

RST carbon-oxygen evaluation computed remain-

ing oil. A decrease in oil between the two may be

due to reservoir depletion, but could also be due

to an overly optimistic openhole evaluation if the

reservoir water was not at connate salinity, but at

the fresher floodwater salinity.

The additional RST data proved invaluable. For

example, in the Gu Dao and Sheng Tuo fields in

general, sigma responds primarily to changes in

matrix sigma and therefore provides the best shale

indicator. The lithology indicator ratio LIR was

used to identify the tight calcite streaks at X201 m

and X218 m.

Interpretation of the salinity indicator ratio (SIR)

is more complicated. However, when the forma-

tion water volume remains constant, SIR responds

directly to formation fluid salinity and can be used

to determine the progress of injection water—

approximately the case in the large reservoir

between X220 m and X245 m.

■■Formation evaluation with additional RST data. Volumetric analysis (track 4) shows remaining hydrocarbonsaturation determined from RST carbon/oxygen ratio. The 1994 openhole fluid curve indicates more oil due toeither depletion or an overly optimistic evaluation. A comparison of RST porosity (TPHI), cased hole CNLCompensated Neutron Log porosity (NPHI), and sonic transit time (DT), shows good agreement (track 3),especially when NPHI is put on a sandstone scale—3 to 4 p.u. shift to the left. The lithology indicator (LIR) isabout 1 for siliclastics and decreases for carbonates (track 2). Two tight calcite streaks can be seen at X201and X218 m. The salinity indicator (SIR) responds to formation salinity if porosity and hydrocarbon saturationare approximately constant (track 2). The iron indicator (IIR), gamma ray and sigma (track 1) follow the sametrend, and each may be used for shale volume calculation under the correct conditions. Gamma ray indicationof shale will be pessimistic if radioactive sands are present—for example, those containing micas andfeldspars. Clays, except for kaolinite, contain iron. Sigma responds to formation matrix and fluids. Sigma fluidis almost the same when oil and fresh water are present, so sigma responds primarily to changes in matrix. In Gu Dao and Sheng Tuo, sigma has proved to be the best shale indicator.

X200

X250

Depth, m

IIR

0 2.5

SIGM

0 c.u. 50

GR

100 API 250

LIR

0.625 1.25

SIR

-0.5 ppk 3.5

DT

150 µsec/ft 50

TPHI

60 p.u. 0

NPHI

60 p.u. 0

Openhole Analysis

0 p.u. 100

Openhole Fluid 1994

100 p.u. 0

Shale

Bound Water

Quartz

Calcite

RST Oil 1995

Water

In the shaly lower section of the reservoir,

salinity is high and probably at connate level,

indicating minimal depletion. The middle section

is the cleanest, most permeable section and

shows a progressive drop in salinity. The water-

flood front has reached this section. The upper

section shows an intermediate salinity and shale

content, and also a smaller discrepancy between

RST saturation and openhole saturation. Flooding

has reached this section, but is not complete.

Similar results have been seen with other RST

logs in these fields.

Summer 1996

Identifying Gas-Bearing Zones

Carbon/oxygen ratio responds to the carbon con-

centration in pore space. In gas-bearing zones,

carbon concentration is low, so C/O is low. Low

C/O can easily be misinterpreted as a water-bear-

ing zone. However, several auxiliary measure-

ments can help identify gas-bearing intervals:

• Gas sigma is much lower than water sigma or

oil sigma; therefore, at comparable shale lev-

els, the RST sigma measurement will be lower

in gas-bearing reservoirs.

• Hydrogen index is also low in gas-bearing

zones. Therefore, neutron porosity measure-

ments such as RST porosity (TPHI) underesti-

mate formation porosity.

• The inelastic count rate ratio (CRRA) from the

near and far detector is sensitive to porosity

and gas content.

For example, in one Gu Dao well, the upper

sand body, X103 m to X109 m, shows the pres-

ence of gas (next page, top). Sigma and CRRA

scales were chosen so that the curves overlay in

clean gas-free formations. In the upper sand they

show negative separation as both sigma and

CRRA are driven lower by the presence of gas.

Similarly, TPHI shows a reduced neutron porosity

when compared to the true formation porosity

taken from the openhole interpretation of 1990.

No gas was apparent on the 1990 openhole

logs, so it is assumed that reservoir pressure has

declined below bubblepoint allowing gas to come

out of solution. Tests indicate that this is a water-

bearing zone with some gas, confirming the RST

interpretation.

Determining Water Resistivity and Flood Index

Interpreting openhole logs of newly drilled wells

in reservoirs that have been partially or fully

flooded is challenging. Water resistivity, Rw ,

often varies continuously from the relatively high

value of fresh floodwater to the low value of the

more saline connate water. If connate water

resistivity is used for Rw , then hydrocarbon satu-

ration will be optimistic in partially flooded

zones.

However, by combining openhole and RST data

a continuously varying Rw may be calculated

leading to true hydrocarbon saturation. The eval-

uation may be taken further if floodwater resistiv-

ity is known and constant. In this case, the total

volume of water may then be split into connate

and floodwater.

Reservoir saturation acquisition timing is criti-

cal to the interpretation. It must be late enough

after well completion to allow drilling fluids to

dissipate, but before significant hydrocarbon

depletion occurs. Four weeks has proven ade-

quate for Gu Dao and Sheng Tuo fields.

Water resistivity is computed using standard

openhole interpretation methods. Openhole logs

provide Rt, Rclay, Vclay and effective porosity,

Φeff. Water saturation comes from RST interpre-

37

38

X100

X125

Depth, m

Openhole Sw 1990

100 p.u. 0

Cased Hole Sw 1995

100 p.u. 0

RST Gas Indicator

5.75 1.75

SIGM

-10.0 c.u. 30.0

Gas

Openhole Analysis

0 p.u. 100

Shale

Bound Water

Quartz

Calcite

RST Oil 1995

Water

Radius of Bit

0 in. 10

Borehole Fluid

Casing Wall

Assumed CementSheath

Formation

Openhole Porosity

50 p.u. 0

O.H. Fluid Volume 1990

50 p.u. 0

RST Fluid Volume 1995

50 p.u. 0

TPHI from Sigma mode

0.5 p.u. 0

RST Oil 1995

X290

X300

Depth,m

Radius of Bit

0 10

Borehole Fluid

Casing Wall

Assumed Cement Sheath

Formation

RST-derived Rw

0 2

Cased Hole RST Sw

100 p.u. 0

Flood Index

2 0

Openhole Porosity

50 p.u. 0

O.H. Fluid Volume 1994

50 p.u. 0

RST Fluid Volume 1995

50 p.u. 0

Nonmovable Oil

Remaining Oil RST1995

Flood Water

Openhole Analysis

0 p.u. 100

Shale

Bound water

Quartz

Nonmovable oilOpen Hole 1995

Movable RST Oil 1995Water

■■Gas detection. Inelastic count rate ratios of near-to-far detector counts and sigma are both affected by gas(track 2). Negative separation of these curves indicates gas. RST porosity, TPHI, also reads lower in gas (track3). Although no gas was shown on the openhole logs, it is assumed that solution gas has accumulated in thefully depleted zone between X100 m to X109 m. Tests indicate that the layer is mainly water and gas.

tation. The flood index is determined as a linear

interpolation between floodwater resistivity and

connate water resistivity.

In a Gu Dao field example, connate and floodwa-

ter salinities are 8.5 ppk and 3 ppk, respectively

(below left). The lower section, X296 to X303 m,

is shaly and water-bearing. The middle section,

X287 m to X296 m, is the cleanest and is separated

from the lower section by a thin, clean, sand streak

where the oil-water contact is situated.

The clean midsection has the highest permeabil-

ity and provides a preferential conduit for water-

flooding. The discrepancy between RST-derived

and openhole hydrocarbon saturation is due to the

inadequate Rw estimation for the openhole evalua-

tion. True hydrocarbon saturation is 40% as shown

by RST data and not 60%. Water resistivity, com-

puted from a synthesis of RST and openhole data,

indicates that fresh waterflooding has increased

Rw from the connate water value of 0.35 ohm-m to

about 1 ohm-m. The flood-index calculation con-

firms that the cleanest levels of this reservoir have

been heavily flooded.

The shalier upper sand section shows general

agreement between RST-derived and openhole

hydrocarbon saturation. Because of the increase in

shaliness and the related decrease in permeability,

waterflooding essentially bypasses this section

and little hydrocarbon sweep is achieved.

Campaign Success

The Shengli oilfield RST campaign has shown that

hydrocarbon monitoring in waterflooded fields with

varying salinity is a viable procedure. In addition,

ancillary RST measurements complement open-

hole information, improving both formation evalua-

tion and detection of gas-bearing intervals. Also,

the combination of openhole and RST data

acquired within one month is a powerful tool for

evaluating the waterflooding process. During the

course of the campaign, RST data contributed to

the achievement of the SPAB-CNPC engineers’ goal

of maintaining oil output while controlling water

production. RST results showed a large amount of

remaining hydrocarbon, especially in the massive

sands of the Sheng Tuo oil field.

Oilfield Review

■■Water resisitivity, Rw, and flood index. A floodindex can be calculated from variable Rw (track 2)computed from RST and openhole data collectedbefore any hydrocarbon depletion and after invasionfluids have dissipated (track 3).

■■WFL Water Flow Log service. A short burst of neutrons interactswith oxygen in the surrounding water forming an oxygen isotopewith a half-life of 7.1 sec. As the activated oxygen decays back toits steady state, gamma rays are emitted. In flowing water thecloud of activated oxygen, and hence gamma rays, travels alongat the water velocity. Characteristic increases in count rate areseen as the cloud passes the various detectors. The distancebetween neutron generator and detector and the time-of-flightgive water velocity. The initial cloud volume is proportional to theamount of oxygen present and hence volume of water. The areaunder the gamma ray peak as the cloud passes a detector is,therefore, also proportional to the volume of water flowing by(water holdup)—allowing for effects of diffusion and decay rate.Combining water velocity and holdup gives water flow rate.

16O+n p+16N β+16O* 16O+γ Half-life ~7.1sec

Minitron Oil

Water

Casing

Near Detector Far Detector Additional Detector

■■Phase VelocityLogging (PVL). A strong neutronabsorber isinjected into theappropriate phaseof producing fluid.This is subse-quently detected,allowing a time-of-flight measure-ment that gives the velocity of thatphase.

Oil

Water

Oil-miscible marker RST tool

Phase Velocity Sonde

0 10 20 30 40 50 60 70 80Time, sec

Start of injection

90

Marker signal

WFL measurements—Water flow logging,introduced with the last-generation TDTThermal Decay Time service several yearsago, is now available with the RST service.The RST neutron generator providesimproved burst control, which allows detec-tion of water velocities up to 500 ft/min[150 m/min] with the far detector alone. Inaddition, the introduction of energy discrimi-nation and shielding between neutron gener-ator and detectors results in a significantimprovement in the signal-to-noise ratio, andextends sensitivity to low flow conditions.

Oxygen molecules in water are activatedby a burst of neutrons producing a radioac-tive cloud. The cloud moves with the wateralong the borehole, emitting gamma rays asactivated oxygen decays back to its steadystate (top right). As the cloud passes, gammarays are first detected by the near detectorand then by the far detector of the RSTsonde, producing a characteristic peak inthe count rate of each. The time betweenneutron burst and cloud detection—time-of-flight—and the distance between neutrongenerator and detector give water velocity.Other detectors can be added farther awayin the tool string to detect extremely highwater velocities. The RST equipment canalso be turned upside-down to detect down-ward flow.

In addition, the volume of activated oxy-gen is proportional to the volume of waterflowing by the detectors. The profile of thedetected signal carries information aboutthe mean water velocity, water holdup andwater flow rate. These quantities are relatedin that the water velocity, water holdup andeffective cross-sectional area of the pipe canbe combined to compute the water flowrate (see “Production Logging in the SanJoaquin Basin,” next page).

PVL—Phase velocity logging has beendeveloped for horizontal wells where strati-fied flow is present. Like WFL logging, thePhase Velocity Log measures time-of-flight.Gadolinium has a very high thermal neutroncapture cross section and is injected into theproducing borehole (bottom right ). Theinjection fluid is designed to mix with eitherthe water or oil phase only. Gadolinium actsas a sink, sucking in thermal neutrons and

39Summer 1996

Production Logging in the San Joaquin Basin

X200

X400

X600

Gas

Oil

Water

Downhole Flow Rate, B/D

Water Flow Log, B/D

Pressure

Depth,ft

Temp

0 3000

01050 1300psi °F 211206 3000

Thief zone

Water Flow Stations

Recirculating water zone

4

Elk Hills is one of the largest oil fields in the San

Joaquin basin about 20 miles [32 km] west of Bak-

ersfield, California, USA (below). The field forms

part of the Naval Petroleum Reserve No. 1 and is

operated by Bechtel Petroleum Operations, Inc.

for the Department of Energy. Although Elk Hills

was discovered in 1911, production was limited

until the 1974 oil crisis resulted in opening up the

field to full production in 1976. The field has pro-

duced over 1.1 billion barrels of oil and a signifi-

cant quantity of gas, and now produces about

60,000 BOPD of medium-gravity crude.

Earlier this year, Bechtel wanted to determine

the flow profile and quantify the zonal contribu-

tions to oil, water and gas production from a well

in which production from a waterflooded sand

reservoir was commingled with production from a

shaly interval. A production log consisting of tem-

perature, pressure and spinner was run and sta-

tionary WFL Water Flow Log measurements were

taken with the RST tool.

The flow profile turned out to be complex,

showing a zone of water recirculation near the

bottom and a thief zone above (right).1

A combination of spinner and WFL data located

the recirculation zone. The spinner indicated down

flow, while the WFL data indicated a small

amount of water flowing up. The temperature log

also showed a strong anomaly over this interval.

The flow profile shows a net flow of oil from this

zone simply because a recirculation zone requires

multiphase flow.

Both spinner and WFL data show an increase in

flow above the recirculation zone before an abrupt

■■WFL Water Flow Log. The flow profile indicates that most of the gas production is from X350 to X370 ft (tracks 2 and 3). Below this depth is a complex profile of thief zone and water recirculation. WFL stationary read-ings determined the water production profile, and temperature and pressure (track 1) aided the interpretation.

1. Water recirculation occurs, usually in deviated wells,when water and oil are present. Water can flow up withthe oil on the upper side of the well and down on thelower side in a continuous cycle. A thief zone occurs when a perforated zone has a lowerformation pressure than the borehole, causing flowfrom borehole to formation.

C A L I F O R N I A

U S A

Taft

Elk hillsBakersfield

Fresno

Coalinga

San Andreas Fault

X800

■■ Location ofElk Hills field,Kern County,California.

0

decrease at X430 ft. The temperature also drops

at this point. The combination of decrease in flow

rate and temperature can occur only if the forma-

tion is taking fluid—a thief zone. Conventional

openhole logs and the mud log suggest that there

is a highly resistive, low porosity carbonate in

this interval. The FMI Fullbore Formation

MicroImager tool shows what has been inter-

preted as a calcite healed fracture. This fracture

has most likely been opened by acid treatment

and has created the thief zone.

The next significant event in the flow profile

occurs across the short perforated interval X350 to

X370 ft. Here, a large increase in spinner flow rate

and a change in slope of the pressure data indicate

an influx of gas. The WFL log shows doubling of the

water flow rate across the same interval.

Oilfield Review

GR RST

FloView toolFlow regimeWater holdup

RST Reservoir Saturation ToolOil holdupGas indicator

FloView Plus tool

Phase Velocity LogMarker injection for oiland/or water velocity

WFL Water Flow LogWater velocityWater holdupWater flow rate index

CPLT

CPLT CombinableProduction Logging ToolPressure and temperature

Fluid markerinjector

Spinner

Total flow rate

Gamma raydetector

■■The next generation production logging tool string.

9. For an alternative method of measuring boreholeholdup with the RST-A tool: Roscoe B et al, refer-ence 6.

10. Schnorr DR: “Determining Oil, Water and Gas Saturations Simultaneously Through Casing by Com-bining C/O and Sigma Measurements,” paper SPE35682, presented at the SPE Western Regional Meet-ing, Anchorage, Alaska, USA, May 22-24, 1996.

changing the borehole sigma. The detectionof this change provides a time-of-flight mea-surement for the marked phase.

Two-phase borehole holdup—The twodetectors of the RST sonde provide two car-bon-oxygen measurements that are suffi-cient to solve for formation water saturation(SW ) and borehole oil holdup (YO ) (seecrossplot, page 29 ). Four points may bedefined on a plot of far carbon-oxygen ratioversus near carbon-oxygen ratio to give aquadrilateral:• Water in the formation and water in

the borehole (SW = 100, YO = 0)• Oil in the formation and water in the

borehole (SW = 0, YO = 0)• Water in the formation and oil in

the borehole (SW = 100, YO = 100)• Oil in the formation and oil in the

borehole (SW = 0, YO = 100).

Summer 1996

The exact position of these points dependson lithology, porosity, hydrocarbon carbondensity, hole size, casing size, casing weightand sonde type—RST-A or RST-B sonde.

With the larger RST-B sonde, the quadrilat-eral is wide since the far detector is shieldedto be more sensitive to the formation andthe near detector shielded to be more sensi-tive to the borehole. This provides good sep-aration of the signals and a good boreholeoil holdup measurement in addition to a for-mation saturation measurement. The slim-mer RST-A sonde is not focused and, there-fore, requires knowledge of the boreholefluids to separate the formation and bore-hole signals.9

Three-phase holdup—A combination ofRST measurements can be used to computethree-phase holdup. Gas holdup is indicatedby the inelastic near-to-far count rate ratio.The near and far C/Oyields depend on gas,water and oil holdups. By combining thesemeasurements and applying two condi-tions—the sum of the holdups must equalunity and also the sum of the saturationsmust equal unity—three-phase holdups maybe calculated. The RST measurement ofborehole sigma can also be combined withthis analysis to enhance the holdup calcula-tion if the water salinity is known.

Comprehensive Cased-Hole EvaluationSince commercialization of the RST servicefour years ago, many applications havebeen developed. With the addition of lithol-ogy interpretation, phase velocity loggingand three-phase holdup, the tool is rapidlybecoming a comprehensive cased-holeevaluation service.10 A future OilfieldReview article will explain in more detailsome of these new services, including newproduction logging combinations (above).

—AM

41

Seamless Fluids Programs: A Key to Better Well Construction

New insights into displacement mechanics inside casing and in the annulus, combined with integrated

drilling and cementing fluid services, can improve primary cementing. This structured “fluids-train”

approach also optimizes overall drilling and completion performance at lower cost for operators.

42

Lindsay FraserBill StangerHouston, Texas, USA

Tom GriffinSugar Land, Texas

Mourhaf JabriBalikpapan, Indonesia

Greg SonesAnadarko Petroleum CorporationHouston, Texas

Mike SteelmanCalgary, Alberta, Canada

Peter ValkóTexas A&M UniversityCollege Station, Texas

For help in preparation of this article, thanks toDominique Guillot, Dowell, Clamart, France, and JasonJonas, Dowell, Sugar Land.

In this article, CBT (Cement Bond Tool), CemCADE, CET(Cement Evaluation Tool), DeepSea EXPRES, EXPRES,MUDPUSH, SALTBOND, USI (Ultrasonic Imager) andWELLCLEAN are marks of Schlumberger.

Improvements in well construction are possi-ble if long-standing boundaries betweendrilling and cementing can be eliminated,and if mud removal and displacement crite-ria are properly applied. Efficient slurryplacement for complete and permanentzonal isolation relies on effective displace-ment of drilling fluids from the casing-bore-hole annulus—mud removal—and on avoid-ing bypassing, mixing and contamination offluids in the annulus and casing duringcement placement. Understanding displace-ment mechanics is essential to successfulcementing, but an integrated drilling andcementing fluids approach is a first steptoward overall wellbore optimization.

The consequences of poor primarycementing jobs can be severe. Incompletemud removal may leave channels, allowingcommunication between subsurface zonesor to the surface. Likewise, failure to prop-erly separate fluids as they are pumpeddownhole can negate the most meticulousplans or the best designs and lead to ineffec-tive mud removal or contamination that pre-vents cement from ever setting up (harden-ing). Approaching well construction as aseries of interrelated events in which bothmud and cement play important roles—totalfluids management—results in a more con-trollable, structured process with optimalwellbores as the objective.1

Traditionally, drilling fluids and cementingservices have been provided separately andthe lack of stated, common objectives hasbeen a roadblock to optimizing these opera-tions. Better management of fluid servicesrequires drillers and cementers to worktogether from well start to finish to select

muds that achieve drilling goals, but do notimpede cementing success. Considerationmust be given to providing gauge holes thatallow casing centralization. It may be neces-sary to reduce rates of penetration—averageto high instead of very high—during drillingif that means improved borehole conditions,lower-cost primary cement jobs and reduc-tion or elimination of expensive repairworkovers. Necessary elements are avail-able and, in most cases, in place to do this;where efforts often fall short is in coordina-tion and management of the entire processto realize maximum benefits. Success interms of the final product—a safe, long-last-ing wellbore at the lowest possiblecost—should be an incentive to rethink andrestate fluid objectives.

Better understanding of annular displace-ment is a key element that is already inplace.2 By using physical and computermodeling, cementing criteria haveimproved. Simulation and design softwareallow the myriad of fluid factors and com-plicated interactions involved in primarycementing to be addressed qualitatively, andmost of the time quantitatively as well. Thetotal process (mud removal and cementplacement) including conditioning, annularflow regimes, spacer—a buffer betweendrilling muds and cement slurries—selec-tion and fluid displacement inside pipe cannow be evaluated in planning and designstages, during mud maintenance and condi-tioning, and before or after jobs.

Oilfield Review

Summer 1996

1. Fraser L and Griffin TJ: “Economic Advantages of anIntegrated Fluids Approach to the Well ConstructionProcess,” presented at the American Association ofDrilling Engineers Drilling Fluids Technology Confer-ence, Houston, Texas, USA, April 3-4, 1996.

2. Lockyear CF and Hibbert AP: “Integrated PrimaryCementing Study Defines Key Factors for Field Success,” Journal of Petroleum Technology 41(December 1989): 1320-1325.Lockyear CF, Ryan DF and Gunningham MM:“Cement Channeling: How to Predict and Prevent,”SPE Drilling Engineering 5 (September 1990): 201-208.

3. Turbulent flow occurs at higher flow rates. Individualfluid particles swirl around, but their average velocityresults in what is considered a flat velocity profile.Momentum is constantly transferring from one regionto another, but overall flow is relatively constant.

4. Specification 10D, Specification for Casing Centralizers,2nd. Dallas, Texas, USA: American Petroleum Institute,1983.Casing standoff (STO) in percent is defined as STO =2w/D - d x 100 or w/R-r x 100, where D is hole diame-ter, d is pipe outside diameter (OD), R is hole radius, r ispipe radius and w is the smallest annular gap. STO is100% when casing is concentric—perfectly centered.

5. Laminar flow occurs at relatively low flow rates. Fluidparticles move parallel to the casing axis or annuluswalls along straight lines in the direction of flow, with a parabolic velocity profile. At the walls, where liquidswet the surface, fluid particles in contact with pipe orannulus walls are stationary and velocity is zero,increasing to a maximum—twice the average velocityfor Newtonian fluids—at the center of the flow channel.

High flow rates effectively displace mud ifturbulent3 flow is achieved around the entireannulus, but are viable only if casing andhole sizes are relatively small and casingstandoff4 from the borehole is adequate.Lower flow rates can also successfullyremove mud in many cases where higherflow rates are not practical, but more sophis-ticated designs and modified fluids are oftenneeded to achieve laminar5 displacements.Spacers with controllable properties—abilityto suspend weighting agents, reasonable tur-bulent rates, adjustable rheology, compatibil-ity, low fluid loss and a wide range of appli-cations—are needed to meet and betterapply mud removal criteria (see “Engineered,Fit-To-Purpose Spacers,” page 46).6

Finally, to close the fluids loop, displace-ments inside pipe must be understoodbecause density differences may cause mix-ing of fluids or bypassing of mud by spacers,spacers by cement slurries or lead by tailslurries.7 Better understanding and applica-tion of fluid flow and displacement mechan-ics are required along with more careful

43

6. Couturier M, Guillot D, Hendricks H and Callet F:“Design Rules and Associated Spacer Properties forOptimum Mud Removal in Eccentric Annuli,” paperCIM/SPE 90-112, presented at the International Tech-nical Meeting of the Petroleum Society of CIM/SPE,Calgary, Alberta, Canada, June 10-13, 1990.Tehrani A, Ferguson J and Bittleston SH: “Laminar Dis-placement in Annuli: A Combined Experimental andTheoretical Study,” paper SPE 24569, presented at the67th SPE Annual Technical Conference and Exhibi-tion, Washington, DC, USA, October 4-7, 1992.

7. Griffin TJ: Displacement Inside Casing. SchlumbergerDowell Report (January 3, 1995).

No bottomwiper plugs

Mud Mud

Chemicalwash

Weightedspacer

Immobile mudin narrow gap

Good Bad

Chemicalwash

Weightedspacer

Float shoe

Tailslurry

Zones ofinterest Inflow

Lostcirculation

Gelled mudchannel

Tail slurrybelow zonesof interest

Mud

Good

Weightedspacer

Leadslurry

Tailslurry Bypassed

lead slurry

Tail slurryahead oflead slurry

Cementmixes withspacer

Spacerbypassesmud

Bad

Top wiperplug

Bottomwiper plugs

Floatcollar Bypassed

or mixedfluids inshoe track

Float joints(shoe track)

Top of cement too high

Borehole Geometry and Mud Removal Displacements

■■Common cement-ing problems (red)related to drilling,mud removal anddisplacement.

design of mud systems, spacer fluids andcement slurries to avoid common cement-ing problems (above). This article gives anoverview of integrated fluids services, andreviews mud conditioning and removalfrom the annulus by turbulent and effectivelaminar flow (ELF). A Dowell and TexasA&M University study defining downwardflow in pipe and proposing methods toimprove cement placement without sacrific-ing effective mud removal is also examined.

The Case for Total Fluids Management In the past, drilling and cementing fluidswere often provided under individual ser-vice contracts, often by different companies.All too frequently, the attitude seemed to be,“drill as fast as possible and worry aboutcementing after reaching TD.” Other needsand intentions, and deleterious effects thatoccur when some fluids commingle wereoften ignored. In principle, instead of segre-gating drilling and cementing fluid services,operations can be unified in a single, inte-grated process. Isolated service-line mentali-ties are replaced by a common goal of pro-viding seamless fluids programs—”fluidstrains”—to optimize overall performanceand results. Territorial considerations are for-

44

gotten, and the two disciplines worktogether to maximize the efficiency andeffectiveness of all well-construction fluids.

Good communications and coordinationare a necessity. Cementing designs are per-formed before drilling is complete, sochoices about flow regime—turbulent orlaminar—and spacer properties are madeassuming hole size and mud characteristics.Last-minute changes or unexpected varia-tions in borehole conditions place cementersat a disadvantage. Irregular holes andwashouts hinder mud removal and casingcentralization, and may preclude use of pre-ferred turbulent flow. Low standoffs result inlarge radial variations in annular fluid veloc-ity around casing with higher velocity on thewide side and lower velocity on the narrowside. This leads to inefficient annular dis-placement and potentially poor cementbonds or channels. For cement jobs, casingOD to hole diameter ratio is close to unity,so annular flow can be calculated using abasic slot model (next page, top).

Drilling fluid designs also influencecement job quality. For example, zonal iso-lation cannot be achieved unless mud andcuttings are removed from the annulus.Drilling fluids must be designed, maintainedand treated to provide optimum final holeconditions, and ultimately be conditionedbefore cementing for easy removal by spac-

ers and cement. Ideal muds for efficient dis-placement are nonthixotropic8 and havereduced gel strengths, plastic viscosities andyield points; low density to facilitateremoval by buoyant forces; minimal fluidloss to prevent thick filter cakes and differ-ential sticking; and are chemically compati-ble with cements. Perfect muds, however,cannot be achieved in practice, so effortsmust be made to get close to ideal charac-teristics during selection, maintenance andprecementing circulation.

Drilling fluid density and rheology mustbe kept low to meet mud-removal require-ments. Displacing fluid weights and viscosi-ties become higher with each successiveinterface, which can lead to unacceptablyhigh cement densities and viscosities, andpossible lost circulation if initial mudweight is too high. Just circulating and con-ditioning mud before cementing is notenough; effective solids and chemical con-trol of rheology are required throughoutdrilling operations. If drilling fluids are notproperly designed or deteriorate duringdrilling or logging, gelled mud that is diffi-cult to remove may be left in washouts oron the narrow side of the annulus.

Fluids compatibility also impacts annulardisplacement. Fluid mixtures should have

Oilfield Review

8. Thixotropic fluids are highly viscous when static, butbecome more fluid-like and less viscous when dis-turbed or moved by pumping.

■■Flow velocity profiles around a 60% standoff eccentric annulus. For cement jobs,outside casing to borehole diameter ratio is close to unity, and annular flow condi-tions can be evaluated and calculated assuming flow through a slot (inset). If annu-lar flow is uniform, the ratio of local to average velocity is equal to one. For thinNewtonian fluids like water in turbulent flow, velocity profiles are relatively flatwith lower-than-average flow in the narrow gap and above-average flow in thewide gap. Viscous non-Newtonian fluids like polymers in laminar flow move mostlyon the wide side and can be static in the narrow annulus gap. Higher pump ratesor increased standoff improve flow velocity on the narrow side of the annulus.

■■Cementing costs versus hole size. The cost of additional centralizers to achieve adequate standoff is often overlooked.As hole size increases from 6.5 to 8.0 in., combined centralizerand cement costs to fill from 8000 ft [2440 m] total depth (TD)up to 5000 ft [1520 m] using a 16.45 ppg slurry with moderatefluid-loss control almost triples from $7850 to $22,500.

0

1

2

3

0° 90° 180°

Loca

l to

aver

age

velo

city

rat

io

Position around annulus

Narrow side (ns) Wideside (ws)

-90°-180°Wideside (ws)

Basic Slot Model

Polymer profiles

Water profiles

1 bbl/min3 bbl/min6 bbl/min

Pump rates

Concentric slot

Eccentric slot

nsws ws

0° 180°-180°

0

5

10

15

20

25

6.5 7.0 7.5 8.0

Cos

t, $1

000

Total

Cement

Centralizers

Hole size, in.

lower rheologies than the individual fluids,but because this is difficult to achieve formuds and spacers, designs need to mini-mize mixture viscosities. Problems also ariseif cement and mud mix inside or outsidecasing. Some drilling fluid additives acceler-ate or retard cement thickening times. Butmore commonly, cement-mud combina-tions result in high-viscosity mixtures andcorresponding friction pressure increasesthat lead to excessive surface pump pres-sures and premature job termination as wellas inefficient displacement. Washes andspacers isolate these potentially incompati-ble fluids, but unexpected variations incomposition leave cementers unprepared tomaintain this separation. This can beavoided by using bottom wiper plugs to sep-arate fluids inside casing and liners.

In addition to displacement considera-tions, cementing cost is an issue as holesizes increase from washout or enlargement.The cost of larger cement volumes is obvi-ous, but additional centralizer cost toachieve adequate standoff for effective mudremoval is often overlooked (right).

Spacer cost is also important. As hole sizeincreases, higher flow rates are needed forturbulent flow and spacer volumes must beincreased. For example, if hole diameterincreases from 6.5 to 8.0 in., the rate toachieve turbulent flow goes from 4 to 14bbl/min and cost of standard spacers goesfrom about $6500 to $15,500.

Workovers are another often overlookedcost component when drilling and cement-ing services are segregated. Typically, if aprimary cement job is unsuccessful and acement squeeze is necessary, more than oneattempt is needed to achieve zonal isola-tion. Remedial cementing costs, includingcement, perforating, packers and rig time,can be as much as, or more than, the pri-mary cement job.

Integrating Fluids Services in CanadaA managed fluids approach proved success-ful in western Alberta, Canada, where verti-cal wells are drilled to between 6888 and7544 ft [2100 and 2300 m] through uncon-solidated formations. Historically, drillingand cementing fluids had been provided byone company, but individual services werenot working to meet common goals. Drillingfluids services tried to minimize expendi-tures directly related to mud use, andcementers did the best job possible withresulting hole conditions. Managed sepa-rately, drilling fluids cost on four wells

Summer 1996

drilled with bentonite mud and three withpartially hydrolized polyacrylamide (PHPA)fluids was $26,600/well, or $3.58/ft[$11.75/m] drilled. Average hole enlarge-ment was 113% by volume and typically 23days were spent drilling. Lost time due tohole problems and backreaming was about24 hr/well.

Some elements of drilling fluids perfor-mance were acceptable, but hole geometriesthat cementers had to address were not.Bentonite mud was not conducive to drillinggauge holes and a PHPA fluid failed to pre-vent washouts that were responsible formajor cementing cost over-runs. Enlarged

holes were compensated for by pumpingextra cement, knowing that there was risk ofchanneling due to reduced fluid velocities inwashouts. Cementing on these seven wellscost $103,750/well or $13.96/ft [$46/m]drilled, about four times drilling fluid costs.Total fluids averaged over $130,000/well, or$17.56/ft [$57.60/m] of hole.

45

Reasonable turbulent flow pump rates

Excellent ability to suspendweighing agents

MUDPUSH Spacer Properties

Adjustable viscosity and densityfor laminar flow

Cement, oil- and water-base mudcompatibility

Good fluid-loss control

Applicable for a wide range of fluidweights and salinities

Engineered, Fit-to-Purpose Spacers

46 Oilfield Review

1. Courturier et al, reference 6, main text.Tehrani et al, reference 6, main text.

Overall improvement was the goal of aunified fluids approach on two subsequentwells. Total fluids costs were targeted to bereduced by improving hole gauge andreducing cement volumes. Unconsolidatedformations in these wells were identified asthe cause of washouts, so because of thelack of success with even a moderatelyinhibitive PHPA system, mixed-metal-hydroxide (MMH) mud with unique fluidrheology was chosen to minimize holeenlargement.

After the revised fluids program wasimplemented, gauge holes allowed for bet-ter casing centralization and improved dis-placement designs—a laminar flow regimewas chosen for these wellbore geometries.Spacers effectively removed MMH fluidsfrom the annulus and logs indicated goodcement placement and successful zonal iso-lation. Cement returns compared to cementvolume pumped in excess of caliper holevolume indicated minimal if any channelingin both the wells drilled with MMH fluid.But severe channeling was likely in three ofthe previous seven offset wells, and one hadsignificant losses during cement placement.

Water flow—the first in this field—occurred while drilling the initial test well.Although most of the 57% washout wasover the interval where flow occurred onthis well, this still compares well with over100% average washout on offsets. Drillingfluid cost exceeded average offset costbecause dilution, borehole instability andthe need to increase density resulted inexcess product use that skewed cost. Posi-tive results, however, were seen in improvedhole gauge and cement cost, which fell to64% of the average.

The second test well had no losses or flowand was drilled in the least number of days,despite moderate rates of penetration. Lostdrilling time on this well was the lowest forthis field and washouts were reduced to29%. Drilling fluid cost at $43,000 wasabove the $25,000/well average, butcementing costs of $45,000 were less thanhalf those of previous wells.

Total fluids cost was the lowest on recordfor this field—a 32% savings over the aver-age for offsets. The objective of reducingoverall well construction fluid costs wasachieved by reducing washouts, and higherdrilling fluid costs to minimize hole enlarge-ment were more than offset by cement sav-ings. Proper drilling practices cannot assurecementing success, but poor drilling prac-tices may make cementing successunachievable.

The primary functions of spacers are fluid separa-

tion to avoid compatibility problems and ensuring

flow under a specific regime—turbulent or lami-

nar—while maintaining hydrostatic well control.

Improved mud removal guidelines require pre-

flushes for either turbulent flow or effective laminar

flow (ELF) techniques, so weighted MUDPUSH

spacers were developed for use with WELLCLEAN

optimal mud removal services (right). XT and XS

spacers are for turbulent flow. Viscous XL is used

with ELF. All three can be adapted for use with oil-

base muds—XTO, XSO and XLO spacers.

Turbulent spacers were designed to overcome

settling problems experienced with thin spacers.

Weighting agents are suspended at surface or bot-

tomhole temperatures under static and shear con-

ditions by a properly designed base-fluid rheology

that eliminates free water and particle settling over

a wide range of densities while allowing turbulent

flow at reasonable pump rates. The XT spacer is for

turbulent flow regimes in low-salinity environments

(fresh or less than 10% salt by weight of mix water)

and the XS spacer is for high-salinity applications

(30% salt by weight of mix water). Both can be for-

mulated at 10 to 19 lbm/gal [1.2 to 2.3 specific

gravity (SG)] densities.

Laminar-flow spacers have higher viscosities

than turbulent-flow spacers, so good particle-carry-

ing capacity ensures that weighting agents to

achieve required densities do not settle out. To

meet ELF friction-pressure hierarchy criterion,

spacer rheology can be adjusted so that apparent

viscosity across the range of pumping shear rates

falls between drilling mud and cement slurry

apparent viscosities. Spacer density can also be

designed halfway between mud and cement slurry

weights at any density from 10 to 20 lbm/gal

[1.2 to 2.3 SG].

In addition to proper spacer rheology and parti-

cle-carrying capacity, fluid-loss control and com-

patibility are important. Fluid-loss control must be

considered because water lost during displacement

increases the spacer solids-to-liquid ratio, density,

and to a greater extent, apparent viscosity. Exces-

sive fluid loss introduces the possibility of spacers

coming out of turbulent flow at design rates, which

can lead to channeling of spacer through the mud.

Fluid loss for these spacers is low and few compat-

ibility problems have been encountered. Some

mixtures of these spacers and cement slurries

develop weak gel strengths when left static at low

temperature, but these gels are broken by shear

rate or small temperature increases.

Consistent performance under field conditions is

also an advantage in effective mud removal. Spac-

ers must perform under variable conditions from

low-quality barite and brackish or high-salinity

water to low-shear mixing without major changes

in properties and effectiveness. Spacers should

also have adequate viscosity and fluid-loss control

at field conditions. MUDPUSH spacers perform

successfully under a wide range of operational con-

ditions, and rheological properties are consistent

with laboratory measurements made prior to jobs.

These spacers are limited to maximum bottom-

hole circulating temperatures of 300°F [149°C], but

the new XEO spacer, a polymer-modified, oil-in-

water emulsion spacer, extends applicability to

450°F [232°C] for oil-base mud removal only. The

WHT spacer is a water-base spacer developed for

these same higher temperature applications and

oil- or water-base mud removal to complement the

XEO spacer. However, it exhibits less fluid-loss

control, especially when seawater is used as mix

water. MUDPUSH spacers can also be used for

other cementing applications where weighted spac-

ers are needed, such as plug or squeeze cement-

ing, even when WELLCLEAN services are not

directly applicable.

47Summer 1996

18

16

14

12

10

8

6

4

2

00 10 20 30 40 50 60 70 80 90 100

API standoff, %

Flow

-rat

e ra

tio

R

rD d

w

STO, % = or x 100R-rw

D-d2w

Adjust rheology if necessary

Adjuststandoffor flow rate

Eccentered Flow Screen

Evaluate flow regimes and range offlow rates versus hole size; selectflow regime and standoff.

Centralizer Calculation

Select centralizers appropriate forhole dimensions and desired standoff.

Pump Rate Selection

Select pump rate that meets criteriafor the chosen flow regime, holesize and standoff.

U-Tube Calculation

Evaluate U-tubing that occurswhile pumping at the selected rate.

Evaluate Mud Removal Criteria

Determine if mud removal criteriaare met across all zones of interest.

■■Turbulent flow-ratecorrections versuscasing eccentricity.The critical flow rateto achieve turbulentflow completelyaround a casing-borehole annulusdoubles as casingstandoff (STO)decreases from 100to 70% and there isalmost a tenfoldincrease if standoffdrops to 30%.

■■Optimizing mudremoval. In the early1990s, pipe eccen-tricity was first takeninto consideration indesigns and in thefield by using WELL-CLEAN optimal mudremoval service inCemCADE cement-ing design and evaluation software. This comprehensivesoftware is used toevaluate all wellparameters, includ-ing casing standoff, and to recommendflow regimes, preflushes and volumes, and pump-rate sequences for optimum fluid displacement.

■■Cementing versus drilling geometries: the importance of standoff. At lower stand-offs, the decrease in frictional pressuredrop in a cementing geometry—large cas-ing in open hole—is significantly greaterthan in a drilling geometry— smaller drillpipe in open hole. Standoff, therefore, hasa double effect on annular displacement ina cementing geometry. Both wall shearstress and pressure drop are lower for poorstandoffs in an eccentric annulus, whichfurther compounds mud removal andcementing problems. In the past, mostcementing designs used drilling simulatorsthat assumed a concentric annulus.

2000

1500

1000

500

0 20 40 60 80 100

Pipe standoff (STO), %

Fric

tiona

l pre

ssur

e dr

op, P

a/m

0

Cementing geometry:0.81 diameter ratio

Drilling geometry:0.55 diameter ratio

9. Howard GC and Clark JB: “Factors to be Consideredin Obtaining Proper Cementing of Casing,” in Drillingand Production Practices. Dallas, Texas, USA: Ameri-can Petroleum Institute (1948): 257-272.Haut RC and Crook RJ: “An Integrated Approach forSuccessful Primary Cementations,” paper SPE 8253,presented at the 54th SPE Annual Technical Confer-ence and Exhibition, Las Vegas, Nevada, USA,September 23-25, 1979.

Circulation: Mud ConditioningPrimary cementing operations often havemultiple objectives. On long intermediatecasing strings, a complete cement sheathfrom bottom to top is preferred, but a goodseal near the bottom of the string andaround the casing seat is all that may berequired, making the casing seat the primaryand the full cement sheath the secondaryobjectives. For liners, isolation away fromthe shoe (bottom) may be important as wellas a seal at the liner-casing overlap (top).Cementing goals dictate job designs. Tosolve cementing problems, better under-standing and application of fluid flow, dis-placements and placement are requiredalong with careful design of mud systems,spacer fluids and cement slurries. Cementplacement is important in most cases; mudremoval is critical on all cementing jobs.

The accepted procedure is to circulate andcondition before cement jobs.9 However, inthe past, there were few guidelines for theseprocedures, except generally to reduce mudviscosity, gel strength and fluid loss; maxi-mize standoff—casing centralization; usepreflushes—chemical washes and spacers toseparate mud and cement; move thepipe—rotate or reciprocate; circulate a min-imum of two hole volumes and pump at

high rates. Also, until a few years ago, criti-cal flow-rate calculations assumed that cas-ing was perfectly centered in the hole. How-ever, the critical flow rate correction toaccount for casing eccentricity is significantand must be taken into consideration (top).In the early 1990s, eccentricity was firsttaken into consideration in designs and inthe field by using WELLCLEAN optimal mudremoval service in the CemCADE software(above).

Gelled mud must be removed from theannulus before placing cement, but mud inthe narrow side of an eccentric annulus isoften difficult to move. Casing standoff fromborehole walls is less than 100% even invertical wells, and frequently no higher than85%. At low flow rates, drilling mud withhigh yield stress and gel strength can bestatic in the narrow gap of an eccentric

annulus because of distorted velocities,lower frictional pressure drops and unevenwall shear stress distribution (left ). This isundesirable because stationary mud may gelor dehydrate by static filtration at permeablezones and be difficult to mobilize duringmud removal and cement placement.

Conditions leading to zero flow in narrowannular gaps need to be defined by account-

48 Oilfield Review

■■Annular flow regimes. Fluids calculated to be in turbulent flow, assuming perfectly cen-tered casing, are now known to be turbulent only in part of the annulus. In fact, threeflow regimes—no flow, laminar and turbulent—can coexist in an annulus, which meansthat mud may be removed effectively on the wide side, while on the narrow side mud isstatic, resulting in a channel. Between the extremes of no flow on the annulus narrowside and full turbulent flow around the annulus, mud removal may be poor, unless lami-nar flow displacements are properly designed.

Increasing flow rate

Decreasing standoff

Turbulent flow

A B

Flow Regimes

Laminar flow

No flow A B

Dis

tanc

e fro

m s

hoe,

m

0

1

2

3

4

5

6

10

7

8

9

MudCement Spacer

ExperimentTheory

Effi

cien

cy, %

100

75

50

25

00 1 2 3 4 5 6 7

Hole volumes pumped

STO = 75%Displacement Efficiency

STO = 50%

STORate

40%8 bbl/min

60%2 bbl/min

60%5 bbl/min

wsnsws wsnsws wsnsws wsnsws wsnsws

40%2 bbl/min

50%8 bbl/min

■■Mud, spacer and cement distribution forvarious displacement rates, standoffs andspacer properties. In the base case (far left),mud and spacer channels were left alongthe length of a simulated annulus in thisfull-scale flow loop. As displacement ratewas increased, mud was displaced fromthe annulus narrow side, but full cementplacement did not occur because interfa-cial velocity was low. Increasing standoff(STO) had a dramatic effect on mud dis-placement and cement placement (middleand bottom), but further rate increaseunder these conditions did not significantlyimprove cement placement. Rate is, there-fore, important in mud displacement, butless influential in cement placement. Bet-ter standoff, higher rate and a thin spacerfor more effective turbulent flow also had apositive impact on cement placement,highlighting the importance of proper fluidrheology designs, especially for spacers(far right). (From Lockyear and Hibbert, refer-ence 2 and Tehrani et al, reference 6.)

ing for casing eccentricity. In the absence ofpipe movement, frictional pressure drop anddensity differences are the only forces actingto move mud. Mud yield strength must beless than the wall shear stress generated byfrictional pressure drop from viscous forcesfor mud to flow in narrow gaps. Wall shearstress can be increased by higher flow rates,improved standoff and increasing density dif-ferences, or mud gel strength can bereduced before casing is run.

Another consequence of uneven velocityprofiles is coexistence of different flowregimes. In an eccentric annulus, mixedflow regimes are possible if critical flow ratefor turbulence is calculated, as in the past,based on a concentric annulus, a commonassumption in drilling hydraulics models.For fluids exhibiting yield stress and gelstrength like muds and cements, it is possi-ble for three annular flow regimes to coex-ist—no flow if wall stress is less than fluidyield strength on the narrow side of theannulus, turbulent on the wide side andlaminar in between (right).

49Summer 1996

CemCADE Design and Evaluation

Not met

Prepare customerreports, printouts

and plots

View “EfficientTime” or “Efficient

Volume” Plots

Enter pumpingschedule andrun simulation

Acceptable rate

Select pumpingrate using

“design rateselection”

Rate notacceptable

If standoff OK

Designcentralizersbased on

eccenteredflow analysis

Centralizer data fromdata base or userenters vendorcentralizer information

If standoffnot OKIf OK

Pressure margins

If notOK

Foamed cementplacementPPA-gas migration

Enter allsequences

Enter fluids

Enter well data Administration, well, casing,caliper, survey and formationFluid editor: rheologies,

slurry design, APIdata, spacer design,wash design, chemicalsand materials

Evaluate displacementcriteria using “EccenteredFlow” screen: Turbulent orEffective Laminar Flow (ELF)versus hole size, standoffand rheology

Mud removal criteria met

3D survey (if significant),Efficient Time/Volume,well security andcontrol, andsurface pressure plots

■■Computer-assisted cement job designs. CemCADE software can be used to make mudcirculation, annular displacement and cement placement recommendations based onactual well geometry, casing standoff and fluid rheologies.

10. Bittleston S and Guillot D: “Mud Removal: ResearchImproves Traditional Cementing Guidelines,” Oilfield Review 3, no.2 (April 1991): 44-54.

11. Brice JW and Holmes BC: “Engineered CasingCementing Programs Using Turbulent Flow Tech-niques,” Journal of Petroleum Technology 16 (May 1973): 503-508.Clark CR and Carter LG: “Mud Displacement WithCement Slurries,” Journal of Petroleum Technology25 (July 1973): 775-783.

The Annulus: Removing Mud, Placing CementA better understanding of annular displace-ment emerged in the late 1980s and early1990s.10 Previously, casing eccentricity, orstandoff, was not considered in designs,even though it was known to be a factor inchanneling and primary cementing failures.Competent cement sheaths and a good sealdepend on effective mud removal by turbu-lent or, under certain conditions, laminarflow. But fluids calculated to be in turbulentflow assuming perfectly centered pipe mightactually bypass mud in an eccentric annulusbecause fluid velocities vary radially aroundeccentric casing. Now CemCADE cement-ing design and evaluation software can beused to make mud circulation, annular dis-placement and cementing recommenda-tions based on actual well geometry, casingstandoff and fluid rheologies (right).

Even if mud gel strength is broken duringcirculation and conditioning, the questionof whether cement will flow into the narrowannulus gap needs to be answered. Ifcement flows primarily on the annulus wideside and leaves a slow-moving mud orspacer channel in the narrow side, goodcement placement and zonal isolation willnot be achieved. Cementing, therefore, canbe considered in two parts: mud removaland cement placement—uniform cementflow without channeling—which bothdepend on proper displacements up theannulus and down casing. Increasing stand-off improves mud displacement and cementplacement; displacement rate is importantfor effective turbulent mud removal (previ-ous page, bottom).

Displacing mud with spacers in turbulentflow is one of the most effective and widelyaccepted cementing techniques. Turbulent-flow mud removal dates back to the 1940s.It was subsequently recognized that turbu-lent scavenger displacing fluids—pre-flushes—placed in contact with formationsfor about 10 minutes improved mudremoval.11 Increasing displacement rateimproves turbulent mud removal. And thin,less viscous spacers like water and surfac-tants that can easily be placed in turbulentflow at low pump rates work best, probablybecause of combined drag, erosion and

50 Oilfield Review

Position around a 50° STO annulus0° 90° 180°Narrowside

Wideside

Loca

l to

aver

age

velo

city

ratio

0

1.0

2.0

0.5

1.5

2.5Velocity Profile

3-lbm/bbl xanthan polymer2-lbm/bbl xanthan polymer0.6-lbm/bbl xanthan polymerWater

Displacing fluids:

■■Various viscosity fluids displacing a 3-lbm/bbl xanthanpolymer. Thin fluids like water displace thicker, more viscousfluids because of increasing turbulence.(From Lockyear, Ryanet al, reference 6.)

Turbulent FlowDisplacement Criteria

Preflushes in turbulence allaround the pipe

+

+

Preflushes in contact withzones of interest for 10 min

Similar displacing and displacedfluid densities

Effective Laminar Flow(ELF) Displacement Criteria

Minimum pressure gradient (MPG)

Positive density hierarchy

Positive frictional pressure hierarchy

Minimum differential velocityat interfaces

+

+

+

■■Recommendations for ELF displacements.These conditions should be applied to bothmud-spacer and spacer-cement interfacesthroughout the zone of interest. The differen-tial velocity criterion is optional because it is difficult to achieve, but should be appliedwhenever possible to get good displace-ment up to the designed top of cement.

dilution at interfaces due to turbulent eddies(below left ). Chemical washes shouldalways be used, but weighted spacersdesigned for turbulent flow—low rheologiesand temperature stability—can be usedunder some conditions if required. The max-imum wash or spacer volume without com-promising well control should be recom-mended or the 10-minute annular contacttime should be used. Even moderate chemi-cal wash volumes used with spacers reducemud viscosity and are preferable to spacersalone.

Pump rates to achieve turbulence on theannulus narrow side depend on hole dimen-sions and casing standoff. However, achiev-ing turbulence around the entire annulus,even on the narrow side, requires highpump rates in large casing that may not bepractical because of surface equipment lim-its or fracture gradients. Achieving mudremoval by turbulent flow becomes harderas hole sizes get larger and standoffdecreases, and is even more difficult whenweighted spacers are used. Turbulent flowcriteria for annular mud removal require tur-bulence around the entire annulus, includ-ing the narrow side, thin preflushes in con-tact with formations for 10 minutes, andsimilar displacing and displaced fluid densi-ties (above).

When turbulent flow is not an option, thereis a need for properly designed mud dis-placements with spacers and cement in lam-inar flow. These designs are more compli-cated, but criteria have been established toensure displacement efficiency (below right).Effective laminar flow requires positive den-sity contrasts—10% is recommended when-ever possible—a minimum pressure gradient(MPG) to overcome mud yield stress andpositive rheological hierarchies to maintainincreasing friction pressure and minimizedifferential velocity between fluids. Positivedensity differential, which is independent ofhole geometry, helps generate a flatter, morestable interface and is the first condition tocheck. In cases where cement slurry density

is close to mud density and mud weight can-not be modified, spacer density range is lim-ited and it may not be possible to meet thiscriterion.

Yield stress of fluids being displaced mustbe exceeded by wall shear stress. Minimumpressure gradient defines the force neededto move drilling fluids in the annulus narrowgap and should also be applied prior tocementing during mud circulation to ensurethat all the mud is moving and recondi-tioned. Below this force some mud remainsimmobile on the narrow side of the annulus.When mud is displaced by heavier fluids inlaminar flow, a density differential helpsmeet this condition by contributing to wallshear stress (next page, top left ). MPG veri-fies fluid mobility and defines a lower flow-rate limit to ensure that flow occurs allaround the annulus.

The differential between frictional pres-sures generated by fluids should be at least20% to increase interfacial stability. Other-wise the displacing fluid tends to bypassfluid ahead. Under laminar flow, spacerswith higher rheologies—thicker or moreviscous than the mud—are most effective(next page, top right). This is equivalent tohaving apparent mud viscosity lower thanthat of the displacing fluid for a given flowrate and annular geometry. The frictional

ExperimentTheory

Effi

cien

cy, %

100

75

50

25

00 1 2 3 4 5 6 7

Annular volumes pumped

∆ρ = 16%Displacement Efficiency

∆ρ = 2%

1.61.291.161.0

Position around a 60% STO annulus

Loca

l to

aver

age

velo

city

rat

io

00° 90° 180°

Velocity Profile

Narrowside

Wideside

1.0

0.5

1.5

2.0

2.5 Displacing fluid specific gravity (SG):

ExperimentTheory

Position around a 50° STO annulus

Loca

l to

aver

age

velo

city

rat

io0

1

2

0° 90° 180°

Velocity Profile

Narrowside

Wideside

Displacing fluid:3-lbm/bbl xanthan polymer

3-lbm/bbl xanthan polymer2-lbm/bbl xanthan polymer0.6-lbm/bbl xanthan polymerWater

Displaced fluids:

Case 1

Case 2

Effi

cien

cy, %

100

75

50

25

00 1 2 3 4 5 6 7

Annular volumes pumped

Displacement Efficiency

■■How differential velocity affects laminardisplacements. Friction pressure developsfaster on the annulus narrow side becauseof the smaller flow area (effective slot size),so the two friction pressure curves cross,since displaced and displacing frictionpressures increase at different rates. Tomaintain a stable interface between fluids,velocity must remain below the criticalvalue (Vc) represented by the intersectionof the two curves. And displacing fluidvelocity must be less than displaced fluidvelocity.

V2 V1 VcVelocity

Pre

ssur

e dr

op

Displaced mudor spacer (1)

Displacing spaceror cement (2)

<

■■How density (ρ) affects laminar flow displacements. Positive density hierarchies—increasing the density of eachsuccessive displacing fluid—greatly improve mud removaland minimize channeling because of buoyancy effects. Thegreater the differential density, the better the displacementefficiency (top left). Like the classic example of communicat-ing vessels from basic physics where liquids come to thesame level regardless of container size or shape, denser displacing fluids try to equalize in an eccentered annulus (top right). Increasing displacing fluid density greatlyimproves the interfacial velocity profile and displacementefficiency as shown by various specific gravity (SG) fluids dis-placing a 1.0 SG fluid (bottom). (From Lockyear, Ryan et al, ref-erence 2 and Tehrani et al, reference 6.)

■■How viscosity affects laminar displacements. A positive rheological hierarchy between displacing and displaced fluids at a low flow rate (Case 2 top) results in more efficient displacement than displacing and displaced fluids of similar rheologies at a high flow rate (Case 1 top) Thick fluids displacethin fluid more uniformly than the reverse. Interfacial velocityon the annulus narrow side improves as displacing fluid plas-tic viscosity and yield point increase—higher rheologies—because of the large frictional pressure drops generated bymore viscous fluids (bottom). (From Lockyear, Ryan et al, refer-ence 2 and Tehrani et al, reference 6.)

pressure criterion is important and an ini-tial check should be always be made. Ifthere is not at least a 40% friction pressuredifferential between mud and cement, bothspacer and cement cannot meet this condi-tion and rheological properties must bechanged by reducing mud yield point, den-sity and solids contents to a minimum dur-ing mud conditioning prior to cementing orby increasing spacer and cement rheology(plastic viscosity and yield point). Improv-ing casing standoff and increasing densitydifferentials also helps satisfy this criterion.Friction pressure hierarchy and MPG estab-lish minimum flow rates.

Differential velocity around the annulus atfluid interfaces must be minimized to estab-lish a relatively flat interface. The combina-tion of density and frictional pressure differ-entials helps generate a relatively flat and

Summer 1996

stable interface and reduce the possibility ofone fluid fingering or channeling throughanother. The sum of gravitational and fric-tion forces for displacing fluids in the wideside must be greater than those of the fluidbeing displaced on the narrow side of theannulus to balance forces so flow is uniformaround the annulus. This condition can besatisfied if annular flow rate is below a criti-cal value (right).

Annular velocity differential can be mini-mized by reducing mud yield point duringconditioning, maximizing standoff, meetingdensity and friction pressure heirarchy con-ditions by using viscous weighted spacers,displacing at low pump rates and movingthe pipe. When displacement rates are toohigh, displacing fluids tend to flow faster inthe wide side of the annulus, regardless ofgravitational effects that tend to flatten theinterface. Therefore, differential velocity cri-

51

Spacer

Mud MudInterfacialboundary

■■Velocity profiles for displacement inside pipe. Overall flow direction was defined to bedownward, but allowed to be locally positive (down) or negative (up). Arrows representvelocity relative to radial position at an axial location. To compute interfacial boundaryshape, computations are made along the entire length of the pipe. A software calledMathematica (version 2.2.3, Wolfram Research) derived displacement calculation rou-tines for displacement efficiency versus time and interfacial boundary position at varioustimes during displacement, using fluid density, yield stress, plastic viscosity, pipe lengthand diameter, and pump rate.

Retarded (delayed) cement set time

Poor zonal isolation

Unset cement at liner tops

Lack of hard cement in “shoe tracks”

High displacement pressures fromviscous incompatible fluids mixtures

Problems associated withincomplete casing displacement

teria establish maximum annular flow ratesand contradict “pump-as-fast-as-you-can”philosophies.

Unlike turbulent displacements in whichannular flow is maintained above a criticalrate, displacements by ELF must be main-tained between maximum and minimumrates. In turbulent flow, preflush volume isdetermined from the 10-minute contact timeat a critical rate. For ELF displacements,spacer volumes should be at least 500 ft[150 m] of annular fill, with a 60 bbl [10 m3]minimum. Increased wellbore inclinationreduces displacement efficiency by decreas-ing gravitational effects, but this reductioncan be compensated for by optimizing pumprates and fluid rheologies. Complicated lami-nar displacements highlight how properlydesigned spacers are essential in annularmud removal.

Down Casing: Displacing CementMuch effort goes into selecting proper flu-ids, flow regimes and displacementmechanics to remove mud from the annulusand place cement. This usually meanspumping fluid stages with increasing densi-ties. For downward flow inside pipe, how-ever, a positive density hierarchy is counterto effective displacement. Mixing and con-tamination occur when interfaces betweenfluids are unstable or displacing fluidsbypass—fall through—fluids ahead, prob-lems that can be overcome by using wiperplugs for mechanical separation. Sometimesonly one bottom wiper plug is run, but moreoften, none is used.

After investigation of primary cementingfailures in which fluid mixing inside casingwas a possible cause, P. Valkó performed anin-depth study of frictional and gravitationalforces on fluids flowing downward inpipe.12 The mechanics of heavier fluids dis-placing lighter fluids down casing whenwiper plugs are not used were defined, andmethods were developed to calculate dis-placement efficiency and interfacial bound-ary shapes. This project was based on ear-lier work involving upward flow in annuli

52

and packed, fluid-filled columns (above).13

The software to make these calculationsuses fluid densities and rheologies alongwith gravitational effects, assuming vertical,laminar flow and no mixing.14 This softwareis only qualitative and not a simulation, andcannot determine when bottom wiper plugsshould not be run.

Subsequent work with this software showsthat there may be three forms of displace-ment inside pipe (next page, top). Fluidinterfacial boundaries may form smoothparabolas with moderate displacement effi-ciency or there may be an outer cylinder ofthe first fluid that is not moving, so effi-ciency is lower. It is also possible to have aregion where the first fluid tends to moveupward, in opposition to primary flow, sodisplacement efficiency is quite low. Incementing applications it is not possible forfluids in the casing to flow up because ofthe cementing head, but this force can leadto a high degree of mixing at fluid inter-faces. As expected, displacement is never

completely effective, demonstrating theneed for mechanical separation—bottomwiper plugs.

Incomplete fluid displacement inside cas-ing is likely to mean an unsuccessfulcement job (left). The tendency for upwardflow at interfaces can cause spacer orcement leading edges to be contaminated orcomplete mixing of mud, spacer andcement, leading to inefficient mud removal.Extreme viscosity increases and correspond-ing high pump pressures can also result ifslurries and muds are incompatible. Fluidmixing can have disastrous results, includ-ing appearance of premature set if incom-patibility is severe enough. It is also possiblefor displacing fluids to bypass fluids thatwere pumped ahead. This is often evidenton pressure charts in the form of early liftpressure and from returns at the surface asheavier fluids bypass lighter fluids and “turnthe corner”—U-tube—from the casing intothe annulus sooner than expected.

Cement contamination by spacer or mudcan change slurry rheology or retard thick-ening time, as evidenced by friction pres-sure increases during displacement orapparent lack of set cement on evaluationlogs. In some cases, mixing may be only atthe slurry leading edge and result in lowerthan expected cement tops or low-strengthcement up hole. It is also possible for tail

Oilfield Review

12. Valkó P: Fluid Displacement in Pipe. College Station, Texas, USA: Texas A&M University, October 30, 1994.

13. Flumerfelt RW: “Laminar Displacement of Non-Newtonian Fluids in Parallel Plate and Narrow GapAnnular Geometries,” SPE Journal 15 (April 1975): 169-180.Beirute RM and Flumerfelt RW: “Mechanics of theDisplacement Process of Drilling Muds by CementSlurries Using an Accurate Rheological Model,”paper SPE 6801, presented at the 52nd SPE AnnualTechnical Conference and Exhibition, Denver, Col-orado, USA, October 9-12, 1977.

Increasing casing size or density difference between fluids

0

60

80100

20

40

0 1 2 3 4 5 6

Dis

plac

emen

tef

ficie

ncy,

%

Normalized time, t

0

60

80100

20

40

0 1 2 3 4 5 6

Dis

plac

emen

tef

ficie

ncy,

%

Normalized time, t Normalized time, t

00 1 2 3 4 5 6

Dis

plac

emen

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80100

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t=1 t=1 t=1

■■Displacement efficiencies (top) and fluid interfacialboundary shapeswhen the leading edgereaches the end ofpipe (bottom). Depend-ing on fluid properties,pipe (wireframe) diameter and flowvelocity, the interfacebetween fluid stagesmay be stable andapproach the shape ofa parabola (left). Theremay be a region inwhich the lighter bot-tom fluid is static andthe heavier top fluid isflowing down throughthe middle of the pipein an internalparabola (middle).Or there may be aregion where thelighter fluid is flowingupward, counter to theprimary downwardflow direction (right).

14. Wolfram S: Mathematica‚ A System for Doing Mathematics by Computer, 2nd ed. Reading, Mas-sachusetts, USA: Addison-Wesley Publishing Com-pany, 1993.

slurries to fall through lead slurries; in thiscase, cement evaluation logs may showgood cement bond across most of the inter-val, but poor cement at the bottom, wheregood, strong tail cement should be. Theremay also be spotty occurrences of good andbad cement. In some cases, no evidence ofcement may be found even after severaldays because of complete mixing and retar-dation of cement by spacer.

Two common problems are failure ofcement to provide a seal at the shoe andlack of hardened cement in shoe tracks(float joints) during drill out. Shoe failuremay be related more to formation character-istics where casing is set than to cement jobquality, but there are cases when slurriesbypass spacers and the cement seal is actu-ally being tested.

Displacement efficiency also affectscement quality in shoe joints. If bottomplugs are not run and cement bypassesspacer or mud, the top wiper plug can pushbypassed spacer and mud into the shoejoint. Since wiper plugs stop at float collars,there may also be low-quality cement ormixed fluids between the float collar andfloat shoe. Even when bottom plugs are run,cement may bypass other fluids in the shoetrack. Also, float collar outlet orifices estab-lish a thin fluid jet through casing or liner

Summer 1996

joints below float collars, compounding adifficult situation.

Sensitivity analyses using this new soft-ware indicate that effective displacementinside casing cannot be achieved by modi-fying fluids without adversely affectingannular displacements. Properties that mightinfluence interface shape and displacementefficiency include average velocity, yieldpoint, density, plastic viscosity and pipesize. Displacement efficiency improves asflow velocity and yield point differencebetween bottom and top fluids increase.Efficiency decreases as fluid-density differ-ences increase; even at similar densities,displacement is only 70% after a pipe vol-ume of fluid is pumped. Differences in plas-tic viscosity have little effect on displace-ments in the range of geometries and shearrates studied. As pipe sizes increase, dis-

Hill S: “Channelling in Packed Columns,” ChemicalEngineering Science 1, no. 6 (1952): 247-253.Flumerfelt RW: in B Elvers, ed: Ullman’s Encyclope-dia of Industrial Chemistry, vol. B1. Cambridge, Eng-land: VCH Publishing (1990): 4-35.

placements become more inefficient, and inlarger pipe sizes, reverse flow of lighter flu-ids causes unstable conditions.

Although there are often acceptable resultswhen bottom plugs are not used, theory andfield data indicate that mechanical separa-tion at each interface is the only way toensure that competent fluids leave the cas-ing and enter the annulus. This work sug-gests that bottom plugs should be usedwhenever possible and that many undesir-able results can be explained by the phe-nomenon of heavier fluids “falling through”or mixing with fluids being displaced aheadin the casing. Running bottom wiper plugsis strongly recommended and, in criticalcases, bottom plugs should be run at eachinterface (see “Using Multiple Wiper Plugs,”next page).

53

Clamp

2-in.inlet

Casingadapter

Casingcollar

Wiperplugs

Plugbasket

Casing

Hydraulic launcher

Wiperplugfins

Using Multiple Wiper Plugs

Use of the EXPRES Extrusion Plug Release

System, a next generation cementing head,

continues to expand. This innovative design

automates release procedures and gives a

positive indication of plug launch. Plugs are held

in a basket below the head and inside casing so

that cementing fluids—chemical washes,

spacers and cement slurries—can flow around

the basket (right). Over 2000 lb of force from a

hydraulic ram launches the plugs, minimizing

chance of premature or accidental release.

Mechanical stops in the launcher provide an end

to each phase of the job. An oil-level gauge

indicates launcher-rod position and gives a clear

indication of plug departure. Top plug departure

is verified by sensors mounted on the casing that

detect drillable magnets in the plug, sounding a

horn and sending a signal to the cementing unit.

Modular design, quick-latch connectors and

remote operating capability save rig-up and job

execution time. This means better mud

conditioning prior to cementing and the unique

ability to launch plugs on the fly—without

interrupting pumping—which reduces U-tube

effects and improves mud removal. High

pressure ratings allow pressure-integrity testing

immediately after cementing, saving rig time and

reducing possibility of forming a microannulus.

An exclusive wiper plug fin design ensures

complete fluid separation and effectively wipes

casing walls, so cement slurry reaches the float

collar without being contaminated. Exposure to

high pressure is minimized by remote control and

light, well-balanced modules make the EXPRES

system easy and safe to handle.

The concept, developed several years ago, of

preloading plugs in a basket has been expanded

■■EXPRES cementing head. The automated ExtrusionPlug Release System improves mud circulation andconditioning, and cement job quality in addition toreducing high-pressure hazards. Plugs are held in abasket below the head and inside casing that cement-ing fluids can flow around. Over 2000 lb of force froma hydraulic ram launches plugs, minimizing chance ofpremature or accidental release. A safety latch pre-vents top plug release until the hydraulic ram beginsits final stroke.

54

from two plugs to three plugs and to subsea

cementing using a Surface Dart Launcher (SDL)

and Subsea Tool (SST) (next page). The first

DeepSea EXPRES prototype was used off the west

coast of Africa in mid-1994 and two other

prototypes were placed in service in the Gulf of

Mexico earlier this year. Over 28 jobs have been

performed with these tools. The SDL holds

identical darts, which are individually released

from surface during cementing jobs. These darts

launch the wiper plugs when they reach the

downhole SST, but unlike free-falling balls, are

pumped down drillstrings to separate fluids and

wipe pipe walls. Other advantages over dropping

balls include positive fluid displacement and

elimination of the time and uncertainty of waiting

for balls to reach bottom.

The heart of DeepSea EXPRES, the downhole

SST, allows use of high-performance, easily

drillable EXPRES plugs with simplified designs

that eliminate problems associated with pumping

fluids through wiper plugs. The tool retains wiper

plugs, preloaded in a basket with over 2000 lb

force, until they are launched by arrival of a dart

from the SDL. Friction holds plugs in place during

pumping operations. The current design accepts

up to three 8 5/8- to 13 5/8-in. plugs, or two 16- to

20-in. plugs that are under development. During

circulation, mud flows down the drillpipe,

through a sliding sleeve and out two orifices into

the casing-SST annulus. When a dart reaches the

tool, drillpipe pressure forces the sliding sleeve

down, ensuring that each dart travels a full

length. Continued pumping forces the dart and

rod down, pushing a plug out of the basket. After

a dart reaches its final position, a spring retracts

the sliding sleeve to ensure complete,

unobstructed flow through the orifices. Darts

remain in the holder and are retrieved with the

tool after the job.

Rod travel is slowed by a shock absorber filled

with hydraulic oil that flows past a small gap

Oilfield Review

■■The heart of DeepSea EXPRES. The downhole Sub-sea Tool (SST) allows use of high-performance, easilydrillable EXPRES plugs with simplified designs thateliminate pumping fluids through wiper plugs. Duringpumping operations, wiper plugs, preloaded in a bas-ket with over 2000 lb force, are held in place inside abasket until they are launched by arrival of a dart fromthe Surface Dart Launcher (SDL).

Spring

Orifice

Rod

Hydraulicshock

absorber

Bottomplug being

released

Sliding sleeve

First dart

Dart holder

Hydraulic oil

Shear pins

Plug basket

Top plug

Plug spacers

1. Drelkhausen H: “Quality Improvement of LinerCementations by Using Bottom and Top Plugs,” paper SPE/IADC 21971, presented at the SPE/IADCDrilling Conference, Amsterdam, The Netherlands,March 11-14, 1991.

Summer 1996

Cement and Spacer MixingA mixed 95/8- by 97/8-in. intermediate cas-ing string was set at 12,673 ft [3863 m] inthe Gulf of Mexico by Anadarko PetroleumCorporation. A bottom wiper plug was runbetween mud and spacer. From all indica-tions, pipe was cemented normally and thejob was successful. On surface, full returnswere taken and samples for quality controlset up as expected. However, two days aftercementing, while testing casing to 5000 psi,pressure dropped to zero. After casingintegrity was checked with a packer andfound to be intact, the float shoe wasdrilled, but no cement was found. After pri-mary cementing, the well circulated aroundthe intermediate casing annulus during acement squeeze. Evaluation with CBTCement Bond Tool, CET Cement EvaluationTool and USI UltraSonic Imager logs indi-cated no cement with strength.

Common problems with cement harden-ing and over-retardation by cement addi-tives were ruled out as causes, but tests oncement-spacer mixtures indicated that mod-erate amounts of spacer could cause longsetting times. A total of 382 bbl [60.6 m3] ofcement and 80 bbl [12.7 m3] of spacer wereused. If these two fluids mixed completely,the ratio of spacer to cement would beabout 17%. Cement contaminated by 20%spacer attained a compressive strength ofonly about 25 psi in 48 hours, whichmatched the actual behavior observed in thefield. Cement-mud mixtures were evenmore retarded.

Software to evaluate casing displacementswas not available during this investigation,but mixing due to poor rheological dis-placement and cement retardation byspacer were suspected. Later, displacementcalculations using these well conditionsshowed that the spacer-cement interfacewas unstable and displacement efficiency

between the rod piston and bore. The resulting

pressure differential resists rapid movement

and stops the rod after plugs are released.

Combined with plug friction, this causes a

1500 psi [10,350 kPa] pumping pressure increase

and provides a positive indication of plug launch.

Three brass shear pins increase top-plug release

pressure to 3000 psi [20,700 kPa]. A sleeve

holding these pins slides down, but remains

inside the basket after the top plug leaves the

tool. Spacers that keep plugs from sticking

together also slide down the basket and are

retrieved with the tool.

Systems are also available to improve liner

cement jobs. In the past, one pump-down plug

and a top plug were used, but new top and

bottom, four-plug systems prevent cement

contamination inside liners. Spacer is pumped

down drillpipe followed by a pump-down plug,

cement slurry, another pump-down plug and

displacement fluid. The first pump-down plug

passes through the top wiper plug and into the

bottom wiper plug at the top of the liner where it

latches into a catcher. Pressure shears pins

attaching the bottom wiper plug to a mandrel and

the plug is pumped down the liner to the float

collar. A further increase in pressure shears the

catcher from the bottom wiper plug, allowing it to

move into a circulating tube, which permits

cement slurry to pass through float equipment

into the annulus. The second pump-down plug

latches into the top wiper plug, which is

displaced through the liner until it reaches the

bottom wiper plug where it forms a seal.

55

56 Oilfield Review

95/8-in. casing

MUDPUSH XS/SALTBONDCement Slurry

0

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7-in. liner

MUDPUSH/Lead Slurry

Lead/Tail Slurries

020

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40

60

■■Gulf of Mexico case history. On this intermediate-casing primarycement job, a bottom plug was run between mud and spacer.Since there was no plug between spacer and cement, cement couldmix with spacer while flowing down casing. Displacement effi-ciency is less than 50% when cement reaches the bottom of thestring. The interfacial boundary shape highlights the magnitude ofthe problem. There is a region of no spacer flow around the insidediameter of the pipe as cement flows down through the center. Thisplot assumes no interfacial mixing, but in reality, there is probablya high degree of interfacial mixing between the two fluids.

■■Balikpapan, Indonesia case history. Efficiency plots show verylow displacement—10 and 20%, respectively—for interfacesbetween lead cement and spacer, and lead and tail slurries forcementing operations on this long liner. Interfacial boundaryplots also show a region of negative velocity, indicating highlikelihood of interfacial mixing between fluids.

was well below 50% (above left). Running abottom wiper plug only between mud andspacer allowed cement to fall through andmix with spacer.

Tail Bypassing Lead SlurryIn Balikpapan, Indonesia, Unocal cementeda long, 7-in, liner with two slurries—12.5ppg lead and 15.8 ppg tail. The liner topwas at 2240 ft [683 m] and the bottom wasat 9844 ft [3000 m]. In liner applications, ofcourse, an added difficulty is dropping bot-tom plugs, and in this case, the problemwas compounded because viscosities had tobe kept low to avoid fracturing the well dueto high friction pressures. During displace-ment, high frictional pressures resulted inthe premature termination of the job, leav-ing cement in the liner. Evaluation of dis-placements for this liner cement job indi-cated that lead slurry fell through spacerand tail slurry fell through the lead.

Interfacial boundary shapes betweenspacer and lead slurry, and lead and tailslurries show a tendency for reverse flow oflighter fluids at the interface in both cases,indicating high likelihood of fluid mixingbetween stages. Calculations also showlow displacement efficiencies—10 and20% (above right ). Tests on cement andmud mixtures resulted in high viscositiesthat correlated with high displacementpressures during the actual job.

Integrating Fluid Services Quality cement jobs depend fundamentallyon the ability to predict and manage fluidsand displacement performance over a widerange of conditions. Personnel training,from management through engineering tofield operations, is high on the list of issuesthat must be addressed to properly integratedrilling and cementing fluids and imple-ment total fluids management. Mud engi-neers do not have to run cement pumpsand cementers do not have to supervisedrilling fluids programs, but it is helpful ifeach understands the other’s needs. If theentire fluids process is to be optimized,cooperation must develop through appreci-ation of needs and intentions of the otherdiscipline. Formal crosstraining must besupplemented by practical experience, withthe goal of establishing wellsite “fluids-engineering” teams dedicated to optimizingall fluid operations.

Rather than view other services from afar,drilling fluids engineers and cementers need

to cooperate in designing structured fluidsequences—fluids trains—for wells. Atwellsites, cementers should gain hands-onfluids experience as backup mud engineersand act as mentors to mud engineers duringcementing operations. At offshore andremote locations where engineers reside onlocation, this approach can be formalizedwith one service-line specialist acting asteam leader in addition to performing pri-mary product-line responsibilities. Effectiveteam leaders must be experts in their pri-mary field, familiar with other disciples andbe good communicators. With availablefluids technology, efficiencies can be foundin cooperation and interfacing between flu-ids services, and between fluids teams andoperators. By restructuring the approach towell construction fluids, savings are avail-able with no up-front increase in either costor risk. —MET