a first look at platform express measurements
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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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0.2 200ohm-m 0.2 200ohm-m 0.2 200ohm-mAIT-H90 in.
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AIT-H10 in.
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AIT-H60 in.
AIT-H30 in.
AIT-H20 in.
AIT-H10 in.D
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, 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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t
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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
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Core plugs Whole cores
Borehole geophysics
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
6600
7000
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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
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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
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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
tef
ficie
ncy,
%
60
80100
20
40
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
60
80100
20
40
0 1 2 3 4 5 6
Dis
plac
emen
tef
ficie
ncy,
%
Normalized time
7-in. liner
MUDPUSH/Lead Slurry
Lead/Tail Slurries
020
100
0 1 2 3 4 5 6
Dis
plac
emen
tef
ficie
ncy,
%
Normalized time
40
60
80
020
80
100
0 1 2 3 4 5 6
Dis
plac
emen
tef
ficie
ncy,
%Normalized time
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
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