4

Steve BonnerMark FredetteJohn LovellBernard MontaronRichard RosthalJacques TabanouPeter WuSugar Land, Texas, USA

Brian ClarkRidgefield, Connecticut, USA

Rodger MillsExxon USAThousand Oaks, California, USA

Russ WilliamsOXY USA Inc.Houston, Texas

Resistivity While Drilling—Images from the String

For help in preparation of this article, thanks to SamanthaDuggan, Anadrill, Sugar Land, Texas; Tom Fett, Geo-Quest, Houston, Texas and Mary Ellen Banks and MartinLüling, Schlumberger-Doll Research, Ridgefield, Con-necticut.

Resistivity measurements made while drilling are maturing to match

the quality and diversity of their wireline counterparts. Recent

advances include the development of multiple depth-of-investigation

resistivity tools for examining invasion profiles, and button electrode

tools capable of producing borehole images as the drillstring turns.

It is hard to believe that logging whiledrilling (LWD) has come such a long wayover the last decade. In the early 1980s,LWD measurements were restricted to sim-ple resistivity curves and gamma ray logs,used more for correlation than formationevaluation. Gradually, sophisticated resistiv-ity, density and neutron porosity tools havebeen added to the LWD arsenal.1 With theadvent of high-deviation, horizontal andnow slim multilateral wells, LWD measure-ments often provide the only means of eval-uating reservoirs. The quality and diversity ofLWD tools have continued to developquickly to meet this demand. Today, applica-tions include not only petrophysical analysis,but also geosteering and geological interpre-tation from LWD imaging (next page).2 Thisarticle focuses on the latest LWD resistivitytools—the RAB Resistivity-at-the-Bit tool andthe ARC5 Array Resistivity Compensatedtool—and the images they produce (see “AProfile of Invasion,” page 17).

(continued on page 6)

Oilfield Review

nFormation evalua-tion made by com-bining data fromseveral LWD mea-surements. This loginterpretation wasmade using ELANElemental Log Anal-ysis software anddata from the RABResistivity-at-the-Bittool, CDR Compen-sated Dual Resistiv-ity and CDN Com-pensated DensityNeutron tools. Volumetric analysis(track 5) shows aquartz-rich zone ofrelatively highporosity. The brownshading indicatesthe movable gasvolume calculatedfrom CDR and RABdata run severaldays later. The RABresistivity image(track 4) shows thatthe sand body issplit into three mainlobes with shale per-meability barriers.

1:2400 ft

XX500

XX450

Net pay

Net sand

Gas effectDensity porosity

CDN60.0 p.u. 0Neutron porosity

CDN60.0 p.u. 0

Add. gas volume right after drilling CDR

Irreducible water

Moved water

Water

Gas volume 7 days after drilling RAB

Quartz

Bound water

Illite

Combined model0 p.u. 100

Perm to gas

Perm to water

Gamma ray

0 API 200

Perm to water

10000 md 0.1

Perm to gas

10000 md 0.1RAB image

0 deg 360

Ring res. RAB

0.2 ohm-m 20

Shallow res. RAB

0.2 ohm-m 20

Medium res. RAB

0.2 ohm-m 20

Deep res. RAB

0.2 ohm-m 20

Phase shift res.CDR

0.2 ohm-m 20Attenuation res.

CDR0.2 ohm-m 20

Diff. caliper-10 in. 10

5Spring 1996

AIT (Array Induction Imager Tool), ARC5 (Array Resistiv-ity Compensated tool), ARI (Azimuthal ResistivityImager), CDN (Compensated Density Neutron), CDR(Compensated Dual Resistivity tool), DIL (Dual InductionResistivity Log), DLL (Dual Laterolog Resistivity), DPT(Deep Propagation Tool), ELAN (Elemental Log Analysis),EPT (Electromagnetic Propagation Tool), FMI (FullboreFormation MicroImager), FracView (fracture synergy log),GeoFrame, INFORM (Integrated Forward Modeling),

1. Bonner S, Clark B, Holenka J, Voisin B, Dusang J,Hansen R, White J and Walsgrove T: “Logging WhileDrilling: A Three-Year Perspective,” Oilfield Review 4,no. 3 (July 1992): 4-21.

2. Bonner S, Clark B, Decker D, Orban J, Prevedel B,Lüling M and White J: “Measurements at the Bit: ANew Generation of MWD Tools,” Oilfield Review 5,no. 2/3 (April/July 1993): 44-54.

MicroSFL, Phasor (Phasor-Induction SFL tool), Power-Pulse (MWD telemetry tool), RAB (Resistivity-at-the-Bittool), SFL (Spherically Focused Resistivity), Slim 1 (slimand retrievable MWD system), StrucView (GeoFramestructural cross section software) and TLC (Tough Log-ging Conditions system) are marks of Schlumberger. FCR(Focused Current Resistivity tool) is a mark of ExplorationLogging. Dual Resistivity MWD tool is a mark ofGearhart Geodata Services Ltd. (now Halliburton).SCWR (Slim Compensated Wave Resistivity) is a mark of Halliburton. EWR (Electromagnetic Wave Resistivity),EWR-PHASE 4 and SLIM PHASE 4 are marks of Sperry-Sun Drilling Services.

Top of hole

Bottom of hole

Top of hole

Top of hole

Bottom of hole

Top of hole

Bed Dipping Away from Kickoff Point (4)

Folded Bed (5)

Bormap in Horizontal Hole (3)

3D View

Unrollingthe cylinder

Bormap

Top ofhole

Horizontalbedding plane

Verticalfracture

Nearly verticalnatural fracture

Vertical induced fracture

Vertical Well (1)

Horizontal Well (2)

Beddingplane

Fracture

0° 90° 180° 270° 360°

North

Beddingplane

Fracture Bottom of hole

Top of hole

nInterpretation of images. Resistivity images show the surface of the borehole—cut along the northerly direction for a vertical well (1) orthe top of the hole for a horizontal well (2)—laid out flat. The image is artificially colored to show contrasts in resistivity—dark brown islow resistivity and light brown is high resistivity—that highlight bed boundaries, faults or fractures. Features crossing the borehole at anangle show characteristic sinusoidal patterns (3). They also are wider at the bottom and top of the hole. Images of beds dipping awayfrom the kickoff point in horizontal boreholes produce an arrow-head pointing in the direction of drilling (4). Images of folded beds pro-duce a characteristic eye shape (5).

Geology From the BitSimply stated, resistivity tools fall into twocategories: laterolog tools that are suitablefor logging in conductive muds, highly resis-tive formations and resistive invasion; andinduction tools which work best in highlyconductive formations and can operate inconductive or nonconductive muds.3 TheRAB tool falls into the first categoryalthough, strictly speaking, it is an electroderesistivity tool of which laterologs are onetype (see “From Short Normal to Axial Cur-rent,” page 9).4

6

3. It should be remembered that laterolog and inductiontools both work well in many environments.

Laterolog tools need a complete electric circuit towork. Current passes from an emitting electrodethrough the borehole into the formation and back tothe tool via a surface electrode or a return electrodeon the tool. Resistivity is a function of voltage drop,between return electrode and source, and source cur-rent. Laterolog tools have to make electric contactwith the formation through either a conductive mudsystem or by direct physical contact. They are capableof logging highly resistive formations and are good atspotting thin resistive beds.

The RAB tool has four main features:• toroidal transmitters that generate axial

current—a technique highly suited toLWD resistivity tools5

• cylindrical focusing that compensates forcharacteristic overshoots in resistivityreadings at bed boundaries, allowingaccurate true resistivity Rt determinationand excellent axial resolution

• bit resistivity that provides the earliestindication of reservoir penetration orarrival at a casing or coring point—alsoknown as geostopping

• azimuthal electrodes that produce aborehole image during rotary drilling.

Induction tools do not need to make contact withthe formation. Instead they transmit electromagneticwaves that induce formation eddy currents. The eddycurrents are a function of resistivity—the higher theconductivity, the greater the induced formation signal.The induced signals are picked up by receiver coilsand transformed into resistivity measurements. Induc-tion tools work best in high-conductivity formationsand can operate in nonconductive mud.

4. Bonner S, Bagersh A, Clark B, Dajee G, Dennison M,Hall JS, Jundt J, Lovell J, Rosthal R and Allen D: “A New Generation of Electrode Resistivity Measure-ments for Formation Evaluation While Drilling,”Transactions of the SPWLA 35th Annual Logging Symposium, Tulsa, Oklahoma, USA, June 19-22,1994, paper OO.

5. Arps JJ: “Inductive Resistivity Guard Logging Appara-tus Including Toroidal Coils Mounted on a ConductiveStem,” US Patent No. 3,305,771, February 1967.

This last feature allows the RAB tool to beused for geological interpretation.

Three 1-in. [2.54-cm] diameter buttonsare mounted along the axis on one side ofthe RAB tool. Each button monitors radialcurrent flow into the formation. As the drill-string turns, these buttons scan the boreholewall, producing 56 resistivity measurementsper rotation from each button. The data areprocessed and stored downhole for laterretrieval when the RAB tool is returned tothe surface during a bit change. Oncedownloaded to the wellsite workstation,images can be produced and interpretedusing standard geological applications like

Oilfield Review

Gianzero S, Chemali R, Lin Y, Su S and Foster M: “A New Resistivity Tool for Measurement-While-Drilling,” Transactions of the SPWLA 26th AnnualLogging Symposium, Dallas, Texas, USA, June 17-20,1985, paper A.Grupping TIF, Harrell JW and Dickinson RT: “Perfor-mance Update of a Dual-Resistivity MWD Tool WithSome Promising Results in Oil-Based Mud Applica-tions,” paper SPE 18115, presented at the 63rd SPEAnnual Technical Conference and Exhibition, Hous-ton, Texas, USA, October 2-5, 1988.

6. Coiled tubing, run into a borehole, forms a naturalhelix. At some stage the frictional forces betweenborehole and coiled tubing become greater than theforce pushing the tubing downhole causing the helixto expand and lock tight against the boreholewall—helical lockup.

Austin Chalk Trend

Texas

Houston

Arkansas0 100

miles

Pearsall

Mexico

Giddings

Brookeland

Master’sCreek field

North Bayou Jack

Gulf of Mexico

Louisiana Mississippi

nLocation of Master’sCreek field in rela-tion to other fields ofthe Austin Chalktrend.

nCrossing bedding planes. As the borehole crosses an almost horizontal, low-resistivitybed, the RAB image shows a characteristic high-amplitude sinusoidal image (darkbrown). Interpreters have picked the bed boundaries (green) for structural interpretation.The notation TD:11/26—True Dip: dip magnitude/dip azimuth—indicates that this bed-ding plane is dipping at 11° to the NNE, north 26° east to be exact.

Crossing the borehole almost vertically at XX896 ft is a fracture (yellow). TD:87/359indicates that the fracture is dipping north at an azimuth of 359° and is nearly vertical,87° from the horizontal. The strike, or trend, of the fracture is perpendicular to the dipdirection—east/west.

The cylindrical 3D image (inset) shows the borehole images as if viewed from the rightof the hole.

xx870.0

xx875.0

xx880.0

xx885.0

xx890.0

xx895.0

TD:11/26

TD:87/359

Display: straight

Top display: xx885.39 Ft

Bottom depth: xx897.59 Ft

StrucView GeoFrame structural cross sec-tion software (previous page).

Wellsite images allow geologists toquickly confirm the structural position of thewell during drilling, permitting any neces-sary directional changes. Fracture identifica-tion helps optimize well direction for maxi-mum production.

Finding the Cracks in Master’s CreekMurray A-1 is a dual-lateral well drilled byOXY USA Inc. in the Cretaceous AustinChalk formation, located in the Master’sCreek field, Rapides Parish, Louisiana, USA(top right). The Austin Chalk is a low-per-meability formation that produces hydro-carbons from fractures, when present. Indi-cations of fractures were seen from cuttingsand gas shows obtained by mud loggers ona previous well. The intention was to drillthis well perpendicular to the fractureplanes to intersect multiple fractures andmaximize production.

OXY wanted to record borehole images inthe reservoir section for fracture evaluation.Fracture orientation would show if the welltrajectory was optimal for intersecting themaximum number of fractures. Knowledgeof fracture frequency, size and locationalong the horizontal section could be usefulfor future completion design, reservoir engi-neering and remedial work.

Ideally, the wireline FMI Fullbore Forma-tion MicroImager tool would have been run,but practical considerations precluded thisoption. Wireline tools can be conveyeddownhole by drillpipe or by coiled tubing inhigh-deviation or horizontal wells, but pres-sure-control requirements prevented the useof drillpipe conveyance in this case andcoiled tubing was considered too costly.Also, calculations showed that helicalcoiled tubing lockup would occur beforereaching the end of the long horizontal sec-tion.6 So OXY decided to try the RAB tool.

The first lateral well was drilled due northto cut assumed fracture planes at rightangles. During drilling, images wererecorded over about 2000 ft [600 m] of the81/2-in. horizontal hole. After each bit runthe data were dumped to a surface worksta-tion and examined using FracView software.

Images clearly showed the characteristicsinusoids of contrasting colors, indicatingchanges in resistivity as the borehole crossesbed boundaries (right).

7Spring 1996

Although the resolution of the RAB tool isnot high enough to see microfractures, sev-eral individual major fractures and clustersof smaller fractures were clearly seen (topright), providing enough evidence that thewell trajectory was nearly perpendicular tothe fracture trend.7

Based on this information the second lat-eral was drilled south 10° east, again to inter-sect as many fractures as possible at 90°.

Images of CaliforniaComplex tectonic activity in southern Cali-fornia, USA, has continued throughout theTertiary period to the present time. Thisactivity influences offshore Miocene reser-voirs where folding and tilting affect reser-voir structure. Production is from fractured,cherty, dolomitic and siliceous zonesthrough wellbores that are often drilled athigh angle.

Wireline logs are run for formation evalu-ation and fracture and structural analysis—although in some cases they have to be con-veyed downhole on the TLC Tough LoggingConditions system.

The CDR Compensated Dual Resistivitytool was used to record resistivity andgamma ray logs for correlation whiledrilling. The oil company wanted to evalu-ate using the RAB tool primarily for correla-tion, but also wanted to assess the quality ofimages produced. In fact, it was the imagesthat, in the end, generated the most interest.

Good-quality FMI logs were available,allowing direct comparison with RAB images(right).8 Both showed large-scale events, suchas folded beds, that were several feet long, aswell as regular bedding planes. However,beds less than a few inches thick were notseen clearly by RAB images.

nFracture clusters. Several fractures cut the borehole around XX956 ft. The largestanomaly (black) is either a cluster of fractures or a very large fracture. The borehole ispassing parallel to the interface between two beds. The more resistive bed (white) is onthe bottom side of the hole. The cylindrical image (inset) gives an alternative 3D view ofthe borehole image.

nRAB and FMI images of dipping beds. Both RAB and FMI images show large-scaleevents that are several feet long. However, the resolution of the FMI image is muchbetter. Beds less than about 4 in. [10 cm] thick are not clearly seen on the RAB image.

8 Oilfield Review

7. The size of fractures seen by the RAB tool depends on several factors. The physical diameter of the buttonis 1 in. [2.54 cm], which produces an electric fieldslightly larger—1.5 in. [3.81 cm] in diameter. Conduc-tive zones thinner than 1.5 in. can be detected, how-ever, resistive zones need to be larger than this to bedetected. Typically fractures with apertures around 1-in. can be detected if the borehole fluid is conductive.

8. Lovell JR, Young RA, Rosthal RA, Buffington L andArceneaux CL: “Structural Interpretation of Resistivity-At-the-Bit Images,” Transactions of the SPWLA 36thAnnual Logging Symposium, Paris, France, June 26-29,1995, paper TT.

Top Bottom TopRAB Image

Dep

th 1

0 ft

Top Bottom TopFMI Image

(continued on page 12)

xx944.0

xx946.0

xx948.0

xx950.0

xx952.0

xx954.0

Display: straight

Top display: xx952.93 Ft

Bottom depth: xx959.03 Ft

xx956.0

xx958.0

TD : 90/167TD : 86/173

TD : 84/355

TD : 86/177

nElectrode resistivity tools. The first LWD resistivity tools used the normal principle (left). Current is forcedinto the formation, returning to the tool at a second electrode far away. Current and voltage drop are measuredbetween the two so that resistivity can be calculated.

An improvement on this is the laterolog technique (middle). Additional electrodes provide a bucking currentthat forces the central measurement current deeper into the formation. This helps suppress distortion to thecurrent path if nearby conductive beds are present.

A method proposed by JJ Arps uses a toroidal-coil transmitter that generates an axial current in a conduc-tor (right). This technique is ideally suited to LWD electrode resistivity tools. Axial current leaves the drill collarradially and at the bottom of the collar. The amount of radial current at any point depends on the formationresistivity at that location. Two different methods of measuring radial current are used: (1) by the differencebetween axial current measured at two receiver toroids or (2) by direct electrode current meters.

Potentialelectrode

Return

Insulation

Currentelectrode

Focused CurrentResistivity Tool

Measurementcurrent

Return

Insulation

Return

Transmitter

Receivers

16 in

.

Short NormalTool

LateralresistivityR Lat

BitresistivityR Bit

Dual ResistivityMWD Tool

Guardelectrodes

9Spring 1996

1. Evans HB, Brooks AG, Meisner JE and Squire RE: “AFocused Current Resistivity Logging System for MWD,”paper SPE 16757, presented at the 62nd SPE AnnualTechnical Conference and Exhibition, Dallas, Texas, USA,September 27-30, 1987.

2. Arps, reference 5 main text.

Laterologs have their roots in a tool called theshort normal, one of the earliest wireline log-ging tools. Its principles were adapted by manymeasurements-while-drilling (MWD) companiesin the early 1980s to provide a simple resistivitylog for correlation (right). The idea is fairlystraightforward: force current from a sourceelectrode to a return electrode through the for-mation; measure the current and voltage dropbetween the electrodes and use Ohm’s law toderive formation resistivity. However, for accu-rate petrophysical analysis in complex forma-tions, more sophisticated devices are needed tomeasure true formation resistivity, R t.

An improvement on the short normal is thelaterolog technique commonly used in wirelinelogging. Exploration Logging introduced a lat-erolog LWD resistivity tool in 1987 based on thelaterolog 3 wireline tool of the early 1950s.1

This FCR Focused Current Resistivity tool hadtwo additional current electrodes on either sideof the measurement electrode. They providedguard currents that forced the main currentdeeper into the formation to measure Rt.

At about this time, another approach wasdeveloped by Gearhart Geodata Services Ltd.from an idea by JJ Arps.2 The Gearhart DualResistivity MWD tool used a toroidal-coil trans-mitter to generate a voltage gap in a drill collar,which causes an axial current to flow along thecollar. This method is ideally suited to LWDbecause resistivity tools have to be built intomechanically strong steel collars. Below thetransmitter, current leaves the tool radially fromthe collar and axially from the drill bit. Theamount of current leaving the collar at any point

depends on the induced drive-voltage and thelocal formation resistivity. Two resistivity mea-surements are made: a focused lateral resistiv-ity measurement and a trend resistivity mea-surement at the bit. Two receiver toroids, 6 in.apart, each measure axial current flowing pastthem down the collar. The difference in axialcurrent equals the radial current leaving thedrill collar between the two receivers and isused to calculate lateral resistivity. Bit resistiv-ity is derived from the axial current measuredby the lower receiver.

Schlumberger also uses the Arps principle ofgenerating and monitoring axial-current flow inthe RAB tool. However, radial-current flow ismeasured directly, and multiple toroidal trans-mitters and receivers are used in a uniquefocusing technique described later.

From Short Normal to Axial Current

RAB Tool—The WorksThe RAB tool measures five resistivity val-ues—bit, ring and three button resistivities—aswell as gamma ray, plus axial and transverseshock.3 Built on a 6.75-in. drill collar, the 10-ft[3-m] long tool can be configured as a near-bitor in-line stabilizer, or as a slick drill collar(right). When real-time data are required, theRAB tool communicates with a PowerPulseMWD telemetry tool via wireless telemetry or astandard downhole tool bus, allowing total BHAdesign flexibility . However, it must be config-ured as a stabilizer for imaging.

Bit Resistivity—A 1500-Hz alternating currentis driven through a toroidal-coil transmitter, 1 ft[30 cm] from the bottom of the tool, thatinduces a voltage in the collar below. Currentflows through the collar, out through the bit andinto the formation, returning to the collar far upthe drillstring (below right). Knowing the volt-age and measuring the axial current through thebit determines resistivity at the bit. Correctionsare made for tool geometry, which variesaccording to the BHA.

The resolution of the bit measurementdepends on the distance between the transmit-ter and the bit face—the bit electrode length.When the RAB tool is run on top of the bit, theresolution is about 2 ft [60 cm]. As the bit-resis-tivity measurement is not actively focused, thecurrent patterns and volume of investigation are affected by nearby beds of contrasting resistivity. As wellbore inclination increases,the effective length of the bit electrode becomesshorter and, in horizontal wells, equals holediameter.

Bit resistivity relies on a good bit-to-forma-tion electrical path. The path is always excel-lent in water-base mud and generally sufficientin oil-base mud.

Applications for the bit-resistivity measure-ment include geostopping to precisely stop atcasing or coring point picks. For example, in aGulf of Mexico well the objective was to drillonly a few inches into the reservoir before set-ting casing. An induction gamma ray log from anearby well was available for correlation.

Drilling was stopped when bit resistivityincreased to 4 ohm-m, indicating reservoir penetration (next page, bottom). Subsequentmodeling showed that the bit had cut only 9 in.[23 cm] into the reservoir.

Focused Multidepth Resistivity—The RABtool with button sleeve provides four multidepthfocused resistivity measurements. For an 81/2-in. bit, the ring electrode has a depth ofinvestigation of about 9 in., and the three 1-in.buttons have depths of investigation of about 1 in., 3 in. and 5 in. [2.5, 7.6 and 12.7 cm]from the borehole wall into the formation. But-ton resistivity measurements are azimuthal andacquire resistivity profiles as the tool rotates inthe borehole. The sampling rate dictates that afull profile is acquired at rotational speedsabove 30 rpm—generally not a limitation.

Data from the azimuthal scans are storeddownhole and dumped from the tool between bitruns. In addition, the azimuthal data may beaveraged by quadrant and transmitted to sur-face in real time along with the ring and bitresistivity, and gamma ray measurements.

All four resistivities use the same measure-ment principle: current from the upper transmit-ter flows down the collar and out into the formation, leaving the collar surface at 90°

10 Oilfield Review

Uppertransmitter

Azimuthalelectrodes

Ringelectrode

Lowertransmitter

Axial current

Lower transmitter

Ring monitor toroid

Upper transmitter

nBit resistivity measurement. The lower toroidaltransmitter generates axial current that flows downthe tool and out through the bit. The ring monitortoroid measures the axial current. Formation resistiv-ity is given by Ohm’s law once the upper transmitterdrive voltage and the current are known. Correctionsare made to compensate for tool geometry andtransmitter frequency.

nRAB tool.

along its length. The return path is along thecollar above the transmitter. The amount of current leaving the RAB tool at the ring and but-ton electrodes is measured by a low-impedancecircuit. Axial current flowing down the collar ismeasured at the ring electrode and at the lowertransmitter. These measurements are repeatedfor the lower transmitter.

Cylindrical Focusing—In a homogeneous for-mation, the equipotential surfaces near the but-ton and ring electrodes on the RAB tool arecylindrical. However, in layered formations, this is no longer the case. Current will besqueezed into conductive beds distorting theelectric field (next page, top). By contrast, resis-tive beds will have the opposite effect: the cur-rent avoids them and takes the more conductivepath. These artifacts are called squeeze andantisqueeze, respectively, and lead to charac-teristic measurement overshoots at bed bound-aries called horns.

11Spring 1996

150.0. 1:240ft

RAB GRAPI

0.02 SFL Offset wellohm-m

200

0.02 ILM Offset wellohm-m

200

2000

200

20000.2 RAB RING resistivityohm-m

0.2 RAB BIT resistivityohm-m

0.02 ILD Offset wellohm-m

100.0. Wireline, GRAPI

Nonfocused System Active Focusing

Conductive bed

Ring electrode

Single transmitterBSBSBMBMBDBD

12

12

12

R1,R2

T2

BD

BM

BS

RM0

M2

T1

M01 M02

M12

By reciprocityM12 = M21

Upper transmitter

Upper transmitter current

Ring electrodeMonitor toroid

Lower transmitter

Lower transmitter current

Lower monitor toroid

M21

n“Geostopping.” Oneadvantage of a correla-tion tool that measuresresistivity right at the bitis the ability to recog-nize marker beds almostas soon as the drill bitpenetrates. This allowsdrilling to stop preciselyat casing or coringpoints. In this example,the bit penetrated only 9in. into the reservoir.

nCylindrical focusing technique. A conductive bed below the ring electrode causes currents to distort in a nonfocused system (left). Withactive focusing, the current paths penetrate the formation radially at the ring electrode and almost radially at the three button electrodes(right). Radial currents are measured at the ring electrode, R, and at each button, BS, BM, BD, for each transmission. Also the axial currentis measured at the ring electrode by a monitor toroid, M0, and at the lower transmitter by a monitor toroid, M2. There is no monitor toroidat the upper transmitter, the axial current there, M1, is assumed equal to M2 by symmetry. Software translates these measurements intoadjustments of transmitter strength so that the axial currents at M0 cancel.

The cylindrical focusing technique (CFT) measures and compensates for this distortion,restoring the cylindrical geometry of the equipo-tential surfaces in front of the measurementelectrodes. Focusing is achieved by combiningthe current patterns generated by the upper andlower transmitters in software to effectivelyimpose a zero-axial-flow condition at the ringmonitor electrode. This ensures that the ringcurrent is focused into the formation and that nocurrent flows along the borehole.4

Wireless Telemetry—Data from the RAB toolmay be stored in nonvolatile memory or trans-mitted uphole via the PowerPulse MWD teleme-try tool. Data are transferred to the PowerPulsetool by a downhole telemetry bus connection ora wireless electromagnetic link. In the lattercase, the RAB tool transmits data to a receivermodule connected to the PowerPulse tool up to150 ft [45 m] away

3. Bonner et al, reference 4 main text.

4. Bonner et al, reference 4 main text.

Analysis of cores indicated wide distribu-tion of fractures throughout the reservoir withapertures varying from less than 0.001 in.[0.025 mm] to 0.1 in. [2.5 mm]. The buttonelectrodes that produce RAB images arelarge in comparison—1in. in diameter. How-ever, even with low-resistivity contrast acrossthe fractures, the largest fractures or densestgroups of fractures that appear on the FMIimages were seen on the RAB images (left).The RAB tool could not replace FMI data.

What intrigued the oil company, however,was the possibility of calculating dips fromRAB images. If this were successful, then theRAB tool could help resolve structuralchanges, such as crossing a fault, duringdrilling. The suggestion was taken up byAnadrill. With commercial software, dipswere calculated from RAB images. Goodagreement was found between RAB andFMI dips.

Dip correlation during drilling proved use-ful on subsequent California wells. Manyhave complex structures, and the absence ofclear lithologic markers during drillingmeans that the structural position of wellsmay become uncertain. Currently, RABimage data are downloaded when drillpipeis pulled out of the hole for a new bit anddips are subsequently calculated. The dataare used to determine if the well is on coursefor the highly fractured target area (left).

The oil company’s experience with theRAB tool in these formations has shown that:• RAB resistivity data are better in these for-

mations than CDR data.• RAB images compare well with FMI

images, but cannot produce the fine detailrequired for fracture analysis.

• Dips can be calculated from RAB images,leading to structural interpretation.

• Dips calculated during drilling aid direc-tional well control in highly faulted, high-angle, structurally complex wells.

• Dips determine when fault blocks arecrossed and, hence, when to stop drilling.

The close cooperation between Anadrill,GeoQuest, Wireline & Testing and oil com-panies has led to the recent development ofsoftware to process RAB dips downhole.Dips may then be sent to surface duringdrilling for real-time structural interpretation.

12 Oilfield Review

nFractures imaged by RAB and FMI tools. Fractures with large apertures or close spac-ing that appear on the FMI image (right) are seen on the RAB image (left).

nStructural interpretation. Workstation interpretation of RABdips shows that the well penetrates a synclinal fold.

RAB ImageD

epth

4 ft

Top Bottom TopFMI Image

Top Bottom Top

Dep

th 1

00 ft

Correlationbetween traces

Correlation left to right

Traces from RAB tool

Directionof logging

Correlationbetween traces

Directionof logging

Traces from dipmeter tool

nDip processing comparison. Conventional dipmeter tools pro-duce resistivity curves as the tool is moved along the borehole(top). Processing relies on crosscorrelation of similar events loggedat different depths and works well for apparent dip below about70°. RAB dip computation uses the resistivity curves generated asthe three azimuthal buttons scan the borehole (right). Processing ismore robust as the three traces are recorded with the tool at onedepth. There is a fixed interval between the buttons.

Real-Time Dip ComputationMost conventional dip processing relies oncrosscorrelation of resistivity traces gener-ated as the dipmeter tool moves along theborehole (right ).9 This type of processingworks best when apparent dip is less than70°—typical of most formations logged invertical wells. However, in horizontal orhigh-angle wells, apparent dip will mostlikely be greater than 70°. This is the terri-tory of LWD tools. Automatic dipcomputation in such situations is useful forgeosteering applications in horizontal wells,especially if this can be done while drilling.

The new method uses the azimuthal resis-tivity traces generated by the three buttonsof the RAB tool. Bedding planes crossing theborehole will normally appear twice oneach trace as the buttons scan past the beds,first on one side of the hole and then theother. Dip computation is a two-part pro-cess that looks at where the beds appear oneach trace and then where they appearbetween traces.

Where the bed appears depends on itsazimuth with respect to the top of the RABtool. The same bed will appear twice onthe second and third traces, but will be dis-placed according to the dip magnitude.Finding the azimuth is simply a matter ofcorrelating one half of each trace againstthe other half. Dip magnitude depends onthe amount of event displacement betweenpairs of traces. Confidence in the computa-tion is increased because three separateazimuths can be calculated—one for eachbutton—and the three pairs of curves canbe used independently for the dip magni-tude computation.

The direction of dip—the azimuth—is cal-culated from the borehole orientation with

(continued on page 17)

13Spring 1996

9. Rosthal RA, Young RA, Lovell JR, Buffington L andArceneaux CL: “Formation Evaluation and GeologicalInterpretation from the Resistivity-at-the-Bit Tool,”paper SPE 30550, presented at the 76th SPE AnnualTechnical Conference and Exhibition, Dallas, Texas,USA, October 22-25, 1995.

Measurement point

EWR tool

Receiver 1

Receiver 2

Transmitter

CDR tool

Transmitter 1

Receiver 1

Receiver 2

Transmitter 2

EWR-PHASE 4 tool SCWR tool

35-in. spacingupper transmitter

Multiarray MBHCpropagation tool

ARC5 tool

0

34-in. transmitter

22-in. transmitter

10-in. transmitter

Receiver

Receiver

16-in. transmitter

28-in. transmitter

2-MHzpropagation tool

Borehole-compensatedpropagation tool

Multiarray BHCpropagation tool

Multiarraypropagation tool

Directionalsensor andpulserDrillstringdynamicssensor

Gamma ray

Receivers

Transmitters

Wear bands

15-in. spacinglower transmitter

15-in. spacingupper transmitter

ReceiverResistivitymeasurement pointReceiver

35-in. spacinglower transmitter

Wear band

1.5-ftcrossover sub

Wear bands

1

Evolution of the 2-MHz LWD Tool:From EWR to ARC5

nPropagation tools. The first 2-MHz propagation tool, the EWR tool, was designed by NL Industries. The tool had one transmitter and two receivers. Measurementswere made by comparing the formation signal phase shift between the two receivers. Later, borehole-compensated (BHC) tools, such as the Anadrill CDR tool, weredeveloped. Borehole-compensated tools have two transmitters equally spaced on either side of the receiver pair. In the case of the CDR tool amplitude and phase-shiftresistivities are measured. Development of multiarray tools, like the EWR-PHASE 4 tool, allowed multiple depths of investigation and the possibility of invasion profil-ing. Later tools, such as the SCWR tool, were also borehole compensated. The Anadrill ARC5 tool has three transmitters above and two below the receiver array andmeasures five attenuation and five phase-shift resistivities. Borehole compensation is achieved by using a linear mix of three transmitter measurements for each read-ing. This not only eliminates five transmitters required for standard borehole compensation (BHC), but also makes the tool shorter and stronger.

In 1983, NL Industries introduced the first LWD

tool to tackle induction-type environments.1 The

EWR Electromagnetic Wave Resistivity tool has a

2-MHz transmitter and two receivers (above). The

high frequency makes it an electromagnetic wave

propagation tool rather than an induction tool (see

“Why 2 MHz?,” page 16). Induction tools measure

the difference in magnetic field between the two

receivers that is caused by induced formation

4

eddy currents. Propagation tools, however, mea-

sure amplitude and phase differences between

the receivers. All measurements can be trans-

formed into resistivity readings. However, the

EWR tool uses only the phase shift.

In 1988, Schlumberger introduced a borehole-

compensated 2-MHz tool.2 This CDR Compen-

sated Dual Resistivity tool has two transmitters

symmetrically arranged around two receivers

built into a drill collar. Each transmitter alter-

nately broadcasts the electromagnetic waves:

the phase shifts and attenuations are measured

between the two receivers and averaged. The

phase shift is transformed into a shallow resis-

tivity measurement and the attenuation into a

deep resistivity measurement.

The EWR tool described earlier was developed

further by Sperry-Sun Drilling Services into a

multispacing tool.3 This EWR-PHASE 4 tool con-

sisted of four transmitters and two receivers pro-

viding four phase-shift resistivity measurements

which, however, were not borehole compensated.

A slimhole version—SLIM PHASE 4—was intro-

duced in 1994.4 Halliburton also offers a slim

4.75-in. tool—the SCWR Slim Compensated

Wave Resistivity tool.5

Oilfield Review

nARC5 tool.

Wear band

34-in. transmitter

22-in. transmitter

Wear band

10-in. transmitter

Receiver

Receiver

Wear band

16-in. transmitter

28-in. transmitter

Wear band

To GR, transverseshocks, electronics andSlim 1 connection

Tota

l too

l len

gth

21 ft

6 in

.

43/4 in.

0.5T1+0.5T2

f(T5, T4, T3)

f(T3, T4, T5)

f(T2, T3, T4)

f2(T1, T2, T3)

f1(T1, T2, T3)

34 in. 22 in. 10 in. 3 in. -3 in. -16 in. -28 in.

0Measurement point

Total tool length = 21 ft

X(TR) = phase shift or attenuation measuredfrom transmitter at spacing TRTR = 10, -16, 22, -28, 34

T1 R1 R2 T2

0Measurement point

+x in. -x in.

T5 T3 T1 R1 R2 T2 T4

1. Rodney PF, Wisler MM, Thompson LW and Meador RA:“The Electromagnetic Wave Resistivity MWD Tool,” paperSPE 12167, presented at the 58th SPE Annual TechnicalConference and Exhibition, San Francisco, California,USA, October 5-8, 1983.

Various acquisitions and disposals by NL Industries haslead to this technology being transferred to Sperry-SunDrilling Services, a Dresser Industries, Inc. company.

2. Clark B, Allen DF, Best D, Bonner SD, Jundt J, Lüling MGand Ross MO: “Electromagnetic Propagation LoggingWhile Drilling: Theory and Experiment,” paper SPE18117, presented at the 63rd SPE Annual Technical Con-

3. Bittar MS, Rodney PF, Mack SG and Bartel RP: “A TrueMultiple Depth of Investigation Electromagnetic WaveResistivity Sensor: Theory, Experiment and PrototypeField Test Results,” paper SPE 22705, presented at the66th SPE Annual Technical Conference and Exhibition,Dallas, Texas, USA, October 6-8, 1991.

4. Maranuk CA: “Development of the Industry’s First MWDSlimhole Resistivity Tool,” paper SPE 28427, presented atthe 69th SPE Annual Technical Conference and Exhibition,New Orleans, Louisiana, USA, September 25-28, 1988.

5. Heysse DR, Jackson CE, Merchant GA, Jerabek A, Beste Rand Mumby E: “Field Tests of a New 2 MHz Resistivity

nCompensating forborehole effects. Stan-dard borehole compen-sation uses a symmetri-cal arrangement oftransmitters around thereceiver pair (top).Resistivity measure-ments from each areaveraged to compensatefor effects such as holerugosity or drifts inreceiver electronics. TheARC5 tool uses mixedborehole compensation(MBHC) to achieve thesame effect, but withoutthe need to duplicatetransmitters (bottom). By placing transmittersasymmetrically aroundthe receiver pair, variouscombinations of mea-surements may be used.For example, to achieveMBHC for the 22-in.spacing, a combinationof 22-in., 16-in. and 28-in. resistivity measure-ments is used.

Propagating the ARC5 Tool

The latest generation LWD propagation tool is the

4.75-in. ARC5 Array Resistivity Compensated

tool, a self-contained 2-MHz multiarray borehole-

compensated resistivity tool developed to log the

increasing number of slim holes being drilled

(above left). 6 The array of five transmitters

—three above and two below the receivers—

broadcast in sequence providing five raw phase-

shift and five raw attenuation measurements. In

addition, there are gamma ray and transverse

shock measurements.

Borehole compensation (BHC) is achieved by a

method unique to the ARC5 tool. Standard BHC

combines data from two transmitters placed sym-

metrically around the receiver array for one com-

Spring 1996

pensated measurement (above). The ARC5 tool

dispenses with the second transmitter, relying

instead on linear combinations of three sequen-

tially spaced transmitters to provide what is

called mixed borehole compensation (MBHC),

The advantage of this system is that tool costs

ference and Exhibition, Houston, Texas, USA, October 2-5, 1988.

and length are reduced by eliminating five trans-

mitters. Five MBHC phase shifts and attenuations

are then transformed into five calibrated phase-

shift and five calibrated attenuation resistivities

(next page, top).

15

Tool for Slimhole Formation-Evaluation While Drilling,”paper SPE 30548, presented at the 76th SPE AnnualTechnical Conference and Exhibition, Dallas, Texas, USA,October 22-25, 1995.

6. Bonner et al, reference 10 main text.

nARC5 logs before andafter MBHC. The spikyappearance of the logwithout MBHC (top) iscaused by overshoots—horns—in resistivitymeasurements atwashouts. These arti-facts are canceled outby MBHC (bottom).

nOperating frequenciesof Schlumberger resis-tivity tools.

16

100

101

102

103

Rps

, ohm

-m

100

101

102

103

Rps

, ohm

-mWithout MBHC

With MBHC

PH10PH22PH34

2 GHz

200 MHz

20 MHz

2 MHz

200 kHz

20 kHz

2 kHz

200 Hz

Propagation dielectricEPT Electromagnetic Propagation Tool 1.1 GHz

Propagation dielectric resistivityDPT Deep Propagation Tool 25 MHz

Propagation resistivityCDR Compensated Dual Resistivity tool 2 MHzARC5 Array Resistivity Compensated tool 2 MHz

Induction resistivityAIT Array Induction Imager Tool 25,50,100 kHzPhasor Phasor-induction SFL tool 20 and 40 kHzDIL Dual Induction Resistivity Log 20 kHz

Conduction resistivityRAB Resistivity-at-the-Bit tool 1.5 kHzSFL Spherically Focused Resistivity tool 1 kHzDLL Dual Laterolog Resistivity toolARI Azimuthal Resistivity ImagerLLS Laterolog shallow 280 HzLLD Laterolog deep 35 Hz

Since the depth of investigation increases as

the transmitter spacing increases, the five phase-

shift resistivities represent five different depths

of investigation with nearly identical axial resolu-

tion. Similarly, the five attenuation resistivities

represent five deeper reading measurements.

At present, the ARC5 tool communicates to the

surface using the Slim 1 slim and retrievable

MWD system. This is essentially a tool that

latches onto the ARC5 tool. After connection to

the ARC5 tool, data are transferred by an induc-

tive coupling to the Slim 1 system and then con-

tinuously transmitted to the surface acquisition

system by a mud-pulse link.

Why 2 MHz?

A wireline induction tool generates an oscillating

magnetic field—typically 10 to 40 kHz—that

induces eddy currents in a conductive formation.

These, in turn, generate a much weaker, sec-

ondary magnetic field that can be measured by a

receiver coil set. Measuring the secondary mag-

netic field gives a direct measurement of conduc-

tivity—the higher the conductivity, the stronger

the eddy currents, and the larger the secondary

magnetic field.

Induction tools use a trick to cancel the pri-

mary magnetic field’s flux through the receiving

coil set and allow measurement of the secondary

magnetic field only. This is accomplished by

arranging the exact number of turns and precise

positions of the coils such that the total flux

through them is zero in an insulating medium

such as air. In a conductive formation, the flux

from the secondary magnetic field doesn’t exactly

cancel, so the induction tool becomes sensitive

to the eddy currents only. If the same trick were

tried on a drill collar, then similar precision for

coil placement and dimensional stability would

be required. In the harsh conditions of drilling, a

drill collar striking the borehole wall can easily

produce 100 g shocks—more than enough to ruin

any precise coil positioning.

At 2 MHz, precise coil placement doesn’t mat-

ter, because the phase shift and attenuation are

measurable with a simple pair of coils—both

quantities increase rapidly with frequency. While

the two receivers may be slightly affected by

pressure, temperature and shock, borehole com-

pensation completely cancels any such effects.

Increasing the frequency further reduces the

depth of investigation and leads to dielectric

interpretation issues (left).

Oilfield Review

300

320

340

360

380

400

420

Dep

th, f

t

70 80 90 100 110Dip, degrees

0 360 Azimuth, degrees

nReal-time dip com-putation. Dip can becomputed from theresistivity image (left)using a real-timealgorithm (right).Results indicate highapparent dips, near90°. Shown on theresistivity image isthe computed dipazimuth, which runsalong the direction ofthe borehole.

10. Bonner SD, Tabanou JR, Wu PT, Seydoux JP, Mori-arty KA, Seal BK, Kwok EY and Kuchenbecker MW:“New 2-MHz Multiarray Borehole-CompensatedResistivity Tool Developed for MWD in Slim Holes,”paper SPE 30547, presented at the 76th SPE AnnualTechnical Conference and Exhibition, Dallas, Texas,USA, October 22-25, 1995.

respect to north plus the orientation of thebedding plane with respect to the borehole.For example, if on a trace, a bed appears tocut the borehole at 10° and 70°, then theorientation of the bed is 40° with respect tothe top of the borehole. The second tracemay see the same bed at 0° and 80° and thethird trace, at 350° and 90°. Both give theorientation as 40° providing additional con-fidence in the calculation.

To determine the apparent dip, correlationis made between the three traces. In theabove example, the bed appears on oneside of the hole at 10°, 0° and 350° on eachtrace, respectively. As the distance betweenRAB buttons is fixed, simple geometry canbe used to calculate apparent dip betweenany pair of traces. Knowing the boreholetrajectory leads to true dip.

This method does not rely on data col-lected at different depths and is effective inhorizontal wells. Also, the two-step approachof first calculating the dip azimuth and thendip magnitude provides a robust and fast

Spring 1996

algorithm that can be implemented in thetool microprocessor, allowing real-time trans-mission of structural dips (above).

A Profile of InvasionThe ARC5 tool is a 4.75-in. slimhole, multi-spacing, 2-MHz, propagation LWD tooldesigned, in record time, to operate in5.75- to 6.75-in. holes (see “Evolution ofthe 2-MHz LWD Tool: From EWR toARC5,” page 14 ).10 Propagation LWDdevices are similar in principle to wirelineinduction logging tools. They transmit elec-tromagnetic waves that induce circulareddy currents in the formation and pair ofreceivers monitors the formation signal. Atthis stage, however, the physics of measure-ment similarities stops.

LWD propagation tools operate at 2MHz, much higher than the 10- to 100-kHzfrequencies of induction tools (see “Why 2MHz?,” previous page). They are built onsturdy drill collars and are capable of takingthe violent shocks imposed by drilling.Wireline induction tools are essentiallybuilt on well-insulated fiberglass mandrelsthat cannot tolerate such heavy handling.

However, they both perform best in similarenvironments, such as conductive and non-conductive muds and low-to-medium resis-tivity formations.

The ARC5 tool was designed to exploitinterpretation methods developed for thewireline AIT Array Induction Imager Tool. Tothis end, both tools provide resistivity mea-surements at five different depths of investi-gation allowing radial resistivity imaging.

The ARC5 has other advantages over pre-vious LWD propagation technologiesincluding:• improved estimation of Rt• improved estimation of permeability

index• better evaluation of thin beds through

improved resolution• inversion of complex radial invasion

profiles• better interpretation of complex

problems, such as invasion, resistivityanisotropy and dip occurring simultaneously

• reservoir characterization based on time-lapse logging.

Unique to the ARC5 tool is mixed-boreholecompensation (MBHC). This method pro-vides five MBHC attenuation and fiveMBHC phase resistivity measurements pro-cessed from only five transmitters. Standardborehole-compensation (BHC) requires 10transmitters (see “Propagating the ARC5Tool,” page 15).

17

18 Oilfield Review

XX50 X1000 X1500 X2000 X2500

ARC5 Phase Resistivities R

ps, o

hm-m

ARI Resistivities

10 0

10 1

10 2

10 0

10 1

10 2

LLD

, LLS

, Mic

roS

FL, o

hm-m

XX500 X1000 X1500 X2000 X2500

PH10PH28PH34

nARC5 phase-shift resistivity comparison. Deep ARC5 phase-shift resistivity curves fromthe 34-in. and 28-in. spacing, PH34 and PH28 (orange and black curves, top log), correlatewith deep laterolog readings, LLD, recorded by the ARI tool (orange curve, bottom log)several days after drilling. The shallowest reading ARC5 curve, PH10 (green curve, toplog), correlates with the shallow laterolog, LLS (purple curve, bottom log), but reads higherthan the MicroSFL curve (green curve, bottom log). This implies that there was little inva-sion at the time of drilling.

nInvasion profile. The radial resistivity image generated from the ARC5 resistivity curvesshows little invasion. Light brown is high resistivity and dark brown, low resistivity. AtXX500 ft, XX550 ft and X2080 ft are possible sources of seawater influx from nearbyinjection wells.

XX500 X1000 X1500 X2000 X2500

-15

-10

-5

0

5

10Rad

ial r

esis

tivity

, in.

Depth, ft

Raiders of the ARC5A slim horizontal sidetrack in an offshoreMiddle East well provided a good field testfor the ARC5 tool.11 Oil company objectiveswere to gain experience with horizontaldrilling and to understand why more waterthan expected was being produced. Thecarbonate reservoir has major faults andseveral fractured zones, and is being pro-duced under seawater injection.

The 6-in. sidetrack was drilled with theARC5 tool run in record mode above thedownhole motor in a steerable bottomholeassembly (BHA) and an interval of morethan 2000 ft was logged from the kickoffpoint. Later, drillpipe-conveyed wirelinelogs were recorded over the same interval.

Comparisons were made between ARC5phase resistivity readings and deep laterolog(LLD), shallow laterolog (LLS) and MicroSFLmeasurements recorded by the ARIAzimuthal Resistivity Imager and MicroSFLtools (left). Deep ARC5 phase resistivitycurves, PH34 and PH28, agree well withLLD readings implying that applications forLWD propagation tools and laterolog toolsoverlap. The shallowest ARC5 curve, PH10,correlates with the LLS curve and readsmuch higher than the MicroSFL curve. Laterprocessing suggests that there was littleinvasion at the time of drilling.

Wireline log interpretation indicateshydrocarbons throughout most of the inter-val. Water saturation is at a minimum fromX1150 ft to X1250 ft, where ARC5 resistivi-ties read higher than 100 ohm-m.

An invasion profile image produced fromARC5 data clearly shows the effects ofdrilling history, as well as formation perme-ability (left ).12 For example, the intervalfrom X2000 to X2050 ft shows increasedinvasion, because it was logged 24 hours

Imagine the FutureThe ARC5 and RAB tools are part of a newgeneration of LWD resistivity tools capableof producing quality resistivity data for awide variety of applications. Both introducemeasurement techniques unique to LWDand wireline logging. For example, MBHCis a cost-effective alternative to doubling upon transmitters for borehole compensationand cylindrical focusing is a more stablealternative to traditional laterolog focusing(see “Cylindrical Focusing,” page 10).

With the development of INFORM Inte-grated Forward Modeling software, interpre-tation in horizontal wells will be greatlyimproved.13 Couple this with downhole dipprocessing and real-time imaging, and thearguments for resistivity-while-drilling mea-surements become powerful.

The value of LWD data will be furtherincreased by close collaboration with Wire-line & Testing and GeoQuest. For example,the concept of invasion-profile measure-ments leads to exciting possibilities. It offersa chance to look at the invasion process indetail. Resistive invasion infers water-filledporosity, whereas conductive invasion infersoil-filled porosity. In the near future, itshould be possible to predict water cut anddraw some conclusions about permeabilitydirectly from LWD fluid invasion-profile log-ging and resistivity anisotropy processing.

What is the next step in development?Although future possibilities are exciting forresistivity while drilling, the next step willbe more evolutionary than revolutionary.With the development of a family of differ-ent sized ARC5 and RAB tools, measure-ments described in this article can beapplied to more borehole sizes. —AM

X1950

-15

-10

10

-5

5

0

Depth,ft

Rad

ial R

esis

tivity

, in.

X2000 X2050 X2100 X2150 X2200

ARC5 Radial Resistivity Image and Diameter of Invasion

ARC5 Phase-Shift Resistivity

Drilling Summary

0

20

40

60

80

100

RO

P, m

in/f

t, G

R, g

api

gamma ray

time atbottom

ROP

TAB

, hr

10

0

Pha

se re

sist

ivity

, ohm

-m

100

101

102

X1950 X2000 X2050 X2100 X2150 X2200

X1950 X2000 X2050 X2100 X2150 X2200

BA C

19Spring 1996

11. Bonner et al, reference 10.12. Howard AQ: “A New Invasion Model for Resitivity

Log Interpretation,” The Log Analyst 33, no. 2(March–April 1992): 96-110.

13. INFORM software allows an analyst to construct adetailed model of the geometry and petrophysicalproperties of the formation layers along a well path.Simulated tool responses along the well are thencompared to acquired log data allowing the modelto be adjusted until they match. For a more detaileddescription:Allen D, Dennis B, Edwards J, Franklin S, KirkwoodA, Lehtonen L, Livingston J, Lyon B, Prilliman J,Simms G and White J: “Modeling Logs for Horizon-tal Well Planning and Evaluation,” Oilfield Review7, no. 4 (Winter 1995): 47-63.

nDrilling summary (top), ARC5 phase resistivities (middle) and resistivity image (bottom)shown in detail for the interval X1950 ft to X2200 ft. ARC5 data (middle) recorded 24 hrafter a bit change show increased invasion (interval A) compared to the previous interval,which was logged only a few hours after being drilled. Little invasion occurs across a low-permeability streak (interval B). All resistivity curves converge (interval C) indicatingwater breakthrough.

after a bit change (above). Other intervalswere logged within a few hours of drillingand show less invasion. Invasion is deeperwhere drilling is slow and also in high-per-meability streaks. The latter coincide withthe position of fractures and faults that areshown on FMI data.

Two intervals were of special interest tothe oil company—around XX550 ft and

X2080 ft. Formation resistivity approaching1 ohm-m in both intervals indicated thatseawater injection had broken through thesezones. Increased pore pressure in theseintervals resulted in dramatic increases inthe rate of drilling. Several days later, theARI tool showed that invasion had pro-gressed to about 35 in. [89 cm].

The well was completed with a slottedliner and produced 4000 BOPD and 600BWPD compared to 1000 BOPD in theoriginal well. The interval at X2080 ft is themost likely contributor to water production.

Quality in Drilling Operations

In modern industry, quality is often discussed, but frequently misunderstood. The perception of quality—what

it is and isn’t—varies widely from individual to individual and company to company. Oilfield service quality has

received increased attention during the past decade as oil and gas operators strive to maximize hydrocarbon

production and recovery at the lowest possible cost. This article illustrates how one drilling contractor,

Sedco Forex, is infusing a quality culture and mindset in its organization to provide the best possible service.

20

For help in preparation of this article, thanks to JeanCahuzac and Charles Nielsen, Sedco Forex, Montrouge,France; Mike Mannering, Sedco Forex, Singapore; AlanWhitmore, Sedco Forex, Aberdeen, Scotland; and StevePrensky, journalist, New Orleans, Louisiana, USA.

Ellis DuncanIra GervaisChannelview, Texas, USA

Yves Le MoignSunil PangarkarBill StibbsMontrouge, France

Paul McMorranPau, France

Ed NordquistDubai Petroleum CompanyDubai, UAE

Ted PittmanPerth, Australia

Hal SchindlerDubai, UAE

Phil ScottWoodside Offshore Petroleum Pty. Ltd.Perth, Australia

“We must define quality as ‘conformance torequirements’ if we are to manage it.” 1

What is your definition of quality? Tosome, it means fine craftsmanship, precisionand attention to the smallest detail. For oth-ers, it’s consistency and reliability—some-thing produced the same way time aftertime, something you can count on. For stillothers, it’s getting the best value for themoney spent. Whatever your definition, youperceive a product or service to be of highquality—whether it’s a new automobile orhow the waiter handles the orders and fooddelivery in the local restaurant—if it meetsor exceeds your expectations. These expec-tations are often highly subjective. In thefinal analysis, quality is really obtainingwhat was promised by mutual agreementbetween provider and end user. For qualityto be more than mere perception, however,requires established specifications—quan-tifiable standards or benchmarks againstwhich the product or service can be mea-sured objectively.

In the oil field, quality has taken on a newmeaning and importance over the past

decade. During the boom of the late 1970s,speed was all important. Wells were beingdrilled at a phenomenal pace; rigs were inshort supply. How rapidly a contractor couldmove onto location, rig up, get the welldrilled, rig down and move to the next sitewas, more often than not, the principalbenchmark of a quality operation. However,the industry paid a premium price for thisspeedy delivery service, and the quality of theend product, the well, frequently suffered.

With the bust of the mid-1980s, the men-tality of the industry changed drastically. Oiland gas operators were forced to look atways to cut costs and squeeze the most outof every dollar spent. This was a prerequisitefor survival and protection of the bottomline. Speed was no longer the prime deter-minant. It was replaced by a growing aware-ness that quality would be the single makeor break factor in the future. Slowly at first,and then with increasing momentum, oper-ators and service companies alike began toadopt the principles of quality that had, untilthen, been relegated to industries outsidethe oil patch. How the application of theseprinciples by one particular drilling contrac-tor provides dividends to its clients, its per-sonnel and its operations is the focus of thisarticle.

Have demonstrable results beenachieved? Most assuredly they have been,as pointed out by the benefits gained inthree diverse operating areas:

Oilfield Review

1. Crosby PB: Quality is Free. New York, New York,USA: Mentor (1980): 15.

2. Crosby, reference 1: 69.3. DeWardt JP: “Drilling Contracting in the Nineties,”

paper IADC/SPE 19902, presented at the IADC/SPEDrilling Conference, Houston, Texas, USA, February27-March 2, 1990.

•Over a two-year period, working withDubai Petroleum Company, Sedco Forexdecreased operational time by 36% in 60controllable rig activities (see “Middle EastOffshore: Quality in Action,” page 23).

•In West Africa, Elf and Sedco Forex wereable to improve field development eco-nomics significantly by reducing the timeand costs of platform installation and wellconstruction (see “Quality and TeamworkPay Dividends in West Africa,” page 26).

•In Australia, using an innovative “techni-cal limit” approach, which specifically

Spring 1996

targets reductions in operational lost anddown time, Woodside Offshore PetroleumPty. Ltd. and Sedco Forex recently com-pleted a development program 20% underbudget (see “A New Approach to Qualityand Efficiency in Australia,” page 29).

To fully understand the route to theseimprovements, we begin with the funda-mentals of a quality culture—what they areand how they are implemented—and theninvestigate how such a culture has beenestablished within Sedco Forex.

Why the Emphasis on Quality?

“The customer deserves to receive exactlywhat we have promised to deliver.” 2

The drilling industry has evolved signifi-cantly in terms of work scope and the divi-sion of responsibilities between oil compa-nies and service suppliers. Much of thechange has been driven by the proactiveinitiatives in drilling contracting thatemerged early in the 1990s.3 Instead of thedrilling contractor simply executing the taskof drilling a well according to the specifica-tions of the operator, a new way of doingbusiness emerged. Closer communicationlinks were established, and a coordinated,joint decision-making process was adoptedfor well planning. This has led to a betterunderstanding of client needs and expecta-tions than ever before, creation of bench-marks, and an improved image and credibil-ity for the contractor who has become a truepartner in an operational team.

Today, the focus is on reorganizing theway tasks are performed and toward reengi-neering the management structure and

21

22

nThe quality hier-archy. Qualitymanagement linksall aspects of plan-ning, control andimprovement into acontinuous systemfor ensuring confor-mance to estab-lished standards.(Adapted from Juran).

Quality management

Quality assurance

Quality planning Quality control Quality improvement

• Policy• Objectives/goals• Quality manual• Regulations• Standards• Controls• Procedures

• Supervision• Reviews• Inspections• Measurement• Performance

monitoring• Change control• Reporting• Auditing

• Identification ofchronic waste

• Measurement ofnonconformance

• Individualcommitment andinvolvement

• Quality improvementproject-by-project

nThe evolution of quality. The approach to quality has changed dramatically over fourgenerations. Initially, products were overengineered to prevent failure. Then, intenseinspection and quality control replaced large safety margins. Process control brought theera of quality assurance. Today, the emphasis is on quality management, eliminatingpotential deficiencies at the design stage.

Generation 1:OverengineeringGeneration 3:

Quality assurance

Generation 2:Quality control

Generation 4:Quality management

interfaces. Safety and operational proce-dures are merging to bring supplierstogether under a common system. Newtechnology and communications methodsare being applied universally, buildinggreater rigsite efficiency. In short, much haschanged and adapting to these changes hasbecome a major challenge.

This evolution emphasizes client-orientedservice and a commitment to do things rightthe first time and every time—the heart of aquality culture. It means eliminating unnec-essary costs and losses that are the legaciesof poor quality. Over time, a qualityapproach gains market share, increasesprofits and ensures competitiveness.

The Quality Evolution

“It is always cheaper to do the job right thefirst time.” 4

Quality has evolved over four distinctstages (above left ). When materials andmanpower were cheap, engineers designedproducts not to fail by overengineering themwith large safety margins. As materialsbecame increasingly expensive, but man-power remained comparatively cheap, engi-neers designed products that met specifica-tions without these extra margins of safety.While the probability of failure increased,intense inspection became the safeguardagainst delivering inferior products.

Then, when both materials and man-power became expensive, there was a reori-entation toward understanding the pro-cesses to determine the causes of defects.Process control became the basis for mini-mizing the probability of failures. Finally,process control evolved into a more proac-tive approach in which planning for confor-mance from the start was the fundamentalprinciple; analyzing contingencies andavoiding pitfalls at the design stage elimi-nated the need for corrective action later.

The last three stages of this evolution inquality are analogous to Quality Control, inwhich inspection was the order of the day;Quality Assurance, in which in-depth pro-cess analysis ruled; and finally, QualityManagement, the current industry focus(left ).5 Putting a quality-oriented manage-ment structure and culture in place is amajor, long-term task, but one that reapstremendous rewards.

(continued on page 24)

Oilfield Review

4. Crosby, reference 1: 232.5. For background on quality control and quality

assurance:Burnett N et al: “Quality,” Oilfield Review 5, no. 4(October 1993): 46-59.

nThe Trident III. This cantilever jackup is currently equipped to operate in waterup to 250 ft [76 m] deep.

nThe Trident 18 at sunset. This cantilever jackup is equipped to operate in waterdepths to 300 ft [91 m].

Middle East Offshore: Quality in Action

The Sedco Forex Trident III (above left) jackup rig

has been working for Dubai Petroleum Company

(DPC), a subsidiary of Conoco, since the early

1980s. But, operations today are far different

than they were over a decade ago.

In 1995, the Trident 18 (above right) joined the

Trident III as the only other jackup rig working for

DPC. The quality program implemented on the

Trident III was one of the primary reasons the

contract was awarded to the Trident 18, even

though another drilling contractor had submitted

a competitive bid. Also, instead of rebidding the

Trident III contract in 1994, DPC and Sedco Forex

worked together to renegotiate and extend the

contract for two more years.

The Trident III and Trident 18 each typically drill

eight to ten wells per year for DPC offshore Dubai

in water depths ranging up to 200 ft [61 m] with

well depths of 9000 to 18,000 ft [2750 to 5500

m]. Today, these wells are almost exclusively

extended-reach and horizontal.

Recent experience on the Trident III and Trident

18 demonstrates how an oil company, working

Spring 1996

closely with the drilling contractor and other ser-

vice suppliers on the rig, can bring an effective

team approach to well planning and construction.

It also points out the benefits to clients of having

a comprehensive quality program as part of the

drilling contractor’s culture.

Early on, Sedco Forex implemented a number

of quality practices in the interest of continuous

improvement, such as improved methods for han-

dling towing lines during rig moves and for secur-

ing rigs, as well as installing test stumps for

blowout preventers (BOPs). By pretesting BOPs

on the stumps, there is a 4-hour savings in the

time needed to install BOPs.

Starting in 1992, Sedco Forex began to track 60

distinct rig procedures under its control, such as

the amount of time for tripping drillpipe and for

running casing, to establish a series of bench-

marks. After a quality improvement program

based on this assessment was established, the

time spent on these operations was reduced by

22% in 1993 compared to 1992, with a further

14% decrease in 1994 from 1993. In total, this

adds up to a savings of over 120 hours per well,

which is equivalent to drilling eleven wells in the

same time previously needed for ten wells.

When problems arise on the rig, they are

solved jointly through participation by all mem-

bers of the team—from initial discussion to fol-

low-up action. For example, new handling meth-

ods were put in place to avert the potential of dis-

charging oily cuttings while drilling the pay zone.

Also, the jackups were having difficulties with

close alignments to the platforms. Analysis

showed that revised operational procedures

would increase their proximity and permit better

access. This has allowed DPC to add more

drilling slots to the platforms.

“When problems arise, there is teamwork in

solving them,” says Hal Schlindler, District Man-

ager for Sedco Forex. “No one is pointing the fin-

ger or trying to determine who’s at fault. Instead,

the philosophy is ‘what does the team need to do

to fix it’.”

Close communication and analysis between

DPC, Sedco Forex and other service companies

overcame difficult problems while drilling a trou-

blesome shale section. During drilling of the

shale, the well angle is typically built from 30

degrees to nearly horizontal. Problems were

23

Teamwork

All-pervasiveEmployeeand clientoriented

Proactive Systematic

Awareness

Well-defined

Consistent

Continuous improvement

nElements of theQuality Manage-ment System (QMS).Implementation of asuccessful QMSrequires that certainkey elements be pre-sent, tied together byan ongoing commit-ment to continuousimprovement in allactivities.

24 Oilfield Review

ConversionCommitmentConviction

nThe three phases of cultural change. A basic change in corporateculture requires passage through the phases of conviction, commit-ment and conversion. The result is a mindset geared toward creatinga climate of “zero defects.”

Quality Doesn’t Just Happen

“If quality isn’t ingrained in the organiza-tion, it will never happen.” 6

How does one go about changing a cul-ture and infusing a new way of thinking anddoing business in an industry that histori-cally accepts change slowly, and oftenreluctantly? Change can be a daunting chal-lenge and requires a concerted approach,nurtured by the top echelons of the organi-zation and effectively transmitted throughthe rank and file. Specific, measurableobjectives are prerequisites, and the tasktakes much time, patience and persistence.

Quality gurus, like W. Edwards Deming,Philip Crosby and Joseph Juran, have pro-posed a number of procedures for bringinga quality outlook to an organization. No sin-gle approach is necessarily superior, for theyall have many fundamentals in common.Whatever route is chosen, the basic princi-ples of quality will apply, adapted, of neces-sity, to fit the particular industry and com-pany structure. To be successful though, acultural change must evolve through threedistinct phases (below).7• Conviction—deciding something needs

changing• Commitment—demonstrating a serious

desire to change• Conversion—embracing the change.

All three elements are critical. Withoutconviction, the effort will never get off theground. Without commitment, once theprocess has started, it will dwindle and fallshort of its aims. But once conversion hasbeen achieved, the converted stay con-verted, and there is no return to the short-cuts or deficiencies of the past. Achievingthe ultimate goal requires the implementa-tion of a Quality Management System(QMS), one that is grounded in a number ofkey principles (above).

For a QMS to be successful, it must besimple and well-defined so that it can beunderstood and effectively communicatedto all participants through a comprehensiveawareness program and, as a result, becomeall-pervasive within the organization. TheQMS must focus both inwardly and out-wardly and be simultaneously employee-and client-oriented. Internal proceduresneed to be systematic, and application mustbe consistent. Actions should be proactive,not reactive, constantly seizing the initiativerather than waiting for events to happen. Itmust foster an environment of cooperation,mutual goal-setting and teamwork where allemployees are empowered not only to par-ticipate in the system but also to contributein demonstrable ways to achieve estab-lished goals. Above all, there must be a

encountered while running the 7-in. [17.8-cm]

liner through this drilled section. Often, the liner

could not be run to bottom and had to be pulled,

and the section was then redrilled or sidetracked.

Recommendations to overcome this problem

included higher mud weights and drilling speed,

and increased frequency of wiper trips. Since

these modifications were implemented, all liners

have been successfully run and landed without

remedial operations.

According to Schindler, “Every manager from

every company on the rig meets with DPC man-

agement each morning to review the morning

report and the three-day forecast. We define and

analyze problems on the spot, and by the end of

the meeting, everyone leaves knowing exactly

what their responsibilities are.”

Service Quality Appraisals are conducted on a

quarterly basis, and the Trident III and Trident 18

averaged a remarkable 98% rating from DPC for

1995 (see “Service Quality at the Wellsite,” page 33).

“Performance tracking is invaluable,” says

Schindler. “Looking at every aspect of the opera-

tion, in every possible way, pays dividends.”

In addition, the combined drilling team, made

up of Sedco Forex and the other service providers

on the rig, received Conoco Drilling Safety Excel-

lence Awards for outstanding safety performance

for the periods 1993-1994 and 1994-1995.

DPC Drilling Manager Ed Nordquist says,

“One of the keys to the successful operation is

the cooperation between DPC and Sedco Forex.

However, this is becoming the norm today

between operator and contractor. More important

is the fact that Sedco Forex has been involved

with DPC operations for a long time, and rig per-

sonnel know what we expect from them and are

ready to deliver it.”

nContinuousimprovement.Analyzing the sta-tus quo highlightsopportunities forimprovement.Optimal solutionsfor achievingimprovement aredefined and thenimplemented andmonitored toensure that resultsmeet expectations.

The Case for Quality Certification

Focusing

Datagathering

Present situationrevealed

Presentsituation

Action PreferredsituationChoice and

commitment AnalysisNewsituation

Implementation

Formulatingand planning

Identifyingstrategies

25Spring 1996

6. Crosby, reference 1: 119.7. Crosby PB: Let’s Talk Quality. New York, New

York, USA: McGraw-Hill, 1989.8. Crosby, reference 1: 19.9. Burnett et al, reference 5.

10. Voehl F, Jackson P and Ashton D: ISO 9000: AnImplementation Guide for Small to Mid-SizedBusinesses. Delray Beach, Florida, USA: St. LuciePress, 1994.

commitment to continuous improvement inall areas.

The basis for continuous improvement isthe belief that within any situation or anyactivity there is room to improve. The goalis perfection or “zero defects,” nothing less.The road to achieving this passes throughthree specific stages (right). In the first stage,the Present Situation, the status quo is inves-tigated to fully understand where an oppor-tunity exists for improvement, defining thedriving forces for change and whetherchange is really worthwhile.

In the second stage, the Preferred Situa-tion, potential solutions to the improvementopportunity are analyzed and the optimalone chosen. This stage focuses on definingfactors that could inhibit successful imple-mentation of the change and, therefore,require selection of an alternate strategy.

In the third stage, Action, proof of thevalidity of the investigation and the plan-ning of the two previous stages are con-firmed. The solution is implemented, andits success is monitored to ensure that whatis achieved is what was expected. Thecycle then repeats, focusing on additionalopportunities for further improvement. Theoverall process increases efficiency andcompetitiveness, reveals opportunities thatmight otherwise be overlooked and pro-motes teamwork and proactive problemsolving. This leads to the ultimate goal ofTotal Quality Management (TQM) in whichevery person and every activity in an orga-nization contribute to the achievement ofoverall quality objectives. This open andhonest culture includes standard systemsfor recording, investigating, implementingand monitoring improvement opportunities.The goal, again, is to get things right thefirst time, every time.

“Quality management is needed becausenothing is simple anymore, if indeed it ever was.” 8

Today’s complex world has led many toseek ways to safeguard quality through setprocedures and controls. The main bodythat assists industry in doing so is the Inter-national Organization for Standardization,based in Geneva, Switzerland, with its ISO9000 family of programs—the recognizedstandard for a quality system.9

ISO 9000 is concerned with process(what is supposed to happen, how it is sup-posed to be done, who is supposed to do it,where it is to occur and when) rather thanthe product itself. ISO certification assuresthat a business does what it claims to, thatthis can be documented, and that problemswill be resolved, not ignored. It has nothingto do with approving a product or service.Implementation of an ISO 9000 system isbased on identifying and understanding cus-tomers’ requirements and systematizing themethods and procedures necessary formeeting their needs, even as these needschange. These procedures are then docu-mented in a reference quality manual.

Standards, in general, imply specification(against which a product can be measuredto establish if it meets the standard), com-

monality, and some recognized method ofassessment. Achieving ISO certificationinvolves (1) design and implementation of aquality system that meets the requirementsof the standard, and (2) a successful assess-ment completed by a suitable assessor body.

The benefits of having a quality system inplace, which include improved efficiencyand assuring a constant level of quality, canresult in reduced production and inspectioncosts. Furthermore, by providing assurancethat a business will correctly meet customerrequirements in a timely manner, compli-ance with an internationally recognizedquality standard can increase confidence ina supplier, particularly when it may belocated in another country.10

As will be seen in the next section, ISOcertification has become an integral part ofthe Sedco Forex drive to develop a corpo-rate quality culture.

(continued on page 28)

26 Oilfield Review

nN’Kossa derrick sets.These modular, pur-pose-built units providethe capabilities and flexi-bility required by Elf inWest Africa and weredesigned for rapid, effi-cient installation on theplatforms.

Quality and Teamwork Pay Dividends in West Africa

Offshore field development economics are influ-

enced significantly by the size and weight of the

platforms deployed and their installation times. In

the N’Kossa field, West Africa, where water depths

range to 590 ft [180 m], Elf and Sedco Forex have

worked jointly to improve economics by reducing

the time and costs involved in, and by increasing

the efficiency of, platform installation and well

construction.

The N’Kossa field was to be developed with two

platforms. Elf wanted several wells drilled in

advance, so that as soon as platform jackets, deck

equipment and production facilities—in this case,

a barge as the main gathering center, offloading to

a tanker—were in place, production could com-

mence from both platforms at near maximum

rates. The field would, thereby, generate signifi-

cant revenue while the remaining wells were

drilled and placed on stream. To achieve this

objective, Elf and Sedco Forex tackled the project

with a coordinated team approach.

From start to finish, the emphasis was on qual-

ity and communication. Beginning in the spring of

1994, both companies appointed special project

teams to work together on all phases of develop-

ment. Communication channels were established,

and formal and informal group meetings were held

at regular intervals.

The development plan for the N’Kossa field con-

sisted of four phases:

• First, prior to mobilizing the rigs to West Africa,

the modifications and upgrades that were

required for both drilling campaigns were car-

ried out while the rigs underwent shipyard refur-

bishments in Rotterdam.

• Second, two subsea templates were preset and

several wells predrilled through them using the

semisubmersibles Sedco 700 and Sedneth 701,

after which the platform jackets were installed.

• Third, the aft sections of the two semis were

modified to accommodate heavy-lift cranes for

use in installing derrick sets on the platforms.

• Fourth, two specially designed, modular derrick

sets were constructed and transported to loca-

tion for placement on the platforms using the

reconfigured semis.

In addition to the crane installations, modifica-

tions to the semis included changing power and

fluid lines to permit tender-assisted operations

during the subsequent drilling phase of the pro-

ject, when umbilicals would connect the semis to

the derrick sets; reconfiguring the subsea BOP

stacks to a surface stack arrangement; and reposi-

tioning the lifeboats so that the aft sections of the

semisubmersibles could face the platforms

directly during derrick set placement and during

operation in the tender-assisted mode.1

The Elf and Sedco Forex teams devoted much of

their time and effort to the design and logistics

associated with the derrick sets, covering the

entire spectrum from conceptual design to detailed

engineering, construction, movement to location

27Spring 1996

1. For background on tender-assisted drilling: Spiers RL,Tranter PH, Burr GR and Unsworth MI: “Conversion of aSemisubmersible Drilling Unit for Tender-Assisted andConventional Drilling Operations,” paper SPE 26755, presented at the Offshore Europe Conference, Aberdeen,Scotland, September 7-10, 1995.

and, finally, installation on the platforms. During

the construction phase, procedures were defined

to ensure compliance with specifications of all

components received from vendors and for quality

control and inspection. Detailed acceptance test

procedures were issued in conformance with ISO

9001 guidelines. Elf had a representative present

at all times overseeing construction and witness-

ing inspections and component testing.

Problems or discrepancies were resolved via

direct communications between Elf, Sedco Forex,

other service companies and parts vendors. A final

debriefing and quality check was held with all ser-

vice companies involved prior to shipment of the

derrick sets to West Africa.

The 700-ton, self-erecting, modular derrick sets

were designed to be as integrated and compact as

possible to 1) minimize the number of crane lifts

during installation, thereby eliminating as many

peripheral small lifts as possible, 2) limit the

number of connections and tie-ins to reduce lost

time and potential problems due to dynamic

motion of the semis, and 3) minimize dead time

during the loading from the semis to the platforms.

Placement would include a total of 14 lifts each,

with the heaviest being 93 tons.

Several special features were included. The

derrick sets were designed to adapt to the jacket

configuration used in West Africa—with jacket

rails perpendicular to the tender-support ves-

sel—or to jackets with rails parallel to the tender

and to be drip-proof, with all runoff collected at a

central point and then pumped to the tender-sup-

port vessel for separation and disposal. On the

tender-support vessel, the shale-shaker cuttings

are deoiled using a cuttings dryer installation

based on centrifugation of a mixture of base oil

and cuttings.

Stainless steel was used for low-pressure piping

and the drilling shelter to minimize corrosion.

Drilling controls were ergonomically designed for

comfort and efficiency, with a 180-degree view of

the rig floor and derrick provided for the driller.

BOPs could be repositioned without breaking out

well-control lines, and handling facilities for the

BOPs allowed the wellhead to be lifted and

installed preassembled. Fast-connect couplings

were used throughout to minimize downtime in the

nippling up of the BOP stack to the wellhead, and

quick-disconnect couplings were used on hydraulic

control circuits to minimize both oil spillage and

downtime.

Construction began in France in October 1994,

with both derrick sets fabricated simultaneously

(previous page). Construction was completed in

May 1995, and the units were shipped by river

barges to the French coast and offloaded onto an

ocean-going barge for the trip to West Africa. Tran-

sit time was 24 days. The barges were anchored

alongside the semisubmersibles, and the derrick

sets were offloaded onto the decks of the semis

with the heavy-lift cranes. The two semis were

then towed to the N’Kossa field, anchored on loca-

tion, and the derrick sets were offloaded and

rigged up. The process, from derrick set arrival to

final installation, took 25 days. At present, the

predrilled wells are being tied-back to surface

wellheads on the platforms and completed, while

awaiting the arrival of the production barge and

final preparations for drilling additional wells.

As a result of the coordinated team approach

and an overriding commitment to quality in all

aspects of the project by both operator and drilling

contractor, the following economic benefits were

realized:

• The decision to contract two rigs at the same

time with almost identical features allowed Elf

to optimize the field development plan for both

predrilling (stand-alone mode) and tender-

assisted drilling mode.

• The decision to modify the semis saved signifi-

cant rig-up and installation time, and cost com-

pared to the option of securing an expensive

crane barge.

• Use of a tender-assisted configuration, with key

support and accommodation facilities on the

semis, enabled Elf to minimize the size, weight

and cost of the platforms.

• The modular and flexible design features of the

derrick sets provide enhanced capabilities, as

well as lower maintenance and operating costs.

28 Oilfield Review

11. Crosby, reference 1: 116.12. Bobillier AAY and Keary T: “Audits Emphasize

Need for Long-Term Relationship to Improve Pre-vention,” paper SPE 27073, presented at the Sec-ond International Conference on Health, Safetyand the Environment in Oil & Gas Exploration,Jakarta, Indonesia, January 25-27, 1994.

13. A lost-time injury is any work-related injury result-ing from an accident that prevents the person fromcontinuing, in the next following shift, the samejob that he or she was performing before the injury.The frequency rate is expressed as the number ofincidents per million person-hours worked.

Worksite/base riskMinimization mechanisms

• Emergency response• HSE meetings• Permit to work• Checklists• Rig up 3rd party

equipment• Authorization for

exemption• Modification

proposal note• STOP program

Resultsversus

objectives

Adequacy of plan?

Corporate statement of policy

HSE objectives

HSE plan

Communication of HSE plan

Reporting HSE resultsIndicators/statistics

Accidentreport 2nd

analysis

Accidentrisk

data base

Inspectionsand

assessment

Companypolicies andprocedures

Compliance?

Safety firstculture

District HSEplans

STOP program, SMS concept

ComplianceQ-HSE audits

Field Q-HSEinstructors

18

16

14

12

10

8

6

4

2

01986 1988 1990 1992 1994

14.5

10.29.7

7.8

6.17

5.2 4.94.5

3.5

LTI f

requ

ency

rat

e

SL commitmentto halve rate in

5 years

nThe HSE manage-ment system inSedco Forex. Thissystem combinesthe basic policies,procedures, track-ing mechanismsand complianceassessment methodsto form a compre-hensive systemwhich has been auseful foundation fora quality culture.

nSafety performanceand program imple-mentation. The evo-lution of the safetyprogram, withgreater emphasis onpreventive programsand complianceaudits, has resultedin a markedimprovement in thelost-time injury (LTI)frequency rate.

How Have Things Evolved in Sedco Forex?

“Improvement comes with each step of theoverall program.” 11

Sedco Forex is one of the largest drillingcontractors in the world, employing 5100 peo-ple of 50 nationalities and operating 42 off-shore and 34 land rigs in 26 countries. Withsuch a far-flung organization and culturaldiversity, implementing a universal qualityprogram represented a formidable task.

As with any company committed toinstalling a quality program, Sedco Forexbegan with the tools at hand. The startingpoint was the company’s health, safety andenvironment (HSE) system, which was rec-ognized as a model within the drilling con-tractor industry.12

Over the years, Sedco Forex had developeda comprehensive HSE Management Systemthat included policies, procedures, trackingmechanisms and compliance assessmentmethods (above right). This system had its ori-gins in a Safety Management System (SMS)which had received considerable attentionfrom industry peers in the late 1980s.

In 1986, Schlumberger management com-mitted to a 50% reduction, over a five-yearperiod, in the drilling lost-time injury (LTI)frequency rate—as defined and reported bythe International Association of Drilling Con-tractors (IADC)—as a show of the corpora-tion’s dedication to safer drilling operationsin the industry.13 This commitment moti-vated the staff and paved the way for a revi-talized safety awareness program in whichsafety activities grew more focused, profes-sional and proactive. Results improved andthe target was achieved (right).

The safety system proved to be a goodstarting point, first for HSE and then forquality efforts. Much of what was neededwas already in place. Over time, managersrecognized that every aspect of operationscould profit from the quality drive. Analysisof accidents and operating failures pointedout the need for better tracking and for clos-ing the loop with specific solutions. Stilllacking, however, was a mechanism for

identifying the cost of quality nonconfor-mance and quantitative measurements ofreal losses.

In general, other than IADC statistics,there are few internationally recognizedbenchmarks for the drilling industry. Thismeant that Sedco Forex had to define andimplement its own set of benchmarks. Thishas been done. Each year, targets are set forkey indicators, and these targets becomeintegral to the company’s objectives, on apar with financial goals.

The system is simple and focused. Fatali-ties, LTIs and major losses, as well as com-pliance with HSE training, identification ofrisks and service quality appraisals aretracked and analyzed at headquarters.Results are regularly summarized and com-municated to the field. Deeper into the field

organization, the number of benchmarksincreases accordingly, finally reaching rig-specific needs. For the first time, a system-atic and coordinated effort is being used toquantify and understand losses in real finan-cial terms.

ISO certification of selected locations hashelped further emphasize the drive toward aquality culture. Operations in Aberdeen,Scotland and Brazil, the EngineeringDepartment in Montrouge, France, and thelogistics and supply center in Channelview,Texas, USA, have been awarded ISO certifi-cation (see “The Road to ISO Certification,”page 32).

Planning Operations

Planning feedback loop

Remove orrefine process

(what if)

Developtheoretical

well

Assign timeestimates

Finalize plan,developtechnical

limit

Expertise

Reviewoffset data

Identifymagnitudeof blockers

Developways toremove

Teambuilding Expertise

Reporting

Trackagainst plan

Analysis

Identifydeviationfrom plan

TQMfeedback loop

nTechnical limit model.This innovative approachto improvement in wellconstruction efficiencytargets the best possiblelevel of performance asthe goal, seeking to elimi-nate all nonproductivetime and efficiency block-ers involved in drillingand completion opera-tions. (Courtesy of Wood-side Offshore PetroleumPty. Ltd.)

A New Approach to Quality and Efficiency in Australia

1. Bond DF, Scott PW, Page PE and Windham TM: “StepChange Improvement and High Rate Learning Curve areDelivered by Targeting Technical Limits on Sub-Sea Wells,”paper IADC/SPE 35077, presented at the 1996 IADC/SPE

In 1993, Woodside Offshore Petroleum Pty. Ltd.

committed to improve its offshore well construc-

tion performance on the Northwest Shelf of Aus-

tralia. The company’s analysis of operations con-

ducted from 1968 to 1992 showed erratic results,

with high average drilling times compared to pub-

lished benchmarks.

For the upcoming Wanaea and Cossack develop-

ments in 270 ft [82 m] of water, which would

include directional wells and the first-ever subsea

completions for the company, Woodside instituted

an aggressive target-setting and planning method-

ology, based on asking the question “What is pos-

sible?” instead of “How can we improve?” The

approach had a central philosophy: targeting the

“technical limit,” a level of performance judged as

the best possible for a given set of parameters

(right).1 Implementation of such a radical change

in thinking required an extraordinary effort and

commitment, and the building of new relationships

with the drilling contractor and other service sup-

pliers, founded on teamwork and effective commu-

nications.

Studies by Woodside had pointed out the critical

importance of the drilling rig’s specifications. The

cost of higher level rig specifications could easily

be justified if the added capabilities translated into

significant efficiency gains toward the goal of

achieving the theoretical minimum well time, the

technical limit. This permitted “fit-for-purpose” rig

selection and sole source negotiation of the

selected rig, eliminating the need for a low-bid

tendering process. Working with Woodside, Sedco

Forex assessed rig options that would deliver the

desired specifications, and the Sedco 702

semisubmersible was selected for the project.

Sedco Forex was involved from the outset in the

extensive planning phase that spanned a period of

nine months. The company placed a former rig

superintendent in the Woodside office to liaise

directly with Woodside’s engineers and design

team. The emphasis was on developing bench-

Spring 1996

Drilling Conference, New Orleans, Louisiana, USA, March12-15, 1996.

marks—the technical limits—optimizing the oper-

ational process and communicating the plan and

process to everyone involved, including

roustabouts on the rig, to enlist their commitment

and ownership. Start-up seminars and regular,

joint management visits and presentations helped

facilitate and underscore the communication pro-

cess. Throughout, a “no-blame” culture was

adopted by Woodside in all its dealings with ser-

vice suppliers, a culture that encouraged problem

solving rather than finger pointing.

Critical path thinking was adopted during the

assessment phase. All activities that could affect

the critical path, either positively or negatively,

were identified and analyzed. Much of the effort

focused on areas normally defined as conventional

down time and lost time. But, studies went further

to concentrate on what became known as “invisi-

ble lost time,” inefficiencies targeted for the first

time using the technical limit approach.

The process resulted in improved procedures

and techniques that speeded operations. For

example, subsea trees were normally assembled

and pressure tested in the moonpool of the

semisubmersible, inhibiting other activities. Tree

and tree-handling operations were removed from

the moonpool area for improved efficiency. During

drilling, running of the drilling riser and BOPs was

streamlined with better make up of lifting subs and

pickup procedures. Where possible, bottomhole

assembly (BHA) components were made up

off-line, allowing pickup and mounting of the

BHA in one piece using a specially designed

roller system.

Applying this methodology, Woodside drilled

three new wells and installed six subsea comple-

tions 20% under budget. By successfully reducing

lost and down time and increasing the percentage

of effective time, they were able to drill the third

well in the project in 20 fewer days than the first.

“Everything we did targeted process optimiza-

tion and control. It has been enormously satisfying

to see our team of people from different compa-

nies pull together—and in the same direction—to

achieve top-class results,” says Phil Scott, Well

Construction Manager for Woodside. According to

Ted Pittman, Sedco Forex District Manager,

“The way the team worked together can best be

summed up in the project motto: ‘Pride in Perfor-

mance.’ From the start, it motivated all members

of the team and kept us continually focused on

quality and efficiency.”

29

nQuality management system. The quality manual collects the key aspects of the sys-tem that include measurement, communication and continuous improvement.

Quality manual Measurement Communication Continuousimprovement

Qualitymanagement system

Uniting all aspects of the QMS is therecently issued Quality Manual, whichdefines a consistent methodology for thepursuit, tracking and structure of the qualityeffort and emphasizes measurement, com-munication and continuous improvement(above ). The HSE and quality functionshave been merged into a universal Q-HSEfunction for coordinating and managing thequality system. The focus is constantly onthe three prime elements, or dimensions,that must be considered in every qualityactivity—product, process and people(below). These elements provide the foun-dation for the new quality culture.

A corporate definition of quality hasemerged: “Giving the client what he wants,when he wants it, at a mutually agreedcost.” This entails defining and meeting theclient’s specifications and expectations;keeping to schedules, programs and projectplans; and satisfying the financial require-ments of both parties. Specifications mustbe agreed to in advance, must be backed upby an effective delivery system and mustnever be less stringent than the internal

30

nQuality dimensions. The QMS is con-stantly focused on three interconnectedaspects of quality: the product, the processand the people involved.

Product

SatisfactionOwnership

People

ConsistencyOptimizationControllable

Process

Fit-for-purposedesign

ConformanceFollow-up

Q-HSE guidelines established within SedcoForex. The remainder of this article focuseson the implementation of specific SedcoForex quality programs in training, engi-neering and field operations.

Changing the Training Focus

“Think of change as skill-building and con-centrate on training as part of the changeprocess.” 14

Thanks to new technology and greater rigautomation, drilling today is less demandingphysically than a decade ago. But, it stillremains a dangerous business. This is whycomprehensive training has always receivedtop priority.15

Within Sedco Forex, four training centers(see “The French (Training) Connection,”page 34) provide formal courses for newand experienced personnel. A follow-upsystem ensures proper application of newskills. Roving instructors visit rigs and checkfor safe work practices. Each rig has safetycommittees that set standards, hold regularinformation and problem-solving meetings,and track compliance. Data bases havebeen developed and are constantly updatedto communicate risk information and profilecritical risk areas. Health and safety cam-paigns are mounted to target areas whereimprovement is needed. Initiatives, like theDupont STOP program, a systematicapproach to recognizing potential problemsand addressing them before they turn intoincidents, provide quality focal points for rigpersonnel.

Within the training effort, benchmarkinghas been critical. Monthly measurements ofcompliance in areas such as HSE and well-control training, providing feedback, anddeveloping action plans to rectify deficien-cies have been at the heart of the program.

Without a focused training effort in qualityfrom the top to the bottom of the organiza-tion, there can be no change toward a qual-ity culture. To this end, two initiatives have

helped instill the quality mentality. WithinSedco Forex, training had historically beentechnical and geared to career developmentneeds for engineers, rig supervisors and rigworkers. This formed the basis for loss con-trol and service quality instruction. As thequality thrust gained momentum, however,it became apparent that training had to bebroadened and, at the same time, moresharply focused.

The first initiative was a shift to a compe-tency-based approach—where assessmentand measurement of proficiency levels anda step-by-step methodology to correct noteddeficiencies was implemented and trackedfor compliance. In essence, this transformedthe training function directly into a totalquality support function.

The second initiative focused on commu-nicating the quality goals of the companythrough the development and applicationof a training matrix for line management(next page). In all facets of this initiative,the ultimate clients of the program—bothemployees and customers—were consultedon scope and content. In some instances,training tools and courses were identifiedand added to fill gaps.

To deliver the message, a train-the-trainermethodology was employed. Supportingmaterials were prepared and presented tomanagement via a Quality Awareness course.Supervisors, in turn, were given the trainingnecessary, as well as a comprehensive presen-tation package, to transmit the quality mes-sage throughout their organizations.

In training and follow-up, the emphasishas evolved from strictly technical trainingto a broader view: how to better manage,how to better recognize problems andissues, how to empower and facilitate, andhow to communicate. At the same time,training became more focused—focused onquality as the end goal.

Reengineering Engineering

“There is absolutely no reason for havingerrors or defects in any product or service.” 16

While some aspects of drilling operationshave changed little over the past 50 years,technological advances, such as top drives,improved downhole motors, and logging-and measurements-while-drilling tech-niques, have had a pronounced influence onefficiency and cost. Ensuring rapid and effec-tive development of new technology and itstransfer to the rigsite requires a qualityapproach within the engineering organiza-tion of the drilling contractor.

Oilfield Review

nManagement training matrix. The matrix outlines priority courses and essential supple-mental programs for training rig personnel and regional management in quality, provid-ing instruction on improving supervision, problem identification and communications.

14. Deal T and Kennedy A: Corporate Cultures. Read-ing, Massachusetts, USA: Addison-Wesley, 1982.

15. Burt GL and Stibbs W: “Personnel Development in the 1990s: Preparing the Next Generation RigProfessionals,” paper SPE 23156, presented at theOffshore Europe Conference, Aberdeen, Scotland,

1 Priority 1: High priority training and highly recommended2 Priority 2: Lower priority training but also recommended

as needed Where either the job or the development plan indicates the needBEST Better Exempt Schlumberger Training

Courses run by Sedco Forex•Courses shared with sister Schlumberger companies•Outside courses

Rigsupervisors

Rig super-intendents

Rigengineers

Staffengineers

Rig managers

Districtmanagers

Projectmanagers

BEST 1 2

Management 1 1 2 1Communication skills 2 1 1 1Train the trainer 1 2IT module 1 1 1 1 2

TQM awareness 1 2 1 1Management 2 2 1Sales training 1 as needed 1 1Sales training 2 2 1BEST 3 - Finance 1Financial analysis as needed 1BEST 3 - Project mgt as needed 2 2 2

Bidding workshop 2Advanced mkt seminar as neededAdvanced mgt seminar 2

Presentation skills as needed as needed as needed as needed as neededRecruiting skills as needed as needed as needed as needed as needed

For Sedco Forex, the engineering depart-ment is one of the sites that has achievedISO recognition. But here the approach wasinitially directed at analyzing existing prac-tices and developing innovative approachesto improve the quality and deliverability ofnew products and techniques. The goal wasto have a practical, workable system inplace, rather than to achieve ISO certifica-tion. However, in the drive to set up a qual-ity system, ISO became viewed as the mosteffective means to this end. Certificationwas a natural outcome of the process.

Examples, ranging from electronic docu-mentation to improved field support andshipyard construction and repair, highlighthow recently introduced products and proce-dures are helping achieve more for the client.

If you’ve ever been on a drilling rig,you’ve seen the overwhelming number ofprinted technical and procedural manualsneeded to support day-to-day operations.One engineering project focused on replac-ing these bulky, hard-copy manuals withelectronic documentation on CD-ROM—saving storage space and streamlining themassive effort to keep them updated.

Spring 1996

September 3-6, 1991.

The first corporate documentation CD-ROM was sent to all rigs in December 1995after pilot testing in four field locations inthe Middle East and Far East. Each rig hasbeen equipped with CD-ROM readers. Asingle CD contains 11 operations, Q-HSEand training manuals; 20 marine operationsmanuals; maintenance policies and proce-dures; and other location- and discipline-specific documents, for a total of 1664 files.Documents are linked; searches by keyword and topic can be conducted; and avariety of navigation tools make finding keyinformation straightforward and efficient.The contents of the CD will be updated andexpanded regularly.

This approach to documentation ensuresaccess to the most current information andimproves the productivity and efficiency ofrig workers by providing the data theyrequire to perform their jobs, thus reducingerrors, downtime and losses.

A second area of quality improvement hasbeen in field support. Historically, when aproblem arose on a rig, an engineer wouldask for help from a contact in the engineer-ing department. There were many potentialpitfalls with this approach: the person might

not be the right one to contact; descriptionsof the problem might be incorrect or incom-plete; similarly, the recommended solutionmight be incorrect or incomplete; or, finally,no action might be taken—the request sim-ply being ignored.

To correct these deficiencies, new proce-dures were established, including a com-plete set of specifications and communica-tion channels known as the Request forEngineering Action (REA) system. Whenhelp is needed, rig personnel describe thenature of the problem to the regional organi-zation. The region then relays the request toan engineering point contact who deter-mines the expert or group of experts bestequipped to answer the question. If theproblem can be solved faster and more effi-ciently outside the engineering organization,for example by using a consultant, the pointcontact will funnel the project accordingly.

Since at any one time there might be 60to 80 such requests in process, priority set-ting is important, particularly with costlydrilling times at stake. The REA systemallows much tighter control over prioritiesand assignment of the proper sense ofurgency—all features lacking in the previ-ous system. The region and rig are both keptinformed of progress toward, and the dead-line for, a solution.

With the checks and balances involved,how rapidly are results delivered? The for-malized procedures bypass many of the pre-vious pinch points, and deliverability is asgood or better. The key benefit is enhancedquality management of the solutions.

The quality system is also reaping benefitsin shipyard construction and repair. Typi-cally, shipyard activities were treated asone-off projects. Each time a new projectcame along, there was a tendency to rein-vent the wheel. Today, a retrievable database captures project information, allowingprior experience to be drawn on. Also, thereis a formalized approach to project manage-ment and coordination, as well as docu-ment control.

Task force managers are appointed, andthe scope of work is defined up-front. Newcommunication channels facilitate earlyexchange of ideas. Staff and facilities benefitfrom better organization, which specifies

(continued on page 33)

31

16. Crosby, reference 1: 58.

The Road to ISO Certification

nThe Jacintoport distribution center. The facility was the first within Sedco Forex, and the first of its type any-where in the USA, to receive ISO 9002 certification.

nJacintoport management staff. Materials managerEllis Duncan (left) and quality manager Ira Gervaisassure that the ISO policies are properly imple-mented and tracked.

In today’s marketplace, identifying and under-

standing a customer’s requirements and meeting

those needs are critical for maintaining a com-

petitive advantage and serve as underlying fac-

tors in the movement toward total quality man-

agement and implementation of quality systems.

An effective system is one that has commitment

to quality and continuous improvement at all lev-

els of the company. Learning from mistakes and

ensuring that problems do not recur are accom-

plished through problem identification (auditing),

investigation (corrective action) and long-term

rectification (controlled procedural change).

Sedco Forex prides itself on being close to its

clients and providing innovative approaches to

better meet their needs and reduce costs in

drilling operations. Following the general move-

ment of many businesses to comply with ISO

9000 standards and the specific desires of sev-

eral customers to deal with ISO 9000-certified

vendors and service providers, certain Sedco

Forex facilities have sought and achieved ISO

9000 certification.

In particular, in 1993, the Materials Logistics

Center (International Chandlers, Jacintoport

Facility) in Channelview, Texas, USA, outside of

Houston, was the first within Sedco Forex, and

the first distribution center of any kind in the

USA, to achieve ISO 9000 certification (above

right). Specifically, the center has been certified

by Det Norske Veritas (DNV), the foremost certify-

ing body, to conform to ISO 9002 quality system

standards for “procurement and logistic services

for oilfield equipment, spare parts, and consum-

ables.” As the procurement center for the pur-

chase and resupply of critical parts and materials

for Sedco Forex rigs operating worldwide, this

group plays a central role in minimizing drilling

rig downtime. Rig time lost by errors in procuring

or shipping replacement parts can significantly

impact operational efficiency, profits, customer

relations and company image.

The motivating factors behind the effort to seek

ISO certification were threefold. “We felt that we

32 Oilfield Review

could create a good quality system for our opera-

tion,” says Ellis Duncan, Materials Manager at

the Jacintoport facility, that it “would be advanta-

geous to our clients,“and that it would also”sat-

isfy the needs of our North Sea operation” (right).

On the first point, Ira Gervais, Jacintoport Quality

Manager, points out that ISO certification is the

facility’s first effort in developing a quality sys-

tem. “We thought we were doing great,” he com-

ments, but he also notes that there was no mech-

anism to identify what they were doing wrong

when problems did arise. Discussing the advan-

tages to their clients, Duncan says, “We wanted

to be sure that if there was any question concern-

ing the quality of our fleet in the North Sea, we

could say that we are buying from suppliers

through an ISO quality system.” Regarding the

last factor, Duncan says that the need to stay

competitive played a major role in the decision to

seek ISO certification. “Major clients started

pushing this in the North Sea.”

Although the Channelview facility went into ISO

certification as a trial, taking a wait-and-see atti-

tude, the experience and positive results paved

the way for subsequent ISO certification of other

Sedco Forex locations.

It’s difficult to compute exact dollars saved due

to improvements resulting from the ISO-related

changes. “How do you put a figure on acciden-

tally purchasing the wrong part or an inferior

product, or sending a part to the wrong place or

Spring 1996

1. Patterson JG: ISO 9000 Worldwide Quality Standard: Criteria for Documentation and Performance. Menlo Park,California, USA: Crisp Publications, 1995.

quality criteria for the shipyard, includingtesting and reporting procedures anddetailed financial controls. ISO guidelineshelp to plug the holes and impose a sched-ule for fixing problems. In this example, asin others, it’s often a few simple improve-ments that together produce a significantincrease in quality.

Service Quality at the Wellsite

“Think where your company could be ifyou completely eliminated failure costs.” 17

Closing the feedback loop with the oiland gas operator is one key to ensuring aclimate of continuous improvement. To aidin this goal, Sedco Forex implemented aService Quality Appraisal (SQA) systemthree years ago. The system is based on acomprehensive set of guidelines. The firstlevel, the SQA form, is filled out by theclient (below). It provides a quantitativeassessment of how the rig and its personnelstack up in several categories, includingHSE, overall drilling performance, organiza-tion and skills of the personnel, conditionand utility of the equipment, and quality ofrigsite communications. The bottom line isan overall performance rating, or index,with a maximum score of 100%.

The SQA covers a particular time periodand is used by the rig manager to assess theoperation and for discussion with clients inquarterly meetings. These sessions reviewthe strengths and deficiencies of the service

nService quality appraisal form. The SQAgives quantitative measures of the perfor-mance of rig and personnel in several cate-gories, summarized by an overall rating.

17. Crosby, reference 1: 48.

the wrong rig, and ending up having to repur-

chase or reship a product,” Gervais points out.

ISO 9002 uses the combination of internal

audits and periodic audits by an external organi-

zation to review procedures, documentation and

corrective actions in purchasing, contracts, pur-

chaser-supplier product control and process con-

trol.1 DNV, the auditing body for the Jacintoport

facility, focuses on one of these areas during its

semi-annual audits. The DNV auditors review

paperwork to verify that the documented proce-

dures are being followed and make spot checks

of portions of the operation. “For example,” Ger-

vais says, “to avoid mistakes in shipping, we

must specify how we handle noncompliant prod-

ucts when they come in. If they can’t be identi-

fied, we place them in a special location, prop-

erly tagged. DNV checks that on a regular basis.

If something does goes wrong, we must specify

how we will correct the problem and isolate the

nonconforming material in the future.” A full

recertification is performed every three

years—with the next due in 1996 for the Jacinto-

port facility.

The quality manual, containing the documenta-

tion of procedures required for ISO certification,

must describe what’s actually done in the busi-

ness process, while at the same time not be

overly burdensome to employees. The liberal use

of flow charts and organizational charts has kept

the Channelview quality manual to a concise and

readable 35 pages, in comparison to other com-

panies where such manuals may be several vol-

umes in length. According to Gervais, “A side

benefit of having all procedures documented in a

manual is that new employees now have a refer-

ence and learn the proper procedures from the

onset.” The quality manual must be updated, and

all employees must have access to the most cur-

rent version. Depending on the size of a facility,

maintaining and updating documentation can be

complicated and cumbersome. In this area, the

Channelview group has taken an innovative

approach: their manual is accessible to employ-

ees through the Sedco Forex home page on the

World Wide Web. “What we've done is put the

current copy on our network,” says Gervais. “It's

the official copy for downloading and printing.”

Duncan indicates that the primary benefits of

ISO certification for the Jacintoport facility are

awareness, discipline and accountability. These

are derived from the ISO 9000 requirements for

establishing formal procedures for recognizing

and handling problems, both internally and in the

field, for accurate documentation and control of

that documentation, and for taking corrective

action. He says that prior to ISO certification,

“There were no established procedures for mak-

ing sure things were actually handled correctly.

Now, when the field has any type of problem with

something we handled, they fill out a procure-

ment incident report and send it to us, and we

have to correct it.” One example involved

changes in receiving and packing procedures to

address complaints that supplies were arriving in

the field wet or damaged. To ensure accountabil-

ity and corrective action, the Jacintoport facility

now sends out a semi-annual service quality

analysis questionnaire to the field to learn how

customers feel about their service. Documenta-

tion produced by this communication must be

addressed and acted on; problems cannot be

ignored. “Without a doubt, a key area is speed”

says Duncan. “They want us to react quicker. We

weren’t as accountable before. But you are with

this system. It’s all documented. It’s all there. It’s

all auditable.”

Since ISO certification, Jacintoport has

received additional business from sister compa-

nies like Dowell for procuring, packing and ship-

ping goods to the field. These companies could

use anyone, but, Gervais says, ISO certification

has allowed the Jacintoport facility to improve its

systems and to demonstrate that “we’re very pro-

fessional in what we do” and that mechanisms

for redressing complaints are in place.— SP

33

The SQA provides the basis for regular meet-ings with clients on quality improvement.

34 Oilfield Review

The French (Training) Connection

nThe training rig. At the Pau training center, thisdiesel-electric land rig provides hands-on instructionfor new engineers and technicians during an inten-sive initiation course.

nWell-control trainingclass. At least every twoyears, each Sedco Forexdrilling crew must suc-cessfully complete a five-day course in well con-trol to be recertified tointernational standards.

The Pyrenees mountains form a spectacular

backdrop to the Sedco Forex training center in a

picturesque suburb of Pau, France. It is the

largest, best-equipped and busiest of the four

training centers the company operates world-

wide. Sister facilities are located in Aberdeen,

Scotland; Warri, Nigeria; and Singapore.

Today, with even greater emphasis on the

health and safety of employees, protection of the

environment, and quality, the center is fulfilling

an expanded role that reflects the Sedco Forex

commitment to training as a core element of the

company’s culture.

The Pau site was originally established in 1949

as a base for North African and European drilling

operations. Training courses were first conducted

in 1972 and, during the nearly two and a half

decades since, the training mandate has evolved

and the course list has grown considerably, in

line with the changing needs of the drilling indus-

try and the profile of the company’s workforce.

Today, the extensive complex includes 10,800

ft2 [1000 m2] of classrooms, workshops and office

buildings, supported by 80,700 ft2 [7500 m2] of

yard space. Eight instructors and support staff

provided 4400 man-days of training in the latest

drilling technology during 1995. For 1996, that

figure is expected to increase to 7000 man-days.

There are four principal classrooms, one

equipped with a state-of-the-art drilling simula-

tor. This simulator, used primarily for instruction

on well-control procedures, also models stuck

pipe situations and various techniques for drilling

optimization, and interfaces with an advanced

computer system that allows trainees to access,

and interact with, actual well data. Extensive

computer and video facilities in the classrooms

permit maximum use of new information technol-

ogy tools and multimedia training aids.

The site’s most striking feature is also its prin-

cipal piece of equipment—an ultraheavy, diesel-

electric land rig with a rated drilling depth of

18,000 ft [5500 m] and a 600-ton capacity mast

and substructure (above left). The size and capa-

bilities provide a training tool unique in Europe.

The rig is fully equipped with hoisting, rotating,

circulating and well-control systems. It is posi-

tioned over a 4400 ft [1350 m] cased well, with

casings ranging from conductor and surface

strings to 95/8 in. [25 cm] at total depth. The rig

and well combination permits realistic simulation

of a wide range of drilling conditions encountered

daily in field operations.

The rig is fitted with a high-pressure air com-

pression, storage and injection system. Air can

be introduced into the well through tubing run

outside the casing to simulate a gas influx (kick)

on a live well. Each Sedco Forex drilling crew

receives mandatory well-control training every

two years, carried out to the certification stan-

dards of the International Well Control Forum, an

organization representing operators, contractors

and drilling schools around the world. Sedco

Forex is a founding member of the group. The

crews must be able to resolve a variety of well-

control problems and successfully shut in and cir-

culate out gas kicks to pass the course and be

recertified (left).

35Spring 1996

nService QualityIndex (SQI). The SQIshows the overallrating achieved for aparticular rig. In thisexample, the indicesare for seven rigs forthe second quarterof 1995.

100

90

80

70

60

50

40

30

20

10

0

Overall averageperformance 82%

Highestscoring rig 93%

Lowestscoring rig 76%

Rig 1 Rig 2 Rig 3 Rig 4 Rig 5 Rig 6 Rig 7

Total possible score 180 180 180 168 180 176 180Actual score 152 137 136 154 167 135 138

Overall performance, % 84 76 76 92 93 77 77

Overall performance, %

18. Crosby, reference 1: 6.

nClosing the loopwith the client. TheSQA and specificfollow-up actionsassure the degreeand frequency offeedback neces-sary to keep theclient informed andfoster an environ-ment of joint prob-lem solving.

Performance review

Client perception SQA

Quality teams

Client forum

Closing theloop with

clients

being provided and define necessary correc-tive actions (top).

Recently, with input from clients, the formhas been updated to make it even moremeaningful in addressing client needs. Anewly introduced criterion that goes beyondjust performance ratings is client perceptionof service quality. For the future, both per-formance and perception will be givenequal attention in client reviews. Applica-tion of SQA procedures and adherence toprescribed follow-up actions have achievedthe objective of effectively closing the loopwith the client (above).

As specific examples pointed out at thebeginning of this article, the implementa-tion of a quality culture, programs on qual-ity in training and engineering, and theSQA system have translated into improvedperformance on the rig and better results forthe client.

The Journey is Only BeginningTo develop and thrive, a corporate qualityculture requires a never-ending journeyalong a route marked with road signs read-ing conviction, commitment and conver-sion. At times, the route is rough and wind-ing, but every step forward bringssubstantive benefits for both clients andemployees.

The words of Philip Crosby sum it upbest. “Quality is an achievable, measur-able, profitable entity that can be installedonce you have commitment and under-standing and are prepared for hard work.”18

—DEO

Today, induction training for newly recruited

drilling engineers and technicians, initiated in

1980, is the principal business of the training

center. In a 19-day course for engineers and a

10-day course for technicians, which combine

theory, classroom lectures, homework and practi-

cal exercises, the rig and well provide a con-

trolled environment for hands-on training in the

latest technology and operational techniques.

Knowledge and skills developed during the

course form the foundation necessary to ensure

that new recruits perform safely and effectively in

their first actual rig assignments.

A complete mechanical workshop maintains all

critical pieces of drilling gear and gives trainees

the opportunity to witness and participate in dis-

assembly and major overhauls of both surface

equipment and downhole tools during hands-on

training sessions.

In addition to new trainee induction and well-

control schools, the center schedules a variety of

other courses. These include drilling technology

courses, covering both the fundamentals of cas-

ing and cementing, directional drilling, drill bits,

drillstring design, hydraulics and solids control,

as well as advanced work on formation evalua-

tion and well design. In addition, there are

marine courses on the stability of offshore rigs

and procedures for moving and operating off-

shore rigs.

For many years, Sedco Forex has been a rec-

ognized industry leader in training field person-

nel. Never has this been more evident than today,

as reflected in the dedication shown by the train-

ing staff at Pau.

Getting to the Root of Gas Migration

Of the two principal objectives facing primary cementing operations—casing support and zonal isolation—

the latter usually raises the most concern, and is perhaps the hardest to achieve when there is potential for

formation gas to migrate into the cement sheath. The challenge for industry is to achieve a long-term annular

cement seal and prevent formation gas entry. Successful handling of gas migration is an evolving science.

This article looks at causes, consequences, predictive methods, new solutions and the latest state of play.

Art BonettCambridge, England

Demos PafitisSugar Land, Texas, USA

Five years ago, an article in Oilfield Reviewstated, “Understanding gas intrusion is anevolutionary process that has not yet run itsfull course.”1 Since then, the evolution hascontinued, providing a more detailed pic-ture of the downhole phenomena activeduring gas migration. Although many possi-ble solutions are similar to those available in1991, increased knowledge of gas entrymechanisms means that these solutions cannow be deployed in a more logical andcost-effective way.

Gas invasion occurs when pressure islower in the annulus than at the formationface. Gas then migrates either to a lowerpressure formation or to the surface. Theseverity of the problem may range fromresidual gas pressure of a few psi at thewellhead to a blowout. Whatever the sever-ity, the major factors contributing to gasmigration are common. Successfully achiev-ing a long-term annular cement seal beginsby understanding these contributing factors

36 Oilfield Review

For help in preparation of this article, thanks to ArtMilne, Dowell, Clamart, France and Tom Griffin, Dowell, Sugar Land, Texas.CemCADE, GASBLOK, GASRULE , VIP Mixer andWELLCLEAN are marks of Schlumberger. MicroVAX is atrademark of Digital Equipment Corp.

1. Bol G, Grant H, Keller S, Marcassa F and de RozieresJ: “Putting a Stop to Gas Channeling,” Oilfield Review3, no. 2 (April 1991): 35-43.

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

3. Cement free-fall or U-tubing occurs when the weightof the slurry causes it to fall faster than it is beingpumped. This must be considered when designing

Wrong density Poor mud/filter-cake removal Premature gelation Excessive fluid loss

Highly permeable slurry High shrinkage Cement failure under stress Poor interfacial bonding

nMajor contributing parameters during the cementing process, in the order that they typically occur. Incorrectcement densities can result in hydrostatic imbalance. Poor mud and filter-cake removal leaves a route for gasto flow up the annulus. Premature gelation leads to loss of hydrostatic pressure control. Excessive fluid loss con-tributes to available space in the cement slurry column for gas to enter. Highly permeable slurries result inpoor zonal isolation and offer little resistance to gas flow. High cement shrinkage leads to increased porosityand stresses in the cement sheath that may cause a microannulus to form. Cement failure under stress helpsgas fracture cement sheaths. Poor bonding can cause failure at cement-casing or cement-formation interfaces.

and knowing what can be done to minimizeor counteract their effects.

In the past, various techniques have beendeveloped to tackle individual factors thatcontribute to gas migration. However, gasmigration is caused by numerous relatedfactors. Only by addressing each factor sys-tematically can a reasonable degree of suc-cess be expected. There is no single “magicbullet” for gas migration.

This article summarizes the current stateof knowledge about gas migration, drawingon field expertise from Dowell, and onexperimental work carried out predomi-nantly at Schlumberger Cambridge Research(SCR) in England. Much of this experimentalwork is unpublished.

Setting the SceneSuccessfully cementing a well that haspotential for gas migration involves a widerange of parameters: fluid density, mudremoval strategy, cement slurry design(including fluid-loss control and slurry freewater), cement hydration processes,cement-casing-formation bonding and setcement mechanical properties (above).

Spring 1996

displacement rates and pumping schedules.

Although gas may enter the annulus by anumber of distinct mechanisms, the prereq-uisites for gas entry are similar. There mustbe a driving force to initiate the flow of gas,and space within the cemented annulus forthe gas to occupy. The driving force comeswhen pressure in the annulus adjacent to agas zone falls below the formation gas pres-sure. Space for the gas to occupy may bewithin the cement medium or adjacent to it.

To understand how, and under what cir-cumstances, gas entry occurs, a review ofthe main mechanisms, including cementhydration and resultant pressure decline,follows. First, however, no cementing articleis complete without emphasizing that goodcementing practices are vital.2 To effectivelycement gas-bearing formations the centralpillars of good practice—density control,mud removal and slurry design—are criti-cal, and here is why.

Density: Controlling the driving force—Gas can invade and migrate within thecement sheath only if formation pressure ishigher than hydrostatic pressure at the bore-hole wall. Therefore, as a primary require-ment, slurry density must be correctlydesigned to prevent gas flow during cementplacement. However, there is a danger oflosing circulation or fracturing an interval if

fluid densities are too high. Also, considera-tion must be given to the free-fall or U-tub-ing phenomenon that occurs during cementjobs.3 Therefore, cement jobs should bedesigned using a placement computer simu-lator program to assure that the pressure atcritical zones remains between the pore andfracture pressures during and immediatelyafter the cement job.

Any density errors made while mixing aslurry on surface may induce large changesin critical slurry properties, such as rheologyand setting time. Inconsistent mixing alsoresults in placement of a nonuniform col-umn of cement in the annulus that may leadto solids settling, free-water development orpremature bridging in some parts of theannulus. This is why modern, process-con-trolled mixing systems that offer accurate

37

0 bar 300 0 sgu 3 00

m3L/min

95950

Time

hh:mm:ss

07:12:00

06:18:00

05:24:00

04:30:00

End displacementBump top plugBleed off pressure

End cement slurryStart displacement

End spacerStart cement slurry

Start pumping spacerPressure test lines

Pressure Fluid Density Tot. FlowrateCumVolume Messages

nProcess-controlledmixing. The VIPMixer delivershighly consistentcement slurries(top). The comput-erized log showsconsistent slurrydensity throughoutthe job (bottom).

38

density control are proving popular for criti-cal cement operations (left).

A cement slurry will not transmit hydro-static pressure forever. The transition from aliquid that controls formation pressure to animpermeable solid is not instantaneous. Con-sequently, there is a period during whichcement loses the ability to transmit pressure.No matter how carefully a slurry has beendesigned to counterbalance formation pres-sure, it will not necessarily resist gas invasionthroughout the hydration process.

Mud removal: No easy paths for gas—Ifchannels of mud remain in the annulus, thelower yield stresses of drilling fluids mayoffer a preferential route for gas migration.Furthermore, water may be drawn from themud channels when they come into contactwith cement. This can lead to shrinkage-induced cracking of the mud, which alsoprovides a route for gas to flow. If the mudfilter cake dehydrates after the cement sets,an annulus may form at the formation-cement interface, thus providing anotherpath for gas to migrate. For example, a 2 mm[0.08 in.] thick mud filter cake contractingby 5% will leave a void 0.1 mm [0.004 in.]wide that has a “permeability” on the orderof several darcies.

Cement slurry design: Mixing the rightstuff—Fluid-loss control is essential. Understatic conditions following placement,uncontrolled fluid loss from the cementslurry into the formation contributes to vol-ume reduction. This reduces pressurewithin the cement column and allowsspace for gas to enter.

Before the cement slurry sets, interstitialwater is mobile. Therefore, some degree offluid loss always occurs when the annularhydrostatic pressure exceeds the formationpressure. The process slows when a low-per-meability filter cake forms against the forma-tion wall, or can stop altogether when annu-lar and formation pressures equilibrate.Once equilibrium is reached, any volumechange within the cement will cause a sharppore-pressure decline in the cement slurry orthe developing matrix, and severe gas influxmay be induced. Poor fluid-loss control infront of a gas-bearing zone may acceleratethe decrease in cement pore pressure. It isequally important to have a cement slurrywith low or zero free water, particularly indeviated wells. As cement particles settle tothe low side, a continuous water channelmay be formed on the upper side of thehole, creating a path for gas migration.

Oilfield Review

4. Parcevaux PA and Sault PH: “Cement Shrinkage andElasticity: A New Approach for a Good Zonal Isola-tion,” paper SPE 13176, presented at the 59th SPEAnnual Technical Conference and Exhibition, Hous-ton, Texas, USA, September 16-19, 1984.

5. Beris AN, Tsamopoulos JA, Armstrong RC and BrownRA: “Creeping Motion of a Sphere Through a Bing-ham Plastic,” Journal of Fluid Mechanics 158(September 1985): 219-244.

6. Geometry separates fingering and viscoelastic frac-tures. A fracture has a sharp tip; a finger has a smooth

nGas migration in aviscoelastic fluid.Gas may flowthrough cement in anumber of differentways in addition tobubble flow. It canrise in the form of an elongated slug—seen in experimentscarried out atSchlumberger Cambridge Researchin England—aschannels alongcement-formationand cement-casinginterfaces, or as a rising plume—where a nearlyspherical chamber is linked to the formation by a narrow umbilicalconduit.

Rising plumeInterface flowSlug flowBubble flow

How Gas Gets into the AnnulusUnderstanding the mechanisms of gasmigration is complicated by the evolution ofthe annular cement column with time. Theslurry begins as a dense, granular suspen-sion that fully transmits hydrostatic pressure.As the slurry gels, a two-phase materialcomprised of a solid network with pore fluidforms. Finally, the setting process reaches apoint where the cement is for all intents andpurposes an impermeable solid. After slurryplacement, gas may enter through differentmechanisms according to the evolution ofthe cement’s state, the pressures it experi-ences and other wellbore factors.

Cement state 1: Dense granular fluid—When pumping stops, the cement slurry inthe annulus is a dense, granular fluid thattransmits full hydrostatic pressure. If forma-tion pore pressure is not greater than thishydrostatic pressure, gas cannot invade.However, almost immediately, pressurewithin the annulus begins to fall because ofa combination of gelation, fluid loss andbulk shrinkage.

This pressure reduction is best describedby the evolution of a wall shear stress (WSS)that begins to support the annular columnas the cement slurry gels. In order for astress to evolve to counteract the hydrostaticpressure, there must be a vertical or axialstrain at the annulus walls. This strain iscaused by the removal of material duringthe hydration and setting processes—pri-marily through fluid loss and shrinkage.

If it is assumed that WSS equals the staticgel strength (SGS) of the slurry and there issufficient axial strain, the following simplifiedexpression can be used to describe hydro-static pressure reduction during gelation:

where ∆P = hydrostatic pressure change across column length

SGS = static gel strength Dh = hole diameterDc = casing outside diameter (OD)L = cement column length.

As the cement sets, static gel strength con-stantly increases, with the rate of increasedependent on the nature of the slurry. Thereis potential for gas invasion once pressure inthe annulus falls below the pressure in thegas-bearing formation. Even with a mud fil-ter cake between the formation and cement,a differential pressure of less than 1 psi may

∆P = SGS 4LDh - Dc

Spring 1996

tip. This difference is determined by a fractal lengthscale that is associated with the fracture or fingergeometry.

allow gas to invade. The resistance of anexternal filter cake to gas flow is controlledby the cake’s strength and adhesion to therock face, which both have relatively lowvalues for drilling fluids and neat cements.

This explains the driving force of gas inva-sion, however, there must also be spacewithin the cemented annulus for gas tooccupy. Space is provided by shrinkage,which occurs because the volume of thehydrated phase is generally less than that ofthe initial reactants. This total shrinkage issplit between a bulk or external volumetricshrinkage, less than 1%, and a matrix inter-nal contraction representing 4 to 6% by vol-ume of cement slurry.4

Permeability is a more complicated issue.Once gelation begins, a cement slurry canbe considered as a pseudoporous mediumas long as the stress that it must withstandfrom formation fluid is less than its intrinsicstrength. Thus, even though only a partialstructure has been formed and the cementcolumn is not yet fully self-supporting, withregard to its flow capacities, it can be said tohave permeability.

Cement slurries display an evolving yieldstress that must be overcome before gasentry and flow can occur. Depending on thestate of the slurry, gas can migrate bymicropercolation, bubbles or fractures.Opportunity for gas entry decreases as thecement cures. The rate and degree of yieldstress development at the time of invasionwill influence the form in which gas flows.Gas may enter and flow through the poros-ity of the gelling structure without disruptingit—micropercolation. Gas may also move

by disrupting the gel structure in the form ofbubbles or elongated slugs, in channelsalong the interfaces with the casing and for-mation or as bubbles which adhere to oneof the surfaces of the annulus. If rising gasremains connected to the influx source itmay form a plume as it moves through thecement slurry (above).

The size of gas bubbles entering the annu-lus is governed by the size of the cementpore throats and the surface tensionbetween the gas and the slurry. Once bub-bles have invaded the annulus, their lowerdensity provides a driving force—buoy-ancy—for them to move up the annulusthrough any available path. Bubble flow iscontrolled by slurry gel strength, and isrestricted to early in slurry development.When cement shear strength is greater thanabout 25 Pa, bubble flow ceases.5

At higher yield stress values, slurry behav-ior changes from that of a viscous fluid to aviscoelastic fluid, and the possibility of flowby viscous fingering or viscoelastic fracturesarises.6 The differential pressure—between

39

Degree of hydration, %

Frac

tion

of c

onn

ecte

d p

ore

s, %

0 10 20 30 40 50 60 70 80 90 1000

20

40

60

100

80

nConnected pores versus hydration of a 0.45 water-to-cement ratio slurry. From this curve, the degree of hydrationneeded to achieve capillary pore discontinuity for cementpaste can be calculated. In this case, it was found that asolids fraction of about 82% was required for discontinuity.A solids fraction of this level is typically not achieved untilwell after the cement has solidified. Hence, at most stagesof setting, some connected paths remain within the porespace. [After Bentz PB and Garboczi EJ: “Percolation of Phases ina Three-Dimensional Cement Microstructural Model,” Cementand Concrete Research 21 (1991):325-344.]

40 Oilfield Review

annulus and formation—combines with thedeveloping elasticity of the cement to deter-mine the rates of deformation and internalrelaxation. The relative values of thesedetermine the transition from fingering tofracture.7 The transition to fracture is exacer-bated if the cemented annulus contains aninternal tensile stress caused by the strain ofshrinkage, fluid loss or pressure fluctuationsin the casing. Gas may then drive the propa-gation of fractures and lead to a rapidlyextending gas channel. Hydrostatic pressurewill continue to decline as static gelstrength—and resultant wall shearstress—develop sufficiently to support theweight of the cement column. The cementhas now reached its second state.

Cement state 2: A two-phase material—Once a cement column becomes fully self-

supporting, it may be considered to act as amatrix of interconnected solid particles con-taining a fluid phase. Setting continues andhydration accelerates. Pressure, now a porepressure, decreases further as cement hydra-tion consumes mix water. This leads to anabsolute volume reduction or shrinkage ofthe internal cement matrix by up to 6%.Furthermore, the majority of shrinkageoccurs at this stage, leading to tangentialtensile stresses in the annulus, which mayassist the initiation of fractures and disruptbonding between the cement and the casingor formation.

Internal shrinkage creates a secondaryporosity in the cement composed mainly ofconductive pores. At the same time, the vol-ume of water continuously decreases due tohydration, and its ability to move within the

pores is reduced by chemical and capillaryforces. Shrinkage and water reductionsharply decrease the hydrostatic pressurethat cement exerts on formations.

There are two essentially different mecha-nisms for gas invasion at this stage, depend-ing on the strength of the solid structure andthe ease with which pore fluid can be forcedthrough the cement pores by invading gas.Early in the setting process, while the cementstill has a weak solid structure, the possibilityof creating fingers or viscoelastic fracturesremains. Later, the solid network becomessufficiently stiff and strong to withstand thiseffect, and gas invasion and subsequent floware limited by the impermeability of the solidnetwork to pore fluids. Now, the flow of gasthrough a channel of connected, fluid-filledcement pores is limited by the flow of thatpore fluid as it is displaced through theporous structure and by the connectivity ofthe channel (left).

Once gas has invaded the porous struc-ture of the cement, it may rise due to buoy-ancy forces. Alternatively, if the invadinggas remains connected through the cementpore space to the gas-bearing formation, thehigher pressure in the formation may forcegas farther into the annulus. If gas pressureis higher than the minimum compressivestress in the cement and the permeability istoo low to allow significant flow, then thecement may fracture. However, this is likelyto occur only where residual tensile stressesin the annulus are sufficiently high to allowcracks to open under the influence of thegas pressure.

During the latter stages of this phase,there is a significant and rapid decrease inpore pressure as water is further consumedby hydration. If this occurs while the porestructure is still interconnected, gas mayinvade and flow rapidly through this porespace (next page). Gas flow may also dis-place fluid remaining in the pores and pre-vent complete hydration that would eventu-ally block pore spaces with reactionproducts.

Cement state 3: An elastic solid—Oncehydration is complete, cement becomes anelastic and brittle material that is isotropic,homogeneous and essentially impermeable.8In most cases, gas can no longer migratewithin the cement matrix and can flow onlythrough interfacial channels or where therehas been mechanical failure of the cement.

nChanges in slurrypermeability, porepressure and temperature versushydration time.These graphs showthat cement porestructure is still inter-connected whenpore pressure beginsto decrease rapidly.In this Dykerhoffclass G plus 1% cal-cium chloride slurry,pore pressure beginsto drop after about 5hours, just before thepeak temperature ofhydration is reached.When cement porepressure drops belowformation gas pres-sure, it is likely thatcement permeabilitywill still be in themillidarcy range,potentially allowingsignificant gas flowby micropercolation.

11

12

13

14

15

16

17

18

19

20

21

0 5 10 15 20 25

10-8

10-7

10-6

10-5

10-4

10-3

10-2

0 5 10 15 20 25

Slurry Permeability

Per

mea

bilit

y, d

arci

es

28

29

30

31

32

33

34

35

36

0 5 10 15 20 25

Slurry Pore Pressure

Por

e pr

essu

re, b

ar

Slurry Temperature

Slu

rry

tem

pera

ture

, °C

Time, hr

41Spring 1996

7. Lemaire E, Levitz P, Daccord G and Van Damme H:“From Viscous Fingering to Viscoelastic Fracturing in Colloidal Fluids,” Physical Review Letters 67(October 1991): 2009-2012.

8. A limited exception to this may occur in the case ofcement systems with high water-cement ratios,resulting in fairly high innate permeabilities (0.5 to 5 md). However, these are exceptional and not con-sidered significant among those cements generallyplaced when a potential gas migration problem isthought to exist.

9. Deformability is the reciprocal of elastic modulus.10. Parcevaux and Sault, reference 4.

Regardless of the cement system used, gascan still migrate at the cement-formation orcement-casing interfaces if a microannulusdevelops, or along paths of weakness wherethe bond strength is reduced. Both shearand hydraulic bond strengths vary as a func-tion of the same external parameters. Bondstrengths increase with effective mudremoval, and with water-wet rather than oil-wet surfaces.

Researchers at Schlumberger CambridgeResearch (SCR) have characterized thenature of hydraulic bonding by measuringshear bond stress and interfacial permeabil-ity. This work showed that lower chemicalshrinkage and higher cement deformabilitypromote better bonding.9 In addition, SCRresearchers found that bonding is not influ-enced by the cement’s compressivestrength.10

Although cement shrinkage leaves par-tially unbonded areas, it does not by itselflead to the development of a microannulus.Development of a true microannulus morelikely results from stress imbalances at theinterfaces due to: • thermal stresses—from cement hydration,

steam or cold fluid injection• hydraulic pressure stresses—caused by

fluid density changes in the casing, communication tests, casing pressuretests, squeeze pressure or stimulationtreatment pressures

• mechanical stresses—caused by drillpipeand other tubulars banging in the casing.The second potential conduit for gas in set

cement is the mechanical failure of thecement sheath due to propagation of radialfractures or cracks across the annulus. Thesecracks may be due to shrinkage-inducedstresses, thermal expansion and contractionof the casing, and pressure fluctuationswithin the casing.

Radial expansion at the cement-casinginterface, due to increased pressure in thecasing, creates a stress that compresses thecement radially and eventually induces ten-sile tangential stress in the cement. When

42 Oilfield Review

Cement

(Fully cracked)

Casing

Rock

Displacement

Cement

P

Tensilestress

(Partially cracked)

nCasing under pressure. Radial expan-sion at the cement-casing interface due toincreased pressure (P) in the casing dis-places the cement sheath creating stress.This stress compresses the cement radi-ally and eventually induces tensile tan-gential stress in the cement (top). As soonas the tangential stress reaches the tensilestrength of the cement—which may beclose to zero if there are also shrinkagecracks—a crack initiates at the casing-cement interface. This crack propagatesradially outwards and may eventuallyreach the cement-formation interface(bottom). If this occurs over a significantaxial distance, a channel is formedthrough which gas can flow.

n Mechanical barrier limitations. Exter-nal casing packers (ECPs) may fail to sealagainst some types of formation. Alterna-tively, the reduction in hydrostatic pres-sure due to the ECP may allow gas toenter the annulus, leaving the packer asthe only barrier to gas movement.

ExternalcasingpackerECP

Cement

Gas flowsaroundECP sealbecause ofincompetentformation

Annulus

More gasentersbecauseECP reduceshydrostaticpressure

11. Marlow RS: “Cement Bonding Characteristics in GasWells,” Journal of Petroleum Technology 41, no. 11(November 1989): 1146-1153.

this tangential stress reaches the tensilestrength of the cement—which may beclose to zero if shrinkage-induced cracksalready exist—a crack initiates at the casing-cement interface (below).

Cracks change the stress distribution inthe cement sheath. Once a crack is initi-ated, tangential stress in the cracked sectionis reduced to zero. Conversely, stress inadjacent uncracked cement eventuallyincreases because of stress redistribution.This process helps the crack propagate radi-ally outward and eventually reach thecement-formation interface. Stress is nowfully transferred to the cement-formationinterface. If this cracking occurs over a sig-nificant axial distance, a channel is formedthrough which gas can readily flow.

Long-term cement durability is importantif a well is to remain safe throughout its life-time. During its active life, a cementedannulus may be subjected to wide varia-tions of temperature and stress from pres-sure testing, workover operations and varia-tions in producing conditions.

However, field surveys on gas storagewells—which endure some of the mostextreme swings in conditions—determinedthat annular gas leakage occurs early, withinthe first few cyclic fluctuations in tempera-ture and pressure, rather than over a longperiod. This implies that leakage occurs dueto failure induced by static loads rather thanlong-term, low-cycle fatigue crack growth.Deeper and higher-pressure wells showedthe greatest tendency to leak.11

The propensity of a particular cement tocrack and for that crack to propagate hasoften been equated with compressivestrength. In fact, work carried out at SCRshows that a property termed toughnessdetermines the extent to which a cementslurry fractures under stress. Toughness isgenerally described in terms of the ability ofa material to resist the initiation and subse-quent propagation of a fracture. However,the situation is somewhat more complicated,since initiation and propagation of fracturesare controlled by physical phenomena thatdiffer, depending on the material’s structure(see “Compressive Strength Versus Tough-ness: A Brief Overview,” next page).

Using Theory to Define Best PracticeOver the years, a number of solutions to gasmigration have been proposed by the indus-try. Theoretical understanding helps toexplain how these solutions work—andtheir limitations.

Physical techniques—A number of physi-cal techniques are available to combat gasentry. Annular pressure can be applied atsurface to keep formation gas from entering,and external casing packers (ECPs) can beemployed to mechanically seal off the annu-lus at intervals and prevent gas migration.

Each of these techniques may sometimesbe valid, but well conditions often limit theirapplication. Annular pressure may berestricted by the risk of inducing lost circula-tion in weak zones and, once the cementstarts to set, surface pressure is not transmit-

ted to the formation. Alternatively, hole con-ditions and type of formation may not allowECPs to seal the annulus. Furthermore,reduction of hydrostatic pressure throughuse of ECPs may enable more gas to imme-diately enter the slurry than would havebeen the case without ECPs (above).

Impermeable cements—Gas migrationmay be prevented by reducing the matrixpermeability of cement systems during thecritical liquid-to-solid transition. There aretwo approaches to achieving this: stop fluidfrom moving through the pores or close offthe pores themselves.

The use of water-soluble polymers thatviscosify cement interstitial water andreduce permeability within setting cementfalls into the first category. Since at least apart of gas migration involves displacementof cement pore fluid, this viscosification canlimit gas mobility. Unfortunately, the pro-cess also tends to affect slurry rheology,making it more viscous and raising the dis-placement pressure. This method is alsousually limited to low-temperature applica-tions because efficiency of viscosifiersdecreases with temperature.

The second strategy of reducing thespaces in the cement matrix, preventingbubble entry and locking the fluids withinthe cement pore spaces, has proven morefertile. As a solid structure develops in set-ting cement, the smaller pore throats reduce

(continued on page 44)

1. The situation is somewhat more complicated, since initia-tion and propagation of fractures are controlled by physicalphenomena that differ depending on a material’s structure.

nCement behaviorunder compression. The load or stress atwhich complete failureoccurs defines the ulti-mate compressivestrength of a material.Toughness, on the otherhand, is an indication ofthe ability of a materialto deform and absorbenergy before fracturesinitiate and propagate.

43

Compressive Strength Versus Toughness:A Brief Overview

Microfracturesdevelop undertensile stress andresult in failure ifallowed to grow andcommunicate

Area indicates toughness

Compressivestrength

A’

Strain

Str

ess X Y

Strain

Str

ess

Homogeneouscement (X)

Cement withlatex (Y)

Compressivestrength

Cement

Compressive load

Failure

A

Displacement transducer

Three-Point Bend Test Equipment

Upper moving knife edge

Sample

Staticknifeedges

nThree-point bend test.This equipment isdesigned so that cementsamples always fail intension. Strain (displacement) and load(stress) are recordedusing computerized datarecording systems.

The compressive strength of a material describes

the stress at which a material fails when a com-

pressive load is applied (top right). When a com-

pressive load is applied to a sample of brittle,

elastic material such as cement, stress generally

increases linearly with strain (displacement) until

small microcracks and flaws in the sample begin

to grow.

This is a progressive mechanism and manifests

itself on the stress-strain plot by the change from

linear proportionality between stress and strain to

a softening section of the curve near the failure

point. Once the cracks coalesce and reach a criti-

cal size, the sample will fracture via a complicated

mechanism, which is determined by the boundary

stress conditions and geometry of the sample.

Compare this with a description of cement

toughness. Simplistically, toughness describes the

property of the material to resist the initiation and

propagation of a crack in a particular orientation.1

Fracture toughness is quantitatively defined as the

energy required to propagate a fracture of unit

width by unit length.

Without considering mathematical details, a

reasonable indication of toughness for similar

materials is given by the area (A) under the

stress-strain curve to the failure point. This area

varies according to the toughness of the material

being tested.

For example, consider two materials X and Y

that have the same compressive strength. The

material X has a much smaller strain to failure

than material Y, which contains latex. Therefore,

material Y can deform further and absorb more

energy before it fractures. Material Y is tougher

than material X.

Data like these were gathered at Schlumberger

Cambridge Research using three-point bend test

equipment (right). The cement sample is placed

on two lower static knife edges and the upper

moveable knife edge is moved downward until the

cement fails. The equipment is designed so that

the sample always fails in tension. Strain (dis-

placement) and load (stress) are recorded using

computerized data recording systems.

44 Oilfield Review

12. Appleby S and Wilson A: “Permeability and Suctionin Setting Cement,” Chemical Engineering Science51, no. 2 (1996): 251-267.

13. Rang CL: “Evaluation of Gas Flows in Cement,”paper SPE 16385, presented at the SPE CaliforniaRegional Meeting, Ventura, California, USA, April 8-10, 1987.

14. Stewart RB and Schouten FC: “Gas Invasion andMigration in Cemented Annuli: Causes and Cures,”paper SPE 14779, presented at the 1986 IADC/SPEDrilling Conference, Dallas, Texas, USA, February10-12, 1986.

nLatex particles incement slurry. After some struc-ture or compressivestrength develops,the primary latexgas-blockingmechanism ismatrix permeabil-ity reduction byplugging of porespaces betweencement grains.Because of itssmall size andlower density compared tocement particles,latex reducescement slurryporosity, improvesfluid-loss control,decreases relativepermeability towater and limitsgas migration.

the size of bubbles that enter, slowing theirsubsequent rise—even when the yield stressof the cement is relatively low.

Polymer latex additives are effective inresisting gas migration. A latex is an aque-ous dispersion of solid polymer particles,including surfactants and protective colloidsthat impart stability to the dispersion. In thepast, the gas-blocking mechanism of latexadditives was attributed to a capability toform films—when latex particles come incontact with a gas or when their concentra-tion exceeds a given threshold value, theycoalesce to form an impermeable polymerbarrier to gas.

However, new work has revealed thatlatex particles are also able to block gaswhen the cement slurry has developedsome structure or some compressivestrength. This demonstrates that the primaryeffect of latex particles is matrix permeabil-ity reduction by plugging spaces betweencement particles, rather than by the forma-

tion of an impermeable plastic film. Due toits smaller size and lower density comparedto cement particles, latex reduces cementslurry porosity, improves fluid-loss control,reduces relative permeability to water andlimits gas migration (above). Latex particlesreduce slurry porosity by 10 to 15%,depending on slurry density and composi-tion (see “A Robust System to Cement Gas-Bearing Formations,” next page).12 Latexadditives also affect the properties of thecement when it is set (see Tough cements,page 46).

The addition of other types of fine fillerswith particle size in the micron range maydecrease permeability throughout the rapidhydration stage by quickly decreasing porecontinuity. For example, if 30% by weightof these fine particles is added to a slurrywith a water-cement ratio of 0.45, the poresbecome discontinuous about 30% morequickly. In addition to latex additives, silicafume and microsilica have been used suc-cessfully in the field.

Right-angle-set cements—Right-angle-set(RAS) cement slurries are well-dispersed

systems that show no progressive gelationtendency, yet set rapidly. Before setting, RASsystems maintain a full hydrostatic head ongas zones, developing a low-permeabilitymatrix with sufficient speed to prevent sig-nificant gas migration.

It is important to differentiate betweentrue RAS systems and cement slurries thatonly build a gel strength. The high-gel-strength systems quickly revert to a waterhydrostatic gradient and, since their gelstrength development is not related to actualsetting, permeability can remain high for aconsiderable time. This may allow gas toenter the cement matrix many hours beforethe cement sets. On the other hand, RAScement systems rapidly build consistency asa direct result of the setting process.13

Surfactants—Surfactants may be includedin cement slurries and preflushes. Under theright circumstances, they entrain invadinggas downhole and create a stable foam. Thisfoam offers significant resistance to flow,limiting upward gas migration.14

Compressible cements—Compressiblecements are sometimes used in an attemptto maintain the cement pore pressure aboveformation gas pressure. These slurries fallinto two main categories: foamed cementsand in-situ gas generators.

Foamed cements work by expanding tooccupy the reduction in slurry volume dueto fluid loss or chemical contraction. This

(continued on page 46)

10-2

10-4

10-5

10-6

10-7

Per

mea

bilit

y, d

arci

es

Time from hydration peak, hr

20 30 40 50

Neat Class G Cement slurry

GASBLOK slurry

nComparison of cement permeabilities. The GASBLOKslurry retains lower permeability throughout the hydra-tion process. Compared to a neat cement slurry, afterabout 40 hours of hydration, it has permeability that isan order of magnitude lower.

A Robust System to Cement Gas-Bearing Formations

The “ideal” slurry properties required to success-

fully withstand gas invasion include:

• favorable rheology to facilitate

efficient placement

• no gel strength development to maintain

hydrostatic balance

• rapid transition to set

• low shrinkage to minimize gas entry

• low fluid loss

• low permeability as the slurry sets

• toughness to absorb stress changes

• good bonding to avoid microannuli.

The Dowell GASBLOK gas migration control

cement system combines specific additives and

strict adherence to good cementing practices,

including spacers and washes, and casing central-

ization. It has a wide range of applications and has

had excellent success. The system is based on

using a well-dispersed, thin, nongelling slurry

with fluid-loss control. The slurry is also imperme-

able to gas in the cement matrix due to plugging of

pore throats during the setting period (above).

In addition to reducing permeability in the pres-

ence of gas, GASBLOK slurries exhibit many other

desirable properties. The main advantages are

ease of design and consistent properties over a

wide range of temperatures.

The lubricating action of the aqueous dispersion

of the latex beads creates low-viscosity slurries.

These thin slurries are beneficial for effective mud

Spring 1996

removal, since the friction pressure during place-

ment is reduced and the critical rate for turbulent

flow will be lower. If turbulent flow cannot be

achieved and an effective laminar regime is

chosen, it is necessary to increase the value of the

rheological parameters to satisfy WELLCLEAN

mud removal service criteria. Viscosification of a

GASBLOK slurry is easily achieved.

Fluid loss is minimal—50 ml/30 min at the rec-

ommended latex concentration—due to the plug-

ging of pore throats in the cement filter cake by

latex particles and improved dispersion of cement

grains. Setting and thickening times are straight-

forward and slurries exhibit rapid sets. There is

no premature gelation of the slurry when the

GASBLOK additive is well stabilized. The slurry

remains thin until final setting. The criterion

used is that the slurry should remain below

30 units of consistency for at least 70% of the

thickening time. Above 250°F [121°C] bottomhole

circulating temperature, a right-angle set should

be easily obtained.

The tendencies for free-water development and

settling of GASBLOK slurries are minimal. The for-

mation of water channels or pockets (especially in

deviated wells) is therefore greatly reduced and

slurry density variations, with resulting changes in

slurry properties, are avoided.

Once set, a cement must also possess good

mechanical properties to withstand thermal and

mechanical stresses. Poor shear bond strength

may lead to formation of microannuli through

which gas can migrate. GASBLOK slurries display

increased tensile strength, reduced drying shrink-

age, increased fracture toughness and improved

adhesion or bond strength. Dowell latex slurries

demonstrate all of the necessary properties to

keep gas at bay. In certain cases, other cement

systems used together with proper placement

techniques have been as successful as, or even

better than, latex in achieving particular individual

properties, but none demonstrate the same

complete range of desirable properties as the

GASBLOK slurries.

45

expansion maintains a higher pore pressurein the slurry for longer than would havebeen the case with incompressible slurries.Foamed cement may be limited by depthbecause in deeper, higher pressure wellsmore gas is needed than is available in thecement to compensate for the chemicalcontraction.

In-situ gas generators are designed tomaintain cement pore pressure by chemicalreactions that produce gas downhole. Thegas produced may be hydrogen or nitrogendepending upon the technique used.15

The principal criticism of these sys-tems—other than concerns about the safetyof those that generate hydrogen—is theinability of a gas at typical downhole pres-sure to achieve the 4 to 6% volumetricexpansion necessary to maintain pore pres-sure. The volume of gas required to offsetchemical shrinkage alone would be exces-sive at high pressure. Also, in unstabilizedgas-generating systems, individual gas bub-bles may coalesce and begin migrating, cre-ating channels for formation gas to follow.

Expansive cements—Fractures occur ingelled cement according to the distributionof stress in the annulus. Eliminating thisstress—and avoiding fractures—limits gasinvasion. Tensile stresses build up in the gelif annular volume increases or cement vol-ume decreases. Thus, designing cement slur-ries with low shrinkage and controlled fluidloss during the gelation stage, and avoidingexcessive pressure fluctuations in the casingare important in preventing fractures.

Designing cement slurries that expand asthey set takes this one step further. The twoprincipal techniques for inducing expansionin oilwell cements are gas generation andcrystal growth. The gas-generating tech-nique operates on the same principle as thatused for compressible cements, except thatthe concentration of gas-generating materialis reduced. Also, expansion can occur onlybefore the cement develops significantstructural strength.

The most common way of inducingexpansion is to encourage the development

46

of ettringite—a highly hydrated form ofcalcium sulfoaluminate—during thehydration reaction. This is often achieved byadding gypsum or plaster of Paris to thecement powder. Ettringite increases thegrowth of certain expansive crystallinespecies within the set cement matrix. Bulkvolumetric expansion is generally less thanone percent.

Alternatively, oxides of certain alkalineearth metals may be added to achieveexpansion. An advantage of these is that theexpansion occurs above 170°F [77°C], atemperature at which ettringite is unstable.

There is little doubt that controlled cementexpansion by crystalline growth can helpseal small gaps between the cement sheathand the casing or formation, but it is unlikelyto be effective in sealing large channels cre-ated by gas migration. Much of the expan-sion takes place after gas flow has been initi-ated and the size of the created channels issimply too large. Also, these cementsundergo a bulk expansion, but still exhibit anet chemical contraction and experience thesame hydrostatic and pore pressuredecreases as nonexpansive cements.

Thixotropic cements16—During cementstate 1—when cement is a liquid suspen-sion—gas bubbles can move within acement column only if cement yield stressremains below a critical value. Designing aslurry with a rapid increase in gel strengthhelps trap invading gas before it can rise inthe form of a bubble, preventing zonal com-munication or gas flow to surface. Somethixotropic slurries offer such a rapidincrease in gel strength.17

There are two ways to induce thixotropicbehavior in a cement slurry. The firstinvolves creation of a microcrystalline net-work of mineral hydrates throughout theslurry by adding a small amount of plaster,bentonite or silicate materials. This friableand temporary microstructure supports thebulk of cement solids from an early stage inthe slurry’s life. The second techniqueemploys polymers (dissolved or dispersed inthe interstitial water), which are crosslinkedto create a self-supporting viscous gel bychemical reaction.

The transmitted hydrostatic pressure ofthixotropic systems should revert to the gra-dient of the interstitial water and remain assuch until the setting period begins. How-

ever, at this point hydrostatic pressure maybegin to decrease and gas may enter bysome other mechanism.

Tough cements—Properties of set cementmay also be modified by inclusion of vari-ous additives. Once again, attention hasturned to polymeric latex additives thathave had widespread use outside the oilfield, largely because of their ability to actas tougheners. Latex-modified cements haveincreased tensile strength, reduced shrink-age during hydration, increased fracturetoughness and improved adhesion or bond-ing (see “Compressive Strength VersusToughness: A Brief Overview,” page 43).18

Predicting Gas Migration and Designingan Appropriate SolutionArmed with an understanding of the phe-nomena, completions engineers face thechallenge of finding the right solutions (see“Gas Migration Mechanisms and ControllingFactors,” next page, bottom). Predicting like-lihood of postplacement gas migration allowsthe design of cost-effective remedies basedon the relative risk of gas migration.

Modeling gas migration is difficultbecause it represents a series of complexphysical processes. Furthermore, it is a non-steady-state phenomenon involving varyingpressure fields, changing fluid saturationand an evolving matrix structure. Hetero-geneity within the cement paste or bound-ary effects at the casing or formation caninduce events such as nonuniform gasbreakthrough which are, by definition,unpredictable. Therefore, it is not possibleto predict gas migration with absolute relia-bility. The following section describes howone company, Dowell, has developed mod-eling and software techniques to assess gasmigration risk.19

The Dowell methodology for predictingpotential gas migration began in 1989 withthe GASRULE gas migration predictive sliderule. This simple slide-rule-based methoduses well data, gas-zone permeability andheight, gas pressure, hydrostatic conditions,mud spacer and cement characteristics,fluid volumes and mud-removal efficiencyto estimate four dimensionless factors: for-mation factor, mud-removal factor, hydro-

Oilfield Review

nQualitative gas-migration prediction.The GASRULE slide-rule-based method of working out theoptimal cementingsolution has beenrefined and incorpo-rated into a quantita-tive design approach.

Spring 1996

15. Fery JJ and Romieu J: “Improved Gas Migration Con-trol in a New Oil Well Cement,” paper SPE 17926,presented at the Middle East Oil Technical Confer-ence and Exhibition, Manama, Bahrain, March 11-14, 1989.Richardson EA: “Nitrogen Gas Stabilized Cementand a Process for Making and Using It,” US PatentNo. 4,333,764 (1982).Burkhalter JF, Childs JD and Sutton DL: “WellCementing Process and Gasified Cements UsefulTherein,” US Patent No. 4,450,010 (1984).

16. Thixotropic gels are viscous when static, but becomemore fluid-like and less viscous when disturbed ormoved by pumping.

State Mechanism Limiting parameters Potential gas flow rate

Viscoelastic fluid Bubble flow Yield stress, gap width 10-9m3/secTube flow Yield stress, gap width 10-6m3/secViscous fingering Plastic viscosity, 10-7m3/sec

viscosity ratioFracture Elasticity, 10-6m3/sec

stress in annulus,Relaxation Time

Porous solid Fingering Fluid viscosity 10-6m3/secFracture Elasticity, darcy drag, 10-5m3/sec

stress in cement,elasticity

Permeation Permeability, 10-9m3/secdarcy drag,capillary pressure

Elastic solid Fracture Fracture toughness, 10-1m3/secinterfacial toughness,stress state

Gas Migration Mechanisms and Controlling Factors

17. Sutton DL, Sabins F and Faul R: “Annular Gas-FlowTheory and Prevention Methods Described,” Oiland Gas Journal 82 (December 10, 1984): 84-92.

18. Ohama Y: “Polymer-Modified Mortars and Con-cretes,” in Ramachandran VS (ed): Concrete Admix-tures Handbook: Properties, Science & Technology.Park Ridge, New Jersey, USA: Noyes Publications(1984): 337-429.

19. The prediction methodology outlined is based onexperiment, engineering and statistical analysis. Thisapproach assumes gas flow through the evolvingcement matrix. The model cannot predict theappearance of gas flow weeks or months after thecement job.

static factor and slurry-performance factor(above ). Each factor may be optimizedindependently and combined into an indexthat classifies the possibility of controllinggas migration—either “poor,” “moderate” or“excellent.” While strictly qualitative, theseclassifications do allow testing of differentcompletion strategies against one another.

Three developments have helped refinethe GASRULE approach. First, in 1990, theempirical mud-removal factor was replacedwith a more complete approach, based onthe Dowell WELLCLEAN mud removaltechnology—which helps choose washes,spacers and slurry types, while indicatingwhether a turbulent or laminar displace-ment regime is the most favorable. Second,the hydrostatic factor used in the GASRULEsystem has been replaced by a more rigor-ous postplacement analysis.

The third development marks a majoradvance. A quantitative design approachhas now been incorporated in the newCemCADE cement job computer-aided

47

nDesigner cementjobs. CemCADEsoftware improvesthe design andevaluation ofcementing joboperations. In thefirst step of a CemCADE session,well geometry and casing config-uration to becemented aredefined (top). The composition,sequence, volumeand final positionsin the wellbore ofthe fluids that willbe pumped (mud,wash, spacer, and lead and tailslurries) are thendefined, andhydrostatic pres-sures are checked(middle). ThePlacement Simula-tor module is usedto determine nec-essary centraliza-tion and to selectthe pump rate formud removal; fric-tion pressures andflow regimes arecalculated (bot-tom). Finally, thejob is simulatedusing the U-TubeSimulator module,indicating the ratesat which fluidsmust be pumped.

design and evaluation software (right ).20

Today, the CemCADE gas-migration mod-ule assists in design and assesses alternativesolutions. This methodology is a consider-able improvement over the GASRULEapproach, but it does retain four similardesign factors: formation factor, mud-removal factor, postplacement factor andslurry-performance factor.

Formation factor—Analysis begins withcharacterizing all possible gas-bearing for-mations in terms of position, height, pres-sure and permeability. An accurate descrip-tion of pore pressure versus depth isrequired to optimize hydrostatic parameters.Good descriptions of the pore pressure ofother permeable layers and the fracture gra-dient are also required. The formation fac-tor, indicating the risk of gas flow, is calcu-lated from these formation parameters.

The more information about the formationthat is available, the greater likelihood of agood design. Trying to understand the gasmigration problem is quite difficult usingonly an average pore-pressure gradient forthe entire openhole section.

Mud-removal factor—As mentioned, aprimary goal when cementing across a gaszone is optimum mud removal. The correctapplication of WELLCLEAN technology ismandatory for gas-migration control. Forpractical purposes, good zonal isolationover a 600-ft [180-m] section above the topof a gas zone should be achieved. In thegas-migration module, information aboutseveral factors is required to determine thequality of mud removal, including:• Mud-circulation factor—an estimate of

whether enough of the mud in the well isin circulation prior to cement placement.

• WELLCLEAN factor—the factor chosen iseither the turbulent or laminar flow resultfor a given simulation, whichever isappropriate for the well conditions anddelivers the required mud removal. Timeof turbulence across the zone is calcu-lated, along with effective volume ofspacer to displace the mud in laminarflow, and effective volume of cement todisplace the spacer in laminar flow, asestimated from the U-tube simulation.

48 Oilfield Review

20. Catala G, de Montmollin V, Hayman A, Hutin R,Rouault G, Guillot D, Jutten J, Qureshi U, Kelly B,Piot B, Simien T and Toma I: “Modernizing WellCementation Design and Evaluation,” OilfieldReview 3, no. 2 (April 1991): 55-71.

• Pipe-movement factor—assigns a positivevalue for pipe movement, which aids inbreaking the gel strength of the mud andmakes it easier to remove. This factordepends on whether reciprocation, rota-tion or both are used to enhance mudmobilization.

• Bottom-plug factor—depends on thenumber of bottom plugs used to reducethe degree of contamination occurring asfluids are circulated.

• Fluids-compatibility factor—relates topossible chemical interaction betweenvarious fluids.The final mud-removal factor is then com-

puted by summing these five factors—thegreater the final value, the better the antici-pated result.

Postplacement factor—Postplacementanalysis is used to evaluate the severity of apotential gas migration problem and toquantify the influence of simple solutionssuch as applying annular pressure. As previ-ously discussed, gas migration is generallycaused by a loss of hydrostatic pressure.First-level understanding of this may bederived from gelation alone.

To characterize gelation, the notion ofwall shear stress (WSS) has been introduced(see “How Gas Gets into the Annulus, page39). As WSS increases, annular hydrostaticpressure falls. When hydrostatic pressureequals formation gas pressure, WSS istermed “critical” WSS (CWSS). Furtherincrease in WSS beyond this critical valuewill allow gas to enter the annulus. WSSdepends on parameters such as formationgas pressure, openhole diameter, and den-sity and position of fluids. It is also sensitiveto any extra annular pressure, the presenceof external casing packers or techniques liketwo-stage cementing that may sometimes beemployed to improve gas control.

CemCADE software calculates WSS andassesses how use of hydrostatic modifiers—such as ECPs—may be adjusted to maxi-mize the critical WSS, delaying gas entryand allowing more time for cement toharden uninvaded. However, the calcula-tion does not take into account possiblefluid loss that may accelerate annular pres-sure decrease.

Slurry-performance factor—Once gasenters the cement column, it may migrate toa point of lower pressure. Resistance to gas

Spring 1996

depends on slurry composition. For everyslurry there is a minimum wall shear stress(MWSS) above which gas can no longermigrate. The MWSS depends mainly on thechemical composition of the slurry as wellas bottomhole static temperature.

For every design there is a critical rangefor WSS and, therefore, a critical timeperiod during which gas can migrate in theslurry. This period extends from the time atwhich the slurry reaches critical WSS to thetime it becomes impermeable to gas. Opti-mizing a design consists of reducing thistime period by increasing critical WSS,decreasing MWSS or shortening the time togo from the CWSS to the MWSS.

The two parameters used by the DowellCemCADE system to calculate the slurry-performance factor are transition time andfluid loss. The faster the slurry developsimpermeability to gas, the lower the proba-bility that gas migration will occur. Themeasure of the evolution of the relative per-meability of a cement slurry to gas duringthe hydration period determines whether acement slurry can control gas. The rate ofcement-slurry permeability decline is diffi-cult to measure. But it is possible to corre-late permeability decline to the rate ofchange in consistency of a cement slurryduring an API thickening time test—that is,the transition time.

During cement hydration, a major cause ofpore-pressure loss is the loss of fluid to sur-rounding formations. The propensity for gasto percolate may thus be related to the fluid-loss potential of the slurry. Transition timeand fluid loss have been incorporated into asingle term, the slurry-performance factor.

Gas-migration factor—The formation,mud-removal, postplacement and slurry-per-formance factors are then linearly combinedto give the final index or gas-migration factor.Evaluation of the risk associated with a givendesign is based on the gas-migration factorcompared to a scale ranging from “very criti-cal” to “very low” risk of migration.

Looking Forward to Further ChangeEvery completions engineer knows that gasmigration is a complex problem. Successfulcontrol requires systematically addressingthe gamut of factors that affect final jobquality. Attempting to prevent gas migrationby addressing a single factor chosen fromthe list of possible chemical and mechanicalevents will inevitably result in failure.

This year, CemCADE design software willbecome available on a PC platform. Thetransition from rules-of-thumb governingchoice of solution through a slide-rule sys-tem of assessing gas migration to a com-puter-based design system will be complete.Some of the advances and technology thathave been described contribute not only tocombating gas migration, but also toimproving the quality of all critical cementoperations. Mud removal, correct choice ofslurry type and accurate mixing technologyare key elements in the evolving world ofcementing design and execution. —CF

49

50

For help in preparation of this article, thanks to MarkBogaards, Cliff Kelly and Mark Puckett, Wireline & Test-ing, Houston, Texas, USA; Bob Godfrey, Colin Hulme,Tore Karlsson, Jane Lam, Dominique Pajot, John Ullo andÖz Yilmaz, Geco-Prakla, Gatwick, England; George Jamieson, Geco-Prakla, Houston, Texas; and Ron Roberts, Amoco, Denver, Colorado, USA.

Paul FarmerGatwick, England

Douglas MillerRidgefield, Connecticut, USA

Andy PieprzakJeff Rutledge Richard WoodsHouston, Texas, USA

Exploring the Subsalt

Advances in seismic imaging have changed the way explorationists

view salt bodies. Once seen as impenetrable barriers to geophysical

probing with some flanking pay zones, many salt structures are now

proving to be thin blankets shielding rich reserves. Geophysicists are

developing new methods to see through salt, illuminating the reservoirs

below. This new vision of subsalt is impacting E&P decisions from well

planning and drilling to field delineation and development.

60°

30°

0°

30°

■■Distribution of offshore salt sheets. [Adapted from Ward RW, MacKay S, Greenlee SMand Dengo CA: “Imaging Sediments Under Salt: Where are We?” The Leading Edge 13,no. 8 (August 1994): 834.]

From the earliest days of exploration,prospectors associated salt with oil andgas—but not always for the right reasons. Inthe 1920s, so many successful wells weredrilled around salt domes that logging meth-ods were tuned to identify the high-salinitywater in formations overlying pay zones.1 By1923, gravity and seismic methods becamesuccessful in spotting salt domes, and theindustry was on its way to understanding thestructural role played by salt. Today, inter-preters can view and tour salt structureswith the help of powerful graphics worksta-tions (next page, top).

Salt is one of the most effective agents innature for trapping oil and gas: as a ductilematerial, it can move and deform surround-ing sediments, creating traps; salt is alsoimpermeable to hydrocarbons and acts as a

Oilfield Review

1. Allaud LA and Martin MH: Schlumberger The Historyof a Technique. New York, New York, USA: JohnWiley & Sons (1977): 68-69.

2. Western PG and Ball GJ: “3D Prestack Depth Migra-tion in the Gulf of Suez: A Case Study,” GeophysicalProspecting 40 (1992): 379-402.

Charisma seismic interpretation system, KUDOS 3Dvelocity modeling system, and SALTBOND cement sys-tem are marks of Schlumberger. CM-5 is a mark of Think-ing Machines Corporation. GeoDepth is a mark ofParadigm Geophysical. InDepth is a mark of WesternGeophysical.

nFlying through a seismic interpretation. The top of a salt feature (yellow surface) has been interpreted on a seismic workstation. Alsoshown is a panel of seismic data (background), a reflector above the salt (brown surface), seismic velocities at vertical well locations(multicolored vertical logs) and deviated well trajectories (blue lines).

Passive—No Space Problem

Active—Diapir Creates Space

Reactive—Extension Creates Space

Thinning,arching

Radial orsubparallelfaults

nStyles of salt intru-sion. When the over-lying sediments offerlittle resistance (top),salt can rise, oftendragging flankinglayers up with it. Ifthe overburden doesresist, salt pressuredfrom below (middle)can still pushthrough, doming theoverburden and cre-ating radial faults inthe process. In thecase of regionalextension (bottom)faulting in the rigidoverburden can openthe way for salt torise. [Adapted fromJackson MPA, Vendev-ille BC and Schultz-ElaDD: “Salt-Related Struc-tures in the Gulf ofMexico: A Field Guidefor Geophysicists,” TheLeading Edge 13, no. 8(August 1994): 837.]

seal. Most of the hydrocarbons in NorthAmerica are trapped in salt-related struc-tures, as are significant amounts in other oilprovinces around the world (previous page).Many reservoirs in the North Sea are belowsalt, as are large fields in the Gulf of Suez.2

A product of seawater evaporation, saltaccumulation can reach thousands of feet inthickness. Salt retains a low density of2.1g/cm3 even after burial. However, the sur-rounding sediments compact and at somedepth become denser than the salt—anunstable situation. If the overlying sedimentsoffer little resistance, as is sometimes thecase in the Gulf of Mexico, the salt rises, cre-ating characteristic domes, pillows andwedges that truncate upturned sedimentarylayers (right). If the overburden does resist,salt can still push through, creating faults inthe process. If tectonic conditions are right,extensional faulting in the rigid overburdencan open the way for salt ascent. Much ofthe Zechstein salt pervasive in the North Seahas been mobilized this way.

In contrast to salt’s low density is its highseismic wave velocity—4400 m/sec (14,432ft/sec)—often more than twice that of sur-rounding sediments. The strong velocitycontrast at the sediment-salt interface actslike an irregularly shaped lens, refracting and

51Spring 1996

Fan ofnormalfaults

52

nEarly imaging results around salt. Seismic data processing resulted in images of bot-tomless salt diapirs (left). Enhancements in processing began to correctly image thesteeply dipping and sometimes overhanging faces of salt (right). [Reprinted with permis-sion from Ratcliff DW, Gray SH and Whitmore ND: “Seismic Imaging of Salt Structures in theGulf of Mexico,” The Leading Edge 11, no. 4 (April 1992): 15 and 22.]

Houston

Lake Charles

New Orleans

Enchilada

Mahogany

Teak Gemini

MickeyMouse

DiscoveryPlugged and abandonedSalt sheets

nSalt sheets mapped in the Gulf of Mexico. Recent exploration wells correspond to wells mentioned in table (next page).

1 2 3 4

Evolution of a Salt Wall

1 2 3 4

Evolution of a Salt Diapir

nEvolution of salt intrusions. Salt walls and diapirs are initiated at instabilities on extensive salt layers. As the salt rises and thenflows horizontally, the walls and diapirs change shape. Eventually some salt features become completely detached from the parentsalt layer.

Two-

way

tim

e

Distance Distance

0

1.0

2.0

3.0

Two-

way

tim

e, s

ec

reflecting seismic energy. Early data process-ing techniques treated this contrast like amirror, resulting in images that portrayed saltfeatures as bottomless diapirs extending tothe deepest level of seismic data (left). In the1980s, seismic processing began to correctlyimage the steeply dipping and sometimesoverhanging faces of salt where hydrocar-bons could accumulate.

But in the last five years, a new image ofsalt has emerged. In some areas, not only isthe top of salt clearly visible, but the bottomalso. Geologists hypothesize that in theseareas of allocthonous salt—found awayfrom its original depositional position—con-ditions allow the salt, having reached verti-cal equilibrium, to begin flowing horizon-tally (above). In the Gulf of Mexico, thisoccurs mainly in deep water beyond thecontinental shelf, where sediment cover isnot as thick as it is near shore (bottom left).Wells drilled through thin salt sheets haveencountered oil-bearing sediments below.

However, knowledge of the existence ofhydrocarbons below salt is insufficient rea-son to start drilling. Drilling salt is risky (see“Drilling and Completions Through Salt,”page 54). The salt itself is weak and under-goes continuous deformation. Belowintruded salt, sediment layers are often dis-rupted and overpressured. And most impor-tant, unless seismic data have been pro-cessed to image through the salt, theposition of the target is unknown.

Oilfield Review

Spring 1996

Subsalt Scorecard in January 1996

Mickey MouseMississippiCanyon 211

Prospect

MahoganyShip Shoal 349

Amoco 1South MarshIsland 169

MesquiteVermillion 349

Ship Shoal 250

TeakSouth TimbalierAddition 260

Ship Shoal 360

Ship Shoal 368

South Timbalier 289

Exxon andConoco

Operators/Partners

Phillips, Anadarkoand Amoco

Amoco

Phillipsand Anadarko

Japex and Vastar

Anadarko(originally withPhillips)

Unocaland Conoco

Amerada Hessand Shell

Consolidated Natural Gas andLouisiana Land & Exploration

Noncommercialdiscovery

Result

Commercialdiscovery

Dry hole

Dry hole

Dry hole

Potentiallycommercialdiscovery

Pluggedand abandoned

Dry hole

Dry hole

1991

Date

1993

1993

1994

1994

1994

1994

1994

1994

EnchiladaGarden Bank 128

South AnaVermillion 308

Garden Banks 119

AlexandriteShip Shoal 337

MonaziteVermillion 375

AgateShip Shoal 361

South Timbalier 231

North LobsterSouth Timbalier 308

GeminiMississippiCanyon 292

No NameSouth MarshIsland 97

Bald PateGarden Banks 260

Shell Offshore Inc.,Amerada Hessand Pennzoil

Amocoand Vastar

Oryx

Phillips, Anadarkoand Amoco

Anadarko

Phillipsand Anadarko

Louisiana Land & Exploration,Anadarko and Agip

Marathon

Texacoand Chevron

Pennzoil, OXYand Total

Commercialdiscovery

Dry hole

Dry hole

Dry hole

Drilling in 1996

Drilling in 1996

Drilling started in 1995

Potentiallycommercialdiscovery

Drilling in 1996

Developmentunder way

1994

1994

1995

1995

Spuddedin 1995

1995Oryx andAmerada

Commercialdiscovery

1996

1996

1995

Hydrocarbons present

nSubsalt drilling scorecard in the Gulf of Mexico. Since the successful well drilled byPhillips and partners in 1993, subsalt exploration in the Gulf of Mexico has blossomed.[From Taylor G: “Subsalt Returns to the Top,” AAPG EXPLORER 17, no. 2 (February 1996): 8.]

A few operators have announced signifi-cant oil discoveries beneath salt in the Gulfof Mexico, rekindling a spirit of explorationin the Gulf. Phillips Petroleum Company, inpartnership with Anadarko Petroleum Cor-poration and Amoco Production Company,announced the first commercial Gulf ofMexico subsalt discovery with theMahogany prospect in 1993, and attributedthe success to the imaging technique calledprestack depth migration.3 Drilled in 375 ft[114 m] of water to a depth of 16,500 ft[5030 m], the well produces from sedimentlayers beneath a salt sheet 3000 to 8000 ft[915 to 2439 m] thick.

Since the Mahogany find, many morewells have been drilled in the area, withother operators experiencing similar suc-cess (left). Before prestack depth migration,the success ratio in the subsalt play wasaround 5%. The new technique is increas-ing that to 25%. Depth migration is alsobringing first-time details to light in some ofthe many North Sea reservoirs that producefrom below salt, and operators plan explo-ration campaigns in the Red Sea using thesame method.4

What is this imaging technique and howdoes it help illuminate subsalt reservoirs? Theanswers are found in a review of the familyof imaging methods, including prestackdepth migration, that are bringing subsaltand other complex structures to light.5

(continued on page 56)

53

3. Westcott ME, Leach MC, Wyatt KD, Valasek PA andBranham KL: “Mahogany: Seismic Technology Lead-ing to the First Economic Subsalt Field,” ExpandedAbstracts, 65th SEG International Meeting and Exposi-tion, Houston, Texas, USA (October 8-13, 1995):1161-1164.

4. Salpukas A: “Anadarko Planning to Drill in Red SeaUsing Computers,” New York Times, September 29,1995.

5. For more on subsalt imaging topics: The Leading Edge13, no. 8 (August 1994).

54 Oilfield Review

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aPotential Problems Casing Strings Wellbore Displacement

Salt

Radial stress relaxation

Salt creep ledgesimpinge on drillstring

Borehole wall weakenedby leaching water, gasand other mineralsout of salt

Wellbore enlargementresults from saltdissolution

Accumulated cuttingsjam drillstring

Salt

Salt

Caprock

Shear zone

Saltflow

150°F

200°F

Potentialoverpressure

Unconsolidatedzone

nSpectrum of challenges in subsalt drilling and completion. Drillers have to address factors that cause openhole instability and accompanying problems, includingborehole walls weakened by incompatible muds, restrictions and undergauge hole caused by salt creep, or enlargement due to dissolution (left). In rapidly moving salt,liners cemented inside cemented casing reduce radial pipe deformation and so increase wellbore resistance to nonuniform loads (center). During the life of a well, saltmovement can displace wellbore tubulars, possibly causing casing failure or restricted access (right).

Drilling and CompletionsThrough Salt

Properties of salt—pseudoplastic flow under sub-

surface temperatures and pressures, and low per-

meability—that make salt bodies effective hydro-

carbon traps also present unique challenges for oil

and gas operators (above). Special considerations,

from selecting drilling fluids and bits to imple-

menting casing programs and cementing proce-

dures, are required to produce long-lasting wells.

Methods developed on the US Gulf Coast and in

the Gulf of Suez, Egypt have improved the effi-

ciency and reliability of drilling and completion

operations in thick salt sections.1

Unlike typical sediment sequences in which hor-

izontal stresses are less than vertical stresses

from overburden, salt is like a fluid, with stresses

in all directions approximately equal to the over-

burden. Therefore, if borehole fluid pressure is

less than in-situ salt strength, stress relaxation

may significantly reduce openhole diameters. In

some cases, relaxation and salt creep can cause

borehole restrictions even before drilling and com-

pletion operations are finished. Undergauge bore-

holes can lead to stuck drillpipe, problems running

casing and ultimately casing failures—ovaling,

bending or collapse.

To maintain near-gauge boreholes, drilling flu-

ids must minimize hole closure and washouts.

Water- and oil-base muds with saturated and

undersaturated salt concentrations, and synthetic

fluids have been used to drill salt, but no single

system works all the time. Water-base muds with

low salt concentrations try to balance salt erosion

and dissolution with creep rate to maintain hole

size. However, because salt creep and dissolution

change across thick salt sections, this can be

problematic and hole size may vary with depth.

High-salt-concentration, water-base muds dissolve

enough salt to offset creep, but can become under-

saturated at high temperatures and enlarge the

hole. Oil and synthetic muds prevent dissolution

and can be used effectively in salt, but are expen-

sive, can leach water, gas and other mineral inclu-

sions out of salt and may not offset creep.2 Eco-

nomic, easy to maintain and adaptable

salt-saturated, water-base muds are often used.

55Spring 1996

1. Barker JW, Feland KW and Tsao YH: “Drilling Long Salt Sec-tions Along the U.S. Gulf Coast,” paper SPE 24605, pre-sented at the 67th SPE Annual Technical Conference andExhibition, Washington, DC, USA, October 4-7, 1992.

Pattillo PD and Rankin TE: “How Amoco Solved CasingDesign Problems in The Gulf of Suez,” Petroleum EngineerInternational 53, no. 11 (November 1981): 86-112.

2. Leyendecker EA and Murray SC: “Properly Prepared OilMuds Aid Massive Salt Drilling,” World Oil 180, no. 4 (April 1975): 93-95.

3. Warren TM, Sinor LA and Dykstra MW: “SimultaneousDrilling and Reaming with Fixed Blade Reamers,” paper SPE30474, presented at the 71st SPE Annual Technical Confer-ence and Exhibition, Dallas, Texas, October 22-25, 1996.

4. O’Brien J and Lerche I: “Understanding SubsaltOverpressure May Reduce Drilling Risks,” Oil & Gas Jour-nal 2, no. 4 (January 24, 1994): 28-34.

5. Cheatham JB and McEver JW: “Behavior of Casing Sub-jected to Salt Loading,” Journal of Petroleum Technology 16(September 1964): 1069-1075.

6. Burkowsky M, Ott H and Schillinger H: “Cemented Pipe-in-Pipe Casing Strings Solve Field Problems,” World Oil 193,no. 5 (October 1981): 143-147.

El-Sayed AAH and Khalaf F: “Resistance of Cemented Con-centric Casing Strings Under Nonuniform Loading,” SPEDrilling Engineering 7, no. 1 (March 1992): 59-64.

7. Recent methods use common Von Mises calculations fornormal loads along with the addition of stresses to accountfor nonuniform collapse. For more on these methods: Hack-ney RM: “A New Approach to Casing Design for Salt Forma-tions,” paper SPE/IADC 13431, presented at the 1985SPE/IADC Drilling Conference, New Orleans, Louisiana,USA, March 6-8, 1985.

8. An article in three parts: LeBlanc L: “Drilling, Completion,Workover Challenges in Subsalt Formations,” Offshore(June 1994): 21-22, 49 (part I); (July 1994): 42-44, 59 (partII); (August 1994): 38-40 (part III).

9. Yearwood J, Drecq P and Rae P: “Cementing Across Mas-sive Salt Formations,” paper 88-39-104, presented at the39th Annual Technical Meeting of the Petroleum Society ofCIM, Calgary, Alberta, Canada, June 12-16, 1988.

Salt is weak and soft, so polycrystalline dia-

mond and other mill-tooth insert cutters, which

make hole by scraping, are used. Stronger inserts

may be needed to penetrate caprock formed on the

top of some salt layers by groundwater leaching of

minerals. Side-cutting, eccentric or bicentered

reamers above bits have been proposed to open up

hole diameters that are larger than the bit and

allow for some salt creep before the borehole

becomes undergauge.3

After drilling into salt, heavier than expected

mud weights may be needed to control salt flow.

Drilling speeds vary among operators, but reason-

ably fast penetration rates—60 to 150 ft/hr [18 to

46 m/hr]—are required, so wells can be cased

quickly. Good hole cleaning and periodic back-

reaming, however, should not be sacrificed just to

make hole faster. Circulating a small volume of

fresh water can remove salt restrictions and free

stuck pipe, but care must be used to prevent

washouts. Enlarged or undergauge holes make

directional control difficult.

Thick salt bodies can affect temperature and

pressure in surrounding formations. Salt thermal

conductivity is high compared to other sediments,

so overlying formations are heated and underlying

formations are cooled. Because salt is a barrier to

basin fluids, if outward flow is insufficient to

achieve normal compaction, high pressure may

develop below salt.4 As disrupted sediments

below salt are penetrated, fluid losses or flow

can occur, depending on mud weight and forma-

tion pressures, unless drillers proceed slowly

and carefully.

Washouts, restrictions, ledges and moving salt

exert nonuniform loads on casing.5 Increasing wall

thickness offers better resistance to these loads

than higher yield strength steels, so heavy-wall

casing can be used if salt creep rates are low and

good cement jobs can be obtained. In more

extreme cases of rapidly moving salt, liners

cemented inside cemented casing increase

nonuniform load capacity by reducing casing

deformation. Collapse resistance of properly

cemented concentric strings can equal or exceed

the combined strengths of individual liners and

casings.6 Casing across salt zones is subjected to

tension, compression, burst and hydrostatic loads

combined with nonuniform forces, which must be

included in design calculations.7 Casing can be set

just below salt to save time or in deeper forma-

tions for better support, depending on the salt

interval.8 A diversion stage tool in the casing

string just below the salt may be needed to place

specialized cements across the salt, reduce hydro-

static pressure on weaker subsalt intervals or

ensure efficient slurry placement.

Effective cement fill in the annulus between the

outer casing and borehole minimizes nonuniform

load effects. Long slurry thickening times may

allow salt to encroach on casing before a complete

set occurs, and inadequate displacement across

washouts may cause unequal loading or localized

bending. Adequate fluid-loss control is needed to

prevent excessive loss of slurry mix water that can

dissolve or weaken salt, adversely affect cement

properties or cause annular bridging, loss of

hydrostatic pressure and gas migration (see “Get-

ting to the Root of Gas Migration,” page 36).

Salt-saturated cements prevent salt dissolution,

but are more difficult to mix on surface and extend

slurry set times (over-retardation). Freshwater and

low-salt concentration slurries avoid retardation

problems and are easier to handle, but long-term

exposure to salt may lead to cement failures.

Additives introduced in the late 1980s helped solve

over-retardation and strength development prob-

lems in salt-rich slurries.9 This led to development

of proprietary slurries for cementing across salt

zones like the Dowell SALTBOND cement system,

which provides controllable thickening times,

good early compressive strengths, effective place-

ment rheology, excellent fluid-loss control and

resistance to aggressive brine attack. –MET

56 Oilfield Review

6. For a review: Farmer P, Gray S, Hodgkiss G, PieprzakA, Ratcliff D, Whitcombe D and Whitmore D: “Struc-tural Imaging: Toward a Sharper Subsurface View,”Oilfield Review 5, no. 1 (January 1993): 28-41.

nStacking to enhance and focus seismic signals by summing traces reflected midway between several source-receiver pairs. Energyarrives on each seismic record at a different time, depending on the source-receiver separation, or offset. The arrival times define ahyperbola. Before the traces can be stacked, they must be shifted to align arrivals. The offset versus time relationship that describesthe shifts defines the stacking velocity of that layer.

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa0 offset

Offset 1

Offset 2

Offset 3

Offset 4

Common midpoint(CMP)

1 2 3 4

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way

tim

e

1 2 3 4Offset

Hyperboliccurve

Stackingvelocity

+ =

Offset

Corrected CMP gather StackedCMP

+ + + =aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaMigratedtrace

Midpointtrace Receiver

MIG

Source

Salt

Originaldata

nRedistribution of reflected seismic energyby migration. In this simple 2D rendition,migration (MIG) repositions a reflectedtrace from its recorded position to its trueposition using a velocity model. In morecomplex and 3D cases, reflections may beredistributed to positions outside the planecontaining the source and receivers.Energy may also be distributed amongmultiple locations.

ImagingImaging describes the two seismic data pro-cessing steps, stacking and migration, thatbring seismic reflections into focus. Stackingattempts to increase signal-to-noise ratio bysumming records obtained from severalseismic shots reflecting at the same point(above). Energy arrives on each trace at adifferent time, depending on the source-receiver separation, or offset. For a uniform-velocity layer overlying the reflector, seismicrays are straight, and the arrival times definea hyperbola. The set of traces is called acommon midpoint (CMP) gather. Before theCMP gather can be stacked, the traces mustbe shifted to align arrivals. The offset versustime parameter that describes the shiftsdefines the stacking velocity of that layer.Shifting is performed for all reflections visi-ble in the traces. The result of stacking is asingle trace, taken to represent the signalthat would have been recorded in a normal-incidence experiment at the midpoint of thesource-receiver pairs. The basic assumptionin stacking is that velocity does not varyhorizontally over the extent of the gather.

The second component of imaging,migration, redistributes reflected seismicenergy from its recorded position to its trueposition using a velocity model (right ).There are many classes of migration, vary-ing in environment of applicability fromsimple structures and smooth velocity varia-tions to complex structures and rapidlyvarying velocities.6

The main distinctions, for the purpose ofthis article, are the imaging domain—either

time or depth—and the order of migrationin the work flow—poststack or prestack. Toprocess any one survey, combinations ofmigration techniques may be used. Thetrend today, as complex reservoirs comeunder scrutiny, is to use depth rather thantime and prestack instead of poststack.

In time migration, the velocity model,sometimes called the velocity field, may varyonly smoothly (next page, bottom). Velocityshould increase with depth, and any varia-tions in the horizontal direction should begradual. The output of the process is a seis-

mic volume with time as the vertical axis.Time migration is most successful whenvelocities are laterally invariant or smoothlyvarying. It is often applicable and, hencechosen in most parts of the world.

In depth migration, the velocity modelmay have strong velocity contrasts verticallyor horizontally. Depth migration is suited forenvironments in which velocities changeabruptly, often the case with complex struc-tures such as steep dips, faults, folds, saltintrusions and truncated layers. The outputvolume has depth as the vertical axis. Depthmigration, though often appropriate, is stillrarely done because of the difficulty in con-structing an accurate velocity model.

Poststack migration is migration appliedafter the seismic traces have been stacked.Stacking enhances the seismic signal, andalso reduces by an order of magnitude thenumber of traces that comprise the stackedseismic volume, so migration poststack isroughly 100 times faster than prestack. Forpoststack migration to be effective, theassumptions made in stacking must bevalid. The amplitude of the stacked tracemust represent that of the normal-incidencetrace and reflected arrivals must be approxi-mately hyperbolic (next page, top). Theseassumptions are valid only when the struc-ture is simple. Otherwise prestack migrationis more suitable.

Prestack migration is run before stacking,and can handle the most complex structures

57

nThe effects of velocity variations on raytracing and common midpoint (CMP) assumptions. In a flat model with simplestructures and velocities (top left), raypaths are straight and wavefronts are spherical. Arrival times on seismic records canbe fit with a hyperbola (bottom left). In such a case, the CMP and reflection point would be coincident. Inserting a salt wedgeover the flat reflector (top right) gives rise to bent raypaths. The arrivals do not have a hyperbolic shape on seismic records(bottom right). In this case, the CMP would not be coincident with the reflection point. Also visible in the salt case are multi-ples—arrivals from multiply reflected waves—that present additional processing problems. These waveforms and traceswere created with 2D acoustic finite-difference modeling.

Simple velocities + simplestructure = poststack time migration

Complex velocities + simplestructure = poststack depth migration

Simple velocities + complexstructure = prestack time migration

Complex velocities + complexstructure = prestack depth migration

Incr

easi

ng v

eloc

ity

nVelocity models for four migrationclasses: time, depth, poststack andprestack. Poststack models are on the left,prestack on the right. Time-based modelsare on the top, depth-based on the bot-tom. In time migration, the velocitymodel may vary only smoothly or mono-tonically—always increasing with depth.Depth migration is required for more com-plex velocity models. Poststack migrationworks with models of low complexity,while prestack migration can handle themost complex models.

Dep

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tDistance, ft

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SnapshotSnapshot

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Snapshottime

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Spring 1996

58 Oilfield Review

Model validation

Current layer = maximum

Current layer < maximum

3D poststackdepth migration

volume

Prestack depthmigration of

selected offsets

AnalyzeCIP gathers

3D CMP gathers

3D prestack travel-timeinversion from ray-based

velocity analysis

Compute and outputvelocity nodes

Update velocitycomponent of model

3D poststackdepth migration

Delineate geometryof base of layerin depth domain

Update depthcomponent of model

3D prestackdepth migration

Interpretation ofcurrent layer

in time domain

Velocity modelin depth

3D prestackdepth migration

volume

Inputs

3D stackvolume

nSubsalt prestack depth migration flow chart.Some of the steps, such as velocity modeling andlayer boundary interpretation, require interactiveworkstations. The migrations are run on powerfulmainframe or MPP computers.

and velocity fields. With the amount of datain modern 3D surveys, the main constraintson this method are the time and skillneeded to construct velocity models and thecomputing power required for reasonableprocessing turnaround time.

Imaging a seismic volume containing asalt body is unlike traditional processing, inwhich thousands of tapes are sent off to aprocessing group that sends back a finishedproduct, ready for interpretation. Subsaltimaging requires several iterations of migra-tion and interpretation. The process is acomplex interplay of many steps (left ).7

Some of the steps, such as the migrations,are run as batch input to mainframe or mas-sively parallel processor (MPP) computers.Others, such as velocity modeling and layerboundary interpretation, require interactiveworkstations.

Different operators and service companiesmay have variants of these methods, but thegeneral processing flow is the same. Thefirst step is to build an initial model of thevelocity in the overburden—the velocities oflayers overlying the salt. In the North Sea,several major velocity contrasts may overliethe salt. Velocity estimates can come fromray-tracing-based velocity analysis on CMPgathers. If the common midpoint geometryis not suitable, such as when velocities varyhorizontally, a CMP gather cannot be used.Instead, a common image point (CIP) gatheris created using a prestack migration tech-nique to assemble all the traces that imagethe depths below a given surface location.8

In the Gulf of Mexico, sediments are typi-cally sand-shale sequences with smallvelocity contrasts between layers. Withoutstrong velocity contrast, CMP-based velocityanalysis is not necessary, so initial velocitiesare taken from stacking velocities. In bothcases, velocities are checked for trends withwell data such as sonic logs or boreholeseismic data.

The second step uses this early velocitymodel to predict reflection arrival times onCMP or CIP gathers at control points. Theshape of the arrival times of the shallowestmajor reflector is analyzed for the velocitythat best flattens the times, and the velocitymodel is updated. This is the most time-intensive step, and requires the interventionof an expert and the versatility of an interac-tive velocity modeling workstation. (For atour of the Geco-Prakla KUDOS 3D veloc-ity model building workstation, see “Foun-dations in Velocity,” page 60.)

Spring 1996

nComparing poststack time (top) to poststack depth migration (bottom) on theCavendish survey. The complex velocity model requires depth migration toaccurately image subsalt structures. Without depth migration, the dips on sub-salt layers may be incorrectly imaged.

nSurface of the comp

nVelocity model for the North SeaCavendish survey. The Zechstein salttop is relatively smooth, allowing post-stack migration. Within the salt layerthe lower-velocity Plattendolomit canbe seen. The target layer is the Silver-pit formation.

Time Migration

Depth Migration

Distance, mTw

o-w

ay ti

me,

mse

cD

epth

, m

Distance, m

011,250

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2400

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Amoco Survey Velocity Section

Base Zechstein

Top Zechstein

Silverpit formation

Plattendolomit

50001500 3250Velocity, m/sec

Plattendolomit Surface

With the updated velocity model, post-stack or prestack depth migration is applied,and the gathers are recomputed andchecked for arrival flatness. If necessary,these few steps are iterated to obtain anaccurate velocity of the topmost layer. Thenthe process is repeated for as many layers asare identified above the salt.

If the top of salt appears to be structurallysimple based on preliminary time migration,the velocities of the overburden can be usedin a poststack depth migration to image thetop of salt with good precision. An exampleof this is the imaging of the Cavendish 3Dsurvey in the North Sea. The velocity modelindicates a smooth top of the Zechstein salt(bottom left). Encased within the Zechsteinis a thin, complexly folded dolomite, calledPlattendolomit, that causes strong distortionof seismic ray paths before they reach theSilverpit target. An important step in theconstruction of an accurate depth-velocitymodel was characterizing the shape of thePlattendolomit (below right). The complex-ity of the velocity model—high-velocity saltoverlying lower-velocity sediments—sug-gests that depth migration is better suited forimaging than is time migration. Applyingdepth migration makes a dramatic differ-ence in subsalt structure: the dip of subsaltlayers, and so the locations of potentialtraps, changes significantly compared to thetime migration results (left).

(continued on page 63)

59

7. Modified from: Godfrey B, Pieprzak A, Berg K and Yilmaz Ö: “3-D Salt and Sub-Salt Imaging Strategy: A Case History from the Gulf of Mexico,” TechnicalProgram and Abstracts SEG Summer Research Work-shop on 3-D Seismology: Integrated Comprehensionof Large Data Volumes, Rancho Mirage, California,USA, (August 1-6, 1993): 128-134.

8. Common image point gathers are assembled by amethod that has been likened to looking for a needlein a haystack. Every possible source-receiver pair inthe 3D volume of interest is checked to see whether itcontributes to the signal generated by the reflection ata test point in the volume.

lexly folded Plattendolomit.

6

Foundations in Velocity

Before the arrival of massively parallel processor

computers, migration was the stumbling block in

prestack depth imaging. Now that MPPs can han-

dle migration in reasonably short order, the con-

struction of an accurate 3D velocity model is the

most time-consuming task. The Geco-Prakla

KUDOS 3D velocity model building system allows

specialists in interpretive processing to construct

and visualize velocity models interactively.

Velocity modeling systems developed by other

service companies, such as InDepth by Western

Geophysical and GeoDepth by Paradigm Geo-

physical, contain similar features.

A velocity model is defined by two sets of

parameters—layer velocities and reflector

geometries. Such models can have either time or

depth as their vertical axis. Models with time as

the vertical axis are relatively easy to derive from

conventional time-domain processing, and are

generally smooth: rays can be traced through the

models with moderate bending at interfaces, so

0

nInteractive ray-based velocity analysis. For a chosen gties. A plot of semblance—the coherence achieved betwleft). The higher the semblance, the better that velocity f(upper right). Velocities that are too low produce correcarrival times across the gather (lower right).

processing steps such as computing travel times

through the model can be executed rapidly and

nearly automatically.

In contrast, earth models in depth usually have

strong horizontal and vertical velocity variations.

Rays can bend sharply at interfaces and so the

reflector geometry must be known very accu-

rately. Processing must take an interpretive pause

after each layer is built, precluding automation.

Efficient construction of depth-based models is

the aim of the KUDOS velocity modeler.

Traditional velocity modeling programs con-

strain models to be simple—unlike the real earth

—with no abrupt terminations, pinchouts or multi-

ple vertical values. Layers must be continuous

and extend across the entire survey. The KUDOS

system, by contrast, allows models to be built

with any structural complexity. Graphic elements

are rendered on a high-performance workstation,

allowing immediate visualization—a key ability in

velocity model construction and validation.

ather (lower left panel) traces can be shifted interactively teen traces shifted with a given velocity—shows the best clattens the traces. Velocities that are too high leave arrival ted gathers that swing up at long offsets (middle right). Th

In the KUDOS system, a modeling volume is

defined that has its vertical dimension in depth.

Surfaces corresponding to the main geological

horizons are inserted into this volume, subdivid-

ing it. Interval velocity fields are derived and

assigned to each subvolume, forming a spatially

variant velocity-depth model.

Layers are added to the model in an iterative

sequence. At each stage the model consists of a

series of layers, each with its own velocity field,

and a halfspace of unknown velocity below the

bottom layer. This halfspace contains the next

horizon to be imaged. The velocity that will cor-

rectly image the next horizon is derived through

ray-based velocity analysis (below). The velocity

of the layer is mapped by interpolating velocities

determined at control points (next page, bottom).

The halfspace is then “flooded” with the velocity

field derived for that next horizon.

The subvolume model is then exported from

the KUDOS workstation as either a tessellation or

Oilfield Review

o test different interval veloci-hoices for velocities (uppertimes drooping at long offsetse correct velocities flatten

Spring 1996

nLayered model before (left) and after (right) tessellation. Tessellation divides layer volumes into tetrahedra and assigns a velocity to each corner of every tetrahedron.

nTessellation of salt volume with structural complexity at many scales.

Velocity Control Points

Layered Model Before Tessellation Layered Model After Tessellation

Tessellated Salt Body

a 3D grid, and sent with the seismic data to the

computer for post- or prestack depth migration.

Tessellation involves dividing the layered

velocity model into tetrahedra (above, left and

right). Interval velocities are stored at each cor-

ner of every tetrahedron, and the topographies of

the depth surfaces are represented by tetrahedral

facets. Tessellated volumes have special proper-

ties; they are especially efficient for modeling

arrival times by raytracing—for generating travel

times for prestack depth migration—and they can

represent realistic geologic models with struc-

tural complexity at all scales (left). The KUDOS

61

nVelocity control pointsfor a chalk reflectorabove the salt. Velocitiesfor the layer immediatelyabove the reflector areinterpolated betweencontrol points (smallcubes) which are colorcoded by interval veloc-ity—blue is faster thangreen. The spatial posi-tion of each control pointis dictated by rays tracedthrough the velocityfields of the overlyinglayers. A 2D slicethrough the seismic vol-ume is displayed withrays contributing toselected control points.

Correct Velocities

High Velocities

system can also express the velocity model as an

array of evenly spaced 3D grid points. This creates

a volume that may not look as complex as the tes-

sellated volume, but has a velocity representation

more suited for some migration algorithms.

Following migration, the seismic data are

loaded to the interpretation workstation, where

the newly imaged horizon is delineated in depth.

This surface is then incorporated into the KUDOS

model, forming a new base layer. The velocity

field below this layer now needs to be determined,

so the next iteration of velocity analysis begins.

In some areas, such as the Gulf of Mexico, the

background velocity is slowly varying and layer

boundaries are difficult to identify (next page, top).

Instead of proceeding in steps, layer by layer, the

background velocity model is built in just a few

steps, each handling several layers. At selected

locations, CIP gathers are analyzed for the overall

velocity function that best flattens all the arrivals

simultaneously. In the KUDOS system, this

method is called image-based velocity analysis.

The velocity function can be modified interactively

and a corrected gather can be viewed (right).

62 Oilfield Review

nFinding the velocity function that flattens all arrivals simultaneously. Common image point (CIP) gathers(top) obtained from prestack depth migration are converted from depth to time using the current velocitymodel and displayed twice (left and center). The interval (green) and root mean square (RMS) velocity func-tions (red) for this model are shown as a pair of curves on a semblance display (right). Interval velocities canbe modified interactively, automatically adjusting the corresponding RMS velocity function. A new gather isthen computed, and the arrival curvature can be compared to that on the reference gather (left) which remainsunchanged. Other velocities can be tested (bottom). In this example, velocities higher than the referencemodel have been picked (green dots) and applied to the gather (center panel). The new velocities are too high,causing downward curvature to the arrivals. The original velocities remain as black dots on the screen.

nGulf of Mexico salt sheet with associated velocity functions at controlpoints. The background velocity increases gradually with depth (yellow togreen) making layer boundaries above the salt difficult to pick. The strongcontrast and constant velocity of the salt are depicted by the dark blueband in the velocity functions.

nA structurallycomplex salt fea-ture requiringprestack depthmigration to imageits top and bottom.The top surface iswhite, the bottomis gold. Imagingoverlapping saltbodies, such asthose shown in thisfigure, requiresadditional itera-tions in processing.

50001500 3250Velocity, m/sec

Overlapping Salt Bodies

If the top of salt is rough, prestack depthmigration must be applied (right). Geolo-gists surmise that such complex topogra-phies indicate instabilities where theupward movement of the salt, once halted,has been reactivated.

Once the top of salt has been imaged, aninterpreter must delineate the top of salt onan interactive seismic interpretation worksta-tion. Then the velocity model is updated byfilling the volume below the top of salt withsalt velocity, assumed to be uniform. Withthis new model, another prestack—or post-stack if overburden velocities are smoothenough—depth migration is performed, andthe bottom of salt comes into focus.

An interpreter then maps the bottom ofsalt. Next, and similar to the first step, veloc-ities of the sedimentary layers below the saltare estimated. These are first approximatedby the velocities of layers at the same depthbut outside the canopy of salt. Then aprestack depth migration is run and sets ofgathers are checked for flat arrivals. Thevelocity model is updated at these controlpoints until all control points show flat

Spring 1996

arrivals on CIP gathers. Then the velocitiesare interpolated between control points andthe full-volume velocity model is complete.

The final step is to run a prestack depthmigration using the full-volume velocitymodel. Then individual cuts through themigrated data volume can be displayed forfurther interpretation. With the vertical axisin depth, locations of interpreted featurescan be communicated directly to engineersto guide drilling and well location decisions.

This set of techniques was used to imagethe salt and subsalt layers in a survey forAmoco in the southern North Sea gas basin.Layers were interpreted on the Charismaseismic interpretation system, and theirvelocities were modeled on the KUDOSworkstation. The target layers were theRotleigendes and Westphalian sands below

63

64 Oilfield Review

nComparison of poststack (left) and prestack (right) depth migration of the Amoco survey in the North Sea. Poststack migrationproduces a broken image of the top and bottom of the Zechstein salt. Prestack migration better images reflections from thesalt boundaries, and brings subsalt layering into focus.

9. Western PG and Ball GJ, reference 2.10. The Geco-Prakla processing megacenter in Houston,

Texas, USA relies on a Connection Machine CM-5with a 400-Gbyte disk and 512 processing nodes,providing 64 Gigaflops of peak processing power.

11. For a review of borehole seismic applications:Christie P, Dodds K, Ireson D, Johnston L, RutherfordJ, Schaffner J and Smith N: “Borehole Seismic DataSharpen the Reservoir Image,” Oilfield Review 7,no. 4 (Winter 1995): 18-31.

Dep

th, m

Distance, m

1200

00 2250 4500 6750

Distance, m0 2250 4500 6750

2400

3600

Poststack Depth Migration Prestack Depth Migration

the Zechstein salt. Comparison of poststackand prestack depth migration shows thegreater clarity of the prestack method infocusing the top and bottom salt reflections(above ). The prestack depth migrationshows a more sharply focused reflection offthe base of salt and more coherently imagedsubsalt strata than does the poststack migra-tion, paving the way for more confidentinterpretation of subsalt layers.

Algorithms for carrying out these classesof migration have been known for sometime.9 But only in the past few years hascomputer power grown sufficiently to allowcommercially acceptable turnaround forprestack depth migration. Massively parallelprocessors have brought the elapsed timerequired to process a “typical” prestackdepth migration down to one month—a ten-fold improvement.10 In this case, typicalmeans an output volume of two to three off-shore US blocks at 9 sq mile [23 km2] each.Specialists estimate that creating an accu-

rate velocity model takes about a week foreach layer in the model. Velocities must beaccurate to within a couple percent to beuseful for guiding subsalt drilling.

Much work remains if subsalt reservoirsare to be understood as fully as other, moreaccessible fields. In general, even the mostcarefully migrated subsalt images fail toexhibit the same signal quality as sectionsimaged in the absence of salt. Up to now,nearly all subsalt features drilled andlabeled commercial successes have beenidentified by structure rather than by ampli-tude or other waveform attributes routinelytracked by interpreters exploring above salt.

Another seismic technique, the boreholeseismic survey, offers subsalt informationunobtainable by other means.11 These sur-veys, with receivers in the borehole, canmeasure subsalt layer velocities with highaccuracy, map reflector locations and mea-sure reflection amplitudes at the subsaltreflectors. Some operators are using bore-hole seismic survey results to update veloc-ity models for reprocessing prestack depthmigrations.

An advance anticipated in the future is themeasurement of sonic velocities whiledrilling, which can be related to seismiclayer velocities. Operators may be willing toupdate seismic velocity models and repro-cess 3D surveys to get a clearer imagebefore drilling deeper.

The future of subsalt exploration anddevelopment promises as many technicalchallenges as in the past. And beyond salt,the same techniques hold the power toimage other complex features such as over-thrust faults, reefs, recumbent folds and sed-iments below high-velocity carbonates.

—LS