16 Oilfield Review

Orienting Perforations in the Right Direction

Jim Almaguer Jorge Manrique Saliya Wickramasuriya Sugar Land, Texas, USA

Ali Habbtar Saudi Aramco Udhailiyah, Saudi Arabia

Jorge López-de-Cárdenas Rosharon, Texas

David May Amerada Hess Aberdeen, Scotland

Alan C. McNally Dominion Exploration and Production, Inc. Oklahoma City, Oklahoma, USA

Arturo Sulbarán Petróleos de Venezuela S.A. (PDVSA) Caracas, Venezuela

For help in preparation of this article, thanks to BradHoffman, George Spencer and Mark Vella, Rosharon,Texas, USA; James Garner, Dwight Peters and Lee Ramsey,Sugar Land, Texas; Dale Logan, Caracas, Venezuela; andMark Norris, Aberdeen, Scotland.In this article, ClearFRAC, CoilFRAC, DSI (Dipole ShearSonic Imager), FMI (Fullbore Formation MicroImager),FracCADE, GVR (GeoVision Resistivity), HSD (High ShotDensity gun system), OrientXact, PowerFlow, PowerJet,PowerSTIM, PropNET, SPAN (Schlumberger PerforatingAnalysis), UBI (Ultrasonic Borehole Imager) and USI(UltraSonic Imager) are marks of Schlumberger.

Oriented perforating minimizes flow restrictions and friction pressures during

fracturing. The resulting wider fractures permit use of larger sizes and higher

concentrations of proppants along with lower viscosity, less damaging fluids to

improve fracture conductivity. In weakly consolidated reservoirs or formations

with large stress contrasts, properly aligned perforations maximize perforation-

tunnel stability in the formation to mitigate sand production.

Operators use various perforating techniques tosolve problems associated with reservoir stimu-lation and sand management, and to meet otherwell-completion objectives. Optimal phasingangles, hole spacing and orientation of perfora-tions facilitate hydraulic fracturing and eliminatethe likelihood of sand influx from perforation-tunnel collapse.

Producing companies also use oriented perfo-rating to prevent damage to downhole well-com-pletion components, repair channels in cementbehind casing, establish communication withrelief wells during pressure-control operationsand avoid casing collapse in high-angle wells.

Operators employ the latest formationevaluation and interpretation techniques forintegrated reservoir characterization to ensureperforating success. They also take advantage ofcontinuing developments in well-logging tools,tubing-conveyed perforating (TCP) equipment andwireline systems that accurately align perfora-tions in a specified direction.

The process of optimizing stimulation treat-ments uses oriented perforations to increase the efficiency of pumping operations, reducetreatment failures and improve fracturing effec-tiveness. Completion engineers also developoriented-perforating strategies that prevent sandproduction and enhance well productivity byperforating to intersect natural fractures orpenetrate sectors of a borehole with minimalformation damage.

Maximum and minimum horizontal stressesand vertical stress from overburden describe in-situ stress conditions in oil and gas reservoirs.Hydraulic fractures initiate and propagate alonga preferred fracture plane (PFP), which is the pathof least resistance resulting from differences indirection and magnitude of formation stresses. Inmost cases, stress is greatest in the verticaldirection, so the PFP is vertical and lies in thedirection of the next greatest stress, the maxi-mum horizontal stress.

Perforations that are not aligned with themaximum stress tend to produce complex flowpaths near a wellbore during hydraulic fracturingtreatments. Fluids and proppants must exit well-bores, and then turn in the formation to alignwith the PFP. This “tortuosity” causes additionalfriction and pressure drops that increase pump-ing horsepower requirements and limit fracturewidth, which can result in premature screenoutfrom proppant bridging and, consequently, lessthan optimal stimulation treatments.

Orienting perforations with the PFP allowscompletion engineers and providers of pumpingservices to focus on stimulation designs andtreatment procedures that generate optimal frac-ture initiation, fracture propagation, proppantplacement and final fracture geometry—width,length, height and conductivity—instead of fluidflow right at the wellbore.

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In some weakly consolidated formations orcompetent rock with high contrasts between ver-tical and horizontal stresses, formation failure atthe perforations causes sand to be produced. Inaddition, because reservoir rock must supportmore overburden as fluids are produced and porepressure decreases, perforation tunnels maycollapse as a formation compresses. Targetingperforations in the most stable directions withminimum stress contrasts often mitigates sandproduction by reducing flowing pressure drops,changing flow configurations and creating moreeven stress distributions around wellbores.

In vertical wells, perforations can be shot in any direction, but are essentially horizontal. In high-angle and horizontal wells or verticalwellbores through steeply inclined formations,random radial perforations can be at variousorientations in the target zone, depending onwellbore inclination and formation dip.

Perforations on the high side of horizontalwells often are more stable and less likely tobreak down or become plugged by debris.Perforations can be targeted slightly away fromvertical for optimal shot density and spacing inorder to increase productivity, reduce pressuredrop and minimize sand production. For the samereasons, perforations in vertical wells can bealigned a few degrees away from the PFP.

This article reviews techniques to determineformation stress directions and discusses TCPand wireline systems for oriented perforating.Case histories from North America, the NorthSea, South America and the Middle East demon-strate the benefits of oriented perforating for pro-duction enhancement in reservoir-stimulationand sand-prevention applications. We also dis-cuss equipment improvements and factors driv-ing development of new systems to enhanceperforating capabilities and reduce the cycle timeof hydraulic fracturing or screenless completions.

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Earth Stresses From rock-mechanics principles, we know thathydraulic fractures propagate in the direction ofmaximum horizontal stress (SH). When perfora-tions are not oriented with the maximum stress,fractures travel from the tunnel base or tiparound casing and cement, or turn out in theformation to align with the PFP. This realignmentcreates complex near-wellbore flow paths,including multiple fracture-initiation points;competing fractures possibly continuing farafield; microannulus pathways with pinch-pointrestrictions; and fracture wings that are curved or poorly aligned with the wellbore and perfor-ations (left).

Laboratory tests indicate that breakdown, orcollapse, of perforation tunnels contributes to theonset of sand production from weakly consoli-dated reservoirs or formations with large stresscontrasts.1 Various factors contribute to sand pro-duction, including rock strength, magnitude anddirection of formation stresses, changing flowrates, increasing stress related to pressure draw-down or reservoir depletion, and water influxover time. Perforations properly aligned withrespect to the maximum formation stress aremore stable than those in other orientationsaround a wellbore (below left).

By determining in-situ stress magnitudes anddirections, completion engineers design perforat-ing strategies for oriented fracturing that targetthe preferred fracture-propagation direction. Inscreenless completions, they target more stablesectors of the formation around a wellbore withlower stress contrasts to prevent or delay sandproduction. Methods for determining stress magnitudes and orientations range from access-ing existing rock catalogs and interpreting bore-hole-imaging logs to building geomechanicalearth models and conducting vertical seismicprofile (VSP) surveys (see “Well-PositionedSeismic Measurements,” page 32 ).

18 Oilfield Review

Pinch points

Perforations

CementBorehole

CasingCharges at 90° phasing

Preferred fractureplane (PFP)

Maximumhorizontalstress (SH)

PFP

Minimum horizontalstress (Sh)

SH

Sh

90°

> Stimulation considerations. Fracture initiation can occur at various discrete points around a wellboreif perforations are not aligned with the preferred fracture plane (PFP), or maximum horizontal stress(SH). These scenarios result in complex flow paths, or tortuosity, that increase formation-breakdownand fluid-friction pressures during hydraulic fracturing treaments. Perforations close to the PFP, whichis the path of least resistance, minimize or eliminate near-wellbore restrictions. Properly aligned perfora-tions, perpendicular to the minimum horizontal stress (Sh), are essential for stimulation optimization andoriented fracturing.

Unstable, ineffectiveperforations

60°

60°

Unstable, ineffectiveperforations

Stable, effectiveperforations

Borehole

CementCasing

Stable, effectiveperforations

Charges at 60° phasing

Maximumhorizontalstress (SH)

Minimum horizontalstress (Sh)

SH

Sh

> Sand-management considerations. In weakly consolidated reservoirs and formations with largestress contrasts created by complex tectonic environments, perforations that target a minimum-stressplane in stable sectors around a wellbore help reduce or eliminate perforation failure and subsequentsand influx. By maximizing perforation-tunnel stability in a formation, oriented perforating plays a keyrole in screenless completions that prevent sand production.

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Drilling-induced fractures in openhole typi-cally form in the maximum horizontal stressdirection, along the PFP; borehole breakoutoccurs as stress concentrations near the holewall exceed formation strength and small piecesof rock break off while drilling (above). The borehole elongates in the minimum stressdirection (Sh), which is 90º from the PFP. Variousopenhole logging tools help operators determinestress directions prior to perforating.

The DSI Dipole Shear Sonic Imager tool mea-sures compressional and shear-wave traveltimesand provides accurate in-situ measurements toestablish local stress gradients and directions,and mechanical formation properties such asPoisson’s ratio and Young’s Modulus of elasticity(right).2 Fracturing design programs likeFracCADE software and other petrophysical mod-els use this information to optimize and evaluatefracturing stimulation treatments, and to predictsand production.

1. Venkitaraman A, Behrmann LA and Noordermeer AH:“Perforating Requirements for Sand Prevention,” paper SPE 58788, presented at the SPE InternationalSymposium on Formation Damage Control, Lafayette,Louisiana, USA, February 23–24, 2000.

2. Brie A, Endo T, Hoyle D, Codazzi D, Esmersoy C, Hsu K,Denoo S, Mueller MC, Plona T, Shenoy R and Sinha B:“New Directions in Sonic Logging,” Oilfield Review 10,no. 1 (Spring 1996): 40–55.

GRAPI0 200

Closure Stresspsi/ft

Water

Moved Hydrocarbon

Moved Water

Oil

Calcite

DPR 400

Fracture Height

DPR 800

DPR 1200

DPR 1600

Quartz

Illite

Bound Water

Gamma Ray (GR)

12,000 4.31

4.31

4.31

4.94

4.71

4.71

4.66

4.66

4.66

4.66

4.63

4.63

4.63

4.63

4.62

4.62

0.285398

5401

5405

5409

5412

5416

5419

5423

5427

5430

5434

5437

5441

5445

5448

5452

5455

5459

5463

5466

5470

5473

0.28

0.28

0.24

0.22

0.22

0.20

0.20

0.20

0.22

0.22

0.22

0.22

0.22

0.27

0.27

0.689

0.689

0.689

0.605

0.547

0.547

0.532

0.532

0.532

0.547

0.547

0.547

0.547

0.547

0.666

0.666

12,050

12,100

12,150

API0 200Porosityft3/ft31 0

Volumetricvol/vol0 1

GR

Depth1 : 24 ft

Pore Pressurepsi

Young's Modulus(YM)

Poisson's Ratio(PR)

API0 200YM FracCADE

MMpsi0 10PR FracCADE

MMpsi0 0.5PR Log

0 0.5YM LogMMpsi MMpsi0 10

Closure Stress - Zonedpsi/ft0 1

Delta Pressure (DPR)psi0 2000

DPR 400psi0 2000

DPR 800psi0 2000

DPR 1200psi0 2000

DPR 1600psi0 2000

psi/ft0 1Closure Stress Gradient

> Formation-stress evaluation. The DSI Dipole Shear Sonic Imager log is one of the most important for-mation-evaluation techniques for determining stress magnitudes and orientation. Engineers use theDSI tool to estimate stress profiles and formation mechanical properties. Data obtained from this log,such as Poisson’s ratio and Young’s Modulus (Tracks 4 and 5), are used in stimulation modeling pro-grams like the FracCADE software to estimate fracture height, and to design, optimize and evaluatefracturing treatments.

Borehole

Maximumhorizontalstress (SH)

Minimum horizontalstress (Sh)

Borehole breakout

Drilling-inducedfractures

SH

Sh

< Borehole deformation during drilling. Breakoutis a form of borehole failure. As drilling bits pene-trate a formation, stress concentrations at or nearthe hole wall exceed the rock’s strength, andpieces of formation fall or erode off along a 45°angle between the maximum and minimum stressdirections. The resulting failure planes coalesceand cause a hole to elongate in the direction ofminimum stress, perpendicular to the maximumstress, or PFP. Borehole elongation is one of thebest indications of stress direction becausebreakouts form in direct response to in-situ con-ditions. If hydrostatic pressure is high enough,the drilling process also induces shallow frac-tures in openholes. These drilling-induced frac-tures occur in the direction of maximum horizon-tal stress, typically propagating vertically up anddown the hole. Natural fractures usually have anassociated dip angle, and can be differentiatedfrom induced fractures on borehole-imaging logs.

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In crossed-dipole mode, the DSI tool deter-mines PFP orientation by detecting shear-waveanisotropy, which often results from differencesin maximum and minimum horizontal stressdirections. Acoustic anisotropy can be intrinsic orstress-induced. Intrinsic anisotropy can becaused by bedding, microstructure or aligned nat-ural fractures. Stress-induced anisotropy resultsfrom depositional conditions and tectonic forces.Borehole-imaging logs help distinguish betweenintrinsic and stress-induced anisotropy.3

In conductive water-base fluids, the FMIFullbore Formation MicroImager tool generates acircumferential electrical image of the boreholewall and provides quantitative information foranalysis of fractures. Engineers use this tool tovisualize drilling-induced fractures and boreholebreakouts, and to establish their orientation(right). This FMI log reveals wellbore breakout inthe upper part of the image and drilling-inducedfractures in the lower section.4

Like the FMI tool, the UBI Ultrasonic BoreholeImager tool provides circumferential boreholeimages. However, because it generates acousti-cal rather than electrical images, the UBI tool canbe run in nonconductive oil-base fluids to charac-terize drilling-induced fractures and boreholebreakout (below right). Oriented four-arm calipersurveys also provide an indication of boreholebreakout, but do not offer circumferential bore-hole coverage like the DSI, FMI and UBI loggingtools. The GVR GeoVision Resistivity tool providescomplete circumferential borehole-resistivityimages while drilling with conductive fluids.5

20 Oilfield Review

3. Armstrong P, Ireson D, Chmela B, Dodds K, Esmersoy C,Miller D, Hornby B, Sayers C, Schoenberg M, Leaney Sand Lynn H: “The Promise of Elastic Anisotropy,” OilfieldReview 6, no. 4 (October 1994): 36–47.

4. Serra O: Formation MicroScanner Image Interpretation,SMP 7028. Houston, Texas, USA: SchlumbergerEducational Services, 1989.Peterson R, Warpinski N, Lorenz J, Garber M, Wolhart Sand Steiger R: “Assessment of the Mounds DrillCuttings Injection Disposal Domain,” paper SPE 71378,presented at the SPE Annual Technical Conference andExhibition, New Orleans, Louisiana, USA, September 30–October 3, 2001.

5. Bonner S, Bagersh A, Clark B, Dajee G, Dennison M, Hall JS, Jundt J, Lovell J, Rosthal R and Allen D: “A NewGeneration of Electrode Resistivity Measurements forFormation Evaluation While Drilling,” Transactions of the SPWLA 35th Annual Logging Symposium, Tulsa,Oklahoma, USA, June 19–21, 1994, paper OO. Bonner S, Fredette M, Lovell J, Montaron B, Rosthal R,Tabanou J, Wu P, Clark B, Mills R and Williams R:“Resistivity While Drilling—Images from the String,”Oilfield Review 8, no. 1 (Spring 1996): 4–19.

7520

90°

7530

Boreholebreakout

dip

Induced-fracture

dipPad 1

azimuth

Calipers 2–4

Calipers 1–3

Gamma ray

Borehole breakout isperpendicular to

drilling-induced fractures

7510

E S WN NDepth, ft

> Microresistivity imaging. In conductive water-base drilling fluids, engineersuse FMI Fullbore Formation MicroImager images to determine the orientationof borehole deformations such as breakout and induced fractures. This FMIlog example shows both anomalies, which appear as low resistivity, or darkbrown features. Borehole breakout in a north-south orientation is shown inthe upper section, and drilling-induced fractures in an east-west orientationare shown in the lower section. As expected, these events are 90° apart.

4

2

2

0

0Borehole radius, in.

Images Versus Depth

-2

-2-4

4

-4

Breakout

Breakout

Depth X66.7m

Hole deviation 37.7 degrees

Breakout 138.0 degrees N111.2 degrees top0.8 in.

X066

X067

X068

Top N

> Sonic imaging. The UBI Ultrasonic Borehole Imager tool uses a pulse-echo reflection measurementto provide high-resolution images of hole size and shape in nonconductive oil-base drilling fluids (left).Breakout caused by compression failures at the borehole wall result in elongation of the hole in thedirection of minimum stress, perpendicular to the maximum stress direction and preferred fractureplane (right).

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Oriented Perforating The first applications of oriented perforatingwere in wells with dual or multiple tubingstrings. Tools were developed to ensure thatguns run in one string of tubing do not perforateother tubulars in a wellbore. Until recently, wire-line perforating options for these types of wellswere limited to systems like the SchlumbergerMechanical Orienting Device (MOD) and PoweredOrienting Tool (POT).

With the MOD system, it is safe to perforatewhen a spring-loaded caliper measures the fullinside diameter (ID) of the casing. The POT sys-tems are motorized tools with sensors thatprovide real-time data as the gun string isrotated. Perforating charges are directed 180°from the caliper or aligned with a specific sensor(left). The POT-B includes a shielded gamma-raydetector to locate radioactive sources run con-currently in other tubing strings. The POT-C useselectromagnetic principles to detect metal innearby tubing or casing strings. The POT-C wasdeveloped primarily for detecting adjacent com-pletions cemented in a single openhole, but ithas also been used successfully inside casingwith two strings of tubing.

In the past, operators frequently used tubing-conveyed systems for oriented perforating.However, these operations can be more complexand costly than wireline conveyance, particularlyif the well is vertical, the target interval is rela-tively short, and perforating is performed with

wellbore hydrostatic conditions equal to forma-tion pressure. For high-angle and horizontalwells, passive oriented-perforating systems forwireline-, tubing- and coiled-tubing conveyanceuse eccentric weights and swivels to orient gunstrings relative to the low side of a wellbore withperforating charges facing upward (above).

New technology is available to accuratelyalign TCP guns across long intervals in deviatedwellbores. This OrientXact system includes pas-sive orienting weights and gun sections joined byroller-bearing swivels that handle high loads.This system orients gun sections longer than1000 ft [300 m] to accurately shoot within 10°of a predetermined direction, such as the highside of an inclined wellbore. An innovativeOrientation Confirmation Device (OCD) measuresand records perforating direction within 1°,which provides valuable data about perforationorientation after retrieving the gun string.

In vertical wells, TCP techniques use gyro-scopes instead of passive orientation by gravityto orient perforations. A gyroscope is run throughtubing on wireline and seated in an orienting pro-file that includes an internal key that is alignedwith the gun charges. The tubing string is rotatedfrom surface to a required orientation, and thepacker is set hydraulically to avoid additionalrotation. Gun orientation is verified by the gyro-scope before it is removed to prevent damagefrom perforating shocks.

Mechanical OrientingDevice (MOD)

Spring-loadedcaliper

Casing

Tubing

Powered OrientingTool (POT) B or C

Maximum metal

Tool

rota

tion

Minimum metalTowardadjacent

pipe

Awayfrom

adjacentpipe

> Orienting techniques. The Mechanical Orient-ing Device (MOD) and Powered Orienting Tool(POT) were developed to perforate wells withdual or multiple tubing strings. Operators usethese tools to ensure that guns run in one stringof tubing do not perforate other production tubu-lars in a wellbore.

BoreholeEccentric, weighted

spacersCasing

Cement

Vertical perforations,0° phasing

Charge

Perforation

Gravity Gravity

0°

Swivel

> Orienting by gravity. Passive orientation for wireline-, tubing- and coiled tubing-conveyed perforat-ing uses eccentric weighted spacers in combination with ballistic-transfer and tubing swivels, relyingon gravity to orient guns on the low side of a wellbore. This technique requires a directional survey of the well.

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When stress directions are not known or ori-ented perforating is not possible, guns with ahigh shot density and 60 or 120° phasing helpensure that at least some perforations will liewithin 25 to 30° of the maximum stress direction.However, this random approach requires addi-tional shaped charges and does not ensure thatperforations are closely aligned with the PFP orminimum stress contrast.

The Schlumberger Wireline OrientedPerforating Tool (WOPT) system, which can berun in vertical and inclined wells, is the latestmethod for orienting wireline guns (below left).The WOPT system, developed initially for ori-ented fracturing, also is deployed to perforate forsand prevention. This tool orients standard HSDHigh Shot Density guns with 0°, 180° or otheroptimal phasing in a predetermined direction.Charge type and shot density depend on comple-tion requirements such as sand control or sand

prevention, and on fracture-design criteria suchas proppant size, pump rates, treating pressuresand required production flow.6

This technique relies on the fact that at agiven depth, wireline tools assume a preferredorientation in a wellbore when string parame-ters—length, weight, mass distribution, cablespeed and direction—are constant, and a swivelis used to minimize the detrimental steeringeffects of torque. The swivel decouples torsion

22 Oilfield Review

Wirelineswivel

Gyroscopecarrier

HSD HighShot Densitygun, 180°phasing

Wireline PerforatingInclinometer Tool

(WPIT) and casing-collar locator (CCL)

Upper weightedspring-positioning

device (WSPD)

Upper indexingadapter

Lower indexingadapter

Lower weightedspring-positioning

device (WSPD)

HSD gun

Casing

Charges

Charges

Initial Gyroscope Run

Relative bearing, 0°

Casing

Perforating Run

Relative bearing, 0°

PFP

PFP HSD gun

>Wireline-oriented perforating. A typical Wireline Oriented Perforating Tool(WOPT) system is configured with a weighted spring-positioning device(WSPD) and indexing adapter above and below standard 0°- or 180°-phasingguns (left). The tool string includes a gyroscope and carrier, an integral Wire-line Perforating Inclinometer Tool (WPIT) with casing-collar locator (CCL) anda wireline swivel to decouple cable torque from the tool. The gyroscope mea-sures well inclination, wellbore azimuth and toolface relative bearing—orien-tation of the tool string—with respect to true north during an initial run withunarmed guns (top right). Perforating is performed on subsequent trips asneeded without the gyroscope and after rotating, or reindexing, the guns atsurface (bottom right). The WPIT remains in a tool string at all times to inde-pendently measure tool deviation and toolface relative bearing, and confirmthat a tool string repeats the previously established orientation.

12,040

Depth, ftWell

SketchLow High

Horizontal Scale: 1:9.153Orientation North

Amplitude360 240 120

degrees

Sonde/Hole Deviation

0 9

0

12,050

12,060

12,070

12,080

12,090

12,100

12,110

12,120

12,130

12,140

12,150

degrees

Sonde/Hole Azimuth

0 360

Gun run 1

Gun run 2

Gun run 3

Gun run 4

> Verifying perforation orientation. After perforating, an oriented USIUltraSonic Imager log can be run to confirm that perforations are in thecorrect orientation. In this USI image, perforations appear as thin linesbecause of the measurement scale (Track 3). The required perforationdepths are shown on the well sketch in Track 2. This well was perfo-rated in four separate gun runs using 180° phasing and 2 shots per foot(spf)—a total of 118 holes—oriented northeast-southwest. Well incli-nation was about 1.7°, but the WOPT has been used in wells with incli-nations as low 0.3°.

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Spring 2002 23

between the wireline cable and a gun string,which allows the tool to assume its preferential,or natural, position. The observed repeatability ofthis “natural lie” was a key in developing theWOPT tool. The WOPT requires two trips forvertical wells with inclinations less than 8°.Perforating wellbores with less than 1° of incli-nation requires extra care during job executionand may require additional time to complete.

The first trip, or “mapping” run, is made withunarmed perforating guns and a true-north-seeking gyroscope to determine the naturalorientation—toolface azimuth, or direction—of the tool string. Upper and lower weightedspring-positioning devices (WSPD) help rotate tool strings toward the relative low side of a wellbore.

Several passes in each direction ensure accu-rate orientation data to determine the requiredgun rotation, or “indexing,” for oriented perforat-

ing. Single or multiple zones can be mappedduring this initial trip. The Wireline PerforatingInclinometer Tool (WPIT), an integral WOPT com-ponent, provides independent, continuous andreal-time measurements of tool deviation andtoolface orientation—relative bearing—withrespect to the high side of a wellbore.

If reliable directional-survey data are avail-able and target zones are in well sections withinclinations greater than 8°, oriented perforatingcan be completed without a gyroscopic run. Inthis case, inclination measurements areextremely accurate and correlate to wellboreazimuth. After toolface azimuth is determined,guns are rotated manually at the surface in 5°increments using indexing adapters above andbelow the guns to orient the charges. The gyro-scope is removed before perforating to avoidshock damage during perforating. The carrierwith a dummy gyroscope and the WPIT remain inthe WOPT system to maintain tool-string lengthand mass.

The WOPT gun string is then run back into the well. Relative-bearing data from the WPITconfirm that the previously established toolorientation repeats. The well is perforated oncegun orientation and depth are verified by repeat-analysis log (above). The WOPT system can accu-rately align perforations within 5° of the requiredazimuth. Because of the need to maintain con-stant tool-string parameters, a current limitationof the WOPT system is the inability to selectivelydetonate more than one gun per run. In verticalwells, a spent gun would alter the previouslyestablished preferential tool orientation.

Operators have run the USI UltraSonic Imagertool to verify that perforations are correctly alignedin the desired direction (previous page, right).

6. Venkitaraman et al, reference 1. Behrmann LA and Nolte KG: “Perforating Requirementsfor Fracture Stimulations,” paper SPE 39453, presentedat the SPE International Symposium on FormationDamage Control, Lafayette, Louisiana, USA, February18–19, 1998.

Alpha X Tiltdegrees

Alpha Y Tiltdegrees

Sonde/HoleDeviation

Relative Bearing Repeat Curve

CCL Repeat Curve

Sonde/Hole Deviation Repeat Curve

-180 degrees 180

0 degrees 20

RelativeBearing

Depth,ft

1.61.61.7

1.61.6

1.61.6

1.91.7

1.41.51.51.3

0.41.1

1.91.61.82.01.8

29.7

1.5

-7.7-0.8

-10.1

-8.9-13.0

-9.2-16.5

-15.7-6.4

-10.4-12.9

-3.4-4.6

-54.6-48.1

-34.8-35.0-40.3-33.9-42.8-46.8

-6.9

Relative Bearing Repeat-180 degrees 180

X Tilt Repeat Curve-25 25degrees

Y Tilt Repeat Curve-25 25degrees

Log into position

-1.6-1.6-1.7-1.5-1.5

-1.6-1.5

-1.9-1.6

-1.4-1.5-1.5-1.2

-0.2-0.7

-1.5-1.3-1.3-1.6-1.3

-19.7

-1.5

-0.2-0.0-0.3-0.2-0.3

-0.3-0.4

-0.5-0.2

-0.2-0.3-0.1-0.1

-0.3-0.8

-1.1-0.9-1.1-1.1-1.2

-21.0

-0.2

11,700Perforate

> Verifying gun orientation. After perforating guns are oriented at the surface, the WOPT system is run back in the well without a gyroscope. The WPIT remains in the string to record a real-time, repeat-analysis log. If the toolface relative bearing (Track 1) on subsequent runs matches the initial run, a gun string is repeating the previously established preferential orientation. Tilt signals (Track 3) areused when relative bearing is undefined because of extremely low wellbore inclination angles. Whentool-string orientation does not repeat, guns are pulled and reindexed accordingly.

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Post-perforating surveys indicate that perfora-tions are consistently within about 10° of therequired azimuth. The WOPT system has suc-cessfully perforated wells with inclinations from0.3° to 58°. Operators accepted the concept oforienting perforations to improve hydraulic frac-turing efficiency and effectiveness, but considered it impractical before the introductionof the WOPT system.7

Hydraulic Fracturing Perforating is an essential, but often-overlookedaspect of hydraulic and acid fracturing treat-ments. Hole size, shot density, penetration, gunphasing and perforation orientation all are important. Neglecting any of these parameterscan lead to a screenout, which is detrimental tolong-term production, adding completion costsfor additional rig time and equipment to clean outwellbores as well as wasting expensive stimula-tion fluids and proppants. A premature screenoutusually results in less than optimal stimulationsand also can make refracturing more difficult inthe future.

In any case, production response usually isless than expected because of incomplete zonalcoverage, shorter fracture length and lower frac-ture conductivity. To deal with friction pressurefrom misaligned perforations and near-wellboreflow restrictions, operators often resorted toincreased pump rates and pressures, higherviscosity fluids that are more damaging, prestim-ulation breakdown with acid, reperforating andproppant slugs pumped during early stages of atreatment to erode restrictions. All of thesemethods add incremental cost and, depending onexisting wellbore and formation conditions, havequestionable effectiveness.

24 Oilfield Review

Perforations

CementBorehole

Casing

Preferred fractureplane (PFP) PFP

180°

Charges at 180° phasing

Maximumhorizontalstress (SH)

Minimum horizontalstress (Sh)

SH

Sh

Multiple initiation pointsand annular fractures

Misalignedperforations

Properly alignedperforations

Singlebiwing fracture

> Optimizing hydraulic fracturing. Orienting perforations in the direction of maximum horizontalstress improves the efficiency and effectiveness of reservoir-stimulation treatments. Perfora-tions aligned with the PFP reduce or eliminate near-wellbore tortuosity and flow restrictions(top). In full-scale fracture-initiation laboratory tests on formation blocks under triaxial stress,perforations in the PFP resulted in a dominant single or biwing fracture with minimal tortuosityand reduced injection pressures (bottom left). In the same tests, perforation misalignmentresulted in multiple competing fractures that initiated at various points on the wellbore radiusand traveled around the cement-formation interface (bottom right).

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Spring 2002 25

Formation stresses control hydraulic fractureinitiation and propagation. Perforations alignedwith the maximum stress direction optimize theimpact and effectiveness of fracture-initiationand fracture-propagation pressures by maximiz-ing the number of holes open to a hydraulic frac-ture and allowing fluids to flow directly into thepath of least resistance—the PFP (previouspage).8 When perforations are not properlyaligned in the stress field, flow-path tortuosityincreases fracture-initiation and fluid-frictionpressures during pumping operations. Theselosses dissipate hydraulic energy, which limitsfracture geometry and increases the horsepowerrequired to pump stimulation treatments. Theconsequences are possible premature screenout,reduced final proppant concentrations and vol-umes, and higher job costs.

An oriented perforating and fracturingstrategy minimizes or eliminates near-wellborepressure losses. Fracturing design and implemen-tation can focus on creating wide, conductivefractures and transporting proppant rather thanfluid flow in the near-wellbore region.9 This alsoallows completion engineers to design moreaggressive fracturing programs with higher con-centrations or larger sizes of proppant and lessviscous, nondamaging fluids like ClearFRACviscoelastic systems to improve fracture conduc-tivity and well productivity.

Oriented perforating also helps optimizestimulation treatments when operations areconstrained by pressure or pump-rate limitationsand restrictions on fluid and proppant volumes.These applications include wells with smallertubing and coiled tubing-conveyed CoilFRACselective stimulations.10

In addition to new opportunities for fracturingwith coiled tubing, oriented perforating can elim-inate the need to pump down tubing and protectcasing from excessive injection pressures, partic-ularly in formations that are difficult to treatbecause of high breakdown pressures. In somecases, lower fracture-initiation and fracture-propagation pressures make it possible to pumpdown casing, which reduces the cost and com-plexity of fracturing through premium-grade,high-strength tubing.

In March 2000, Louis Dreyfus Natural Gas Inc.(now Dominion Exploration and Production Inc.)drilled Well ETA-4 in southeast New Mexico,USA (above right). No pressure data were avail-able, but a bottomhole pressure of 2000 psi [13.8 MPa] was measured in an offset well.Wireline logs identified a homogeneous, high-quality, 10-ft [3-m] zone in the Morrow formation

with about 14% porosity and 20% water satura-tion. Rotary sidewall cores verified these values.A zone of this quality should produce naturally,but high permeability and low pressure make theformation susceptible to drilling- and completion-fluid damage. Significant separation betweenresistivity curves confirmed deep invasion, so theoperator wanted to design a fracture stimulationto bypass the damage.11

Early fracture stimulations with water-basefluids in this formation were marginally success-ful because these gas sands are low pressureand potentially water sensitive, with a widerange of permeabilities. If possible, wells arecompleted naturally without stimulation, butthose in low-permeability areas of the reservoirmust be hydraulically fractured, often withmarginal results. Operators approach Morrowstimulation treatments cautiously. To addresswater sensitivity and avoid a screenout, lessviscous foam fluids with low proppant concen-trations that yield narrow, low-conductivityfractures are frequently used.

Studies suggested that poor results were dueto water-sensitive clays or capillary-pressureeffects that reduce permeability when zones areexposed to fracturing fluids. Low reservoir pres-sure exacerbates capillary effects. These issueswere addressed by pumping nitrogen [N2] orcarbon dioxide [CO2] energized treatments andusing methanol in fracturing fluids. However,stimulation results with foam systems have beeninconsistent. In higher permeability zones, smallfracturing treatments using foams effectivelybypass near-wellbore damage, but in lower per-meability zones where fracture length is criticalfor optimal productivity, results with foam sys-tems are inconsistent.

These treatments address water sensitivity,but low viscosity, high friction pressure andchemical requirements increase costs and therisk of screenout. Lower proppant concentrationsand frequent premature screenout leave wellsproducing considerably below their full potential.Fracture-treatment designs that develop ade-quate hydraulic width and transport higher con-centrations and volumes of proppant wereneeded to maximize production.

Reservoir quality in the ETA-3 well, com-pleted two months earlier, was similar to that ofthe ETA-4 well, but with half as much pay. Thisoffset well was perforated conventionally with 4-in. carrier guns with 4 shots per foot (spf) at 60° phasing and fracture stimulated down 5-in.casing with CO2 foam and high-strength, man-made ceramic proppant. Surface treating pres-sure was 5000 psi [34.4 MPa] with a maximum

proppant concentration of 4 pounds of proppantadded (ppa). Increasing pressure near the end of the job indicated a possible screenout. Post-stimulation production stabilized at 1.7 MMscf/D[48,700 m3/d] and 500-psi [3.4-MPa] flowing tub-ing pressure (FTP) at surface.

7. Pearson CM, Bond AJ, Eck ME and Schmidt JH: “Resultsof Stress-Oriented and Aligned Perforating in FracturingDeviated Wells,” paper SPE 22836, presented at the SPE Annual Technical Conference and Exhibition, Dallas,Texas, USA, October 6–9, 1992. Pospisil G, Carpenter CC and Pearson CM: “Impacts of Oriented Perforating on Fracture Stimulation Treat-ments: Kuparuk River Field, Alaska,” paper SPE 29645,presented at the SPE Western Regional Meeting,Bakersfield, California, USA, March 8–10, 1995.

8. Behrmann and Nolte, reference 6. 9. Nelson DG, Klins MA, Manrique JF, Dozier GC and

Minner WA: “Optimizing Hydraulic Fracture Design inthe Diatomite Formation, Lost Hills Field,” paper SPE36474, presented at the SPE Annual TechnicalConference and Exhibition, Denver, Colorado, USA,October 6–9, 1996. Manrique JF, Bjornen K and Ehlig-Economides C:“Systematic Methodology for Effective Perforation andFracturing Strategies,” paper SPE 38630, presented atthe SPE Annual Technical Conference and Exhibition,San Antonio, Texas, USA, October 5–8, 1997. Manrique JF and Venkitaraman A: “OrientedFracturing—A Practical Technique for ProductionOptimization,” paper SPE 71652, presented at the SPEAnnual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 30–October 3, 2001.

10. For more on CoilFRAC coiled tubing-conveyed selectivestimulations: Degenhardt KF, Stevenson J, Gale B,Gonzalez D, Hall S, Marsh J and Zemlak W: “Isolate andStimulate Individual Pay Zones,” Oilfield Review 13, no. 3(Autumn 2001): 60–77.

11. Logan WD, Gordon JE, Mathis R, Castillo J and McNally AC:“Improving the Success of Morrow Stimulations the Old-Fashioned Way,” paper SPE 67206, presented at the SPEProduction Operations Symposium, Oklahoma City,Oklahoma, USA, March 24–27, 2001.

New Mexico

CANADA

USA

> Morrow fracture stimulations. Many differentwell-completion and fracturing strategies havebeen attempted in the Morrow gas-sand reser-voirs of southeast New Mexico, USA.

51381schD2R1.p25.ps 04/24/2002 07:52 PM Page 25

The operator decided to use theSchlumberger WOPT system to align 33⁄8-in. HSD High Shot Density gun systems with 6 spf at 180° phasing along the PFP. Using FMI logdata, engineers determined that the maximumstress direction was northwest to southeast inthe ETA-4 well. Higher proppant concentration—6 versus 4 ppa—to increase fracture width was possible because oriented perforatingreduced risk of premature screenout caused bynear-wellbore tortuosity.

Because reservoir quality was equivalent tothe ETA-3 well and the pay was twice as thick,the operator expected ETA-4 to be an excellentwell, but production after perforating was only500 Mscf/D [14,300 m3/d] with 220-psi [1.5-MPa]FTP. This rate was equivalent to an extremelydamaged completion with a positive 45 skin. Totake full advantage of reservoir quality, the oper-ator wanted to design a more conductive fracture

using a higher proppant concentration. However,fracture-treatment pressures in the offset wellindicated a possible screenout at 4 ppa, so thiswould not be easy.

At 6 ppa, the FracCADE simulation shows afracture half-length of 300 ft [91 m] and a widthof 0.15 in. [3.8 mm], more than twice as wide asa 4-ppa design (below). This treatment appearsover-designed, but local experience suggeststhat a 300-foot design target may be necessaryto obtain an effective 200-ft [60-m] conductivefracture, considering the potential for fracture-conductivity damage after the fracture closes andproduction begins.

Treatment pressures highlight the positiveimpact of oriented perforations on job execution(next page, top left). Pump rates for the two stim-ulation treatments are identical at 30 bbl/min [4.7 m3/min], but the conventional fracturestimulation had a treating pressure of 5000 psi,

while pressures for the oriented fracturing treat-ment range between 3000 and 4000 psi [20 and27 MPa].

Another important indicator of the benefits oforiented perforating is pressure response afterpumping stops. On the conventional job, it took15 minutes for pressure to reach 3000 psi, sug-gesting that net pressure was increasing and thisjob was close to screenout. For the oriented frac-ture, pressure stabilized almost immediately,suggesting that higher proppant concentrationscould have been placed.

Early production history for Well ETA-4 indi-cated a successful stimulation. Post-fractureproduction was 3.5 MMscf/D [1 million m3/d]with 1280-psi [8.9-MPa] FTP compared with 500 Mscf/D and a flowing pressure of 220 psibefore stimulation. The goal was to bypassdrilling damage, so skin is a good measure offracturing success. The post-stimulation produc-tion rate of 3.5 MMscf/D indicates that skin wasreduced from 45 to –4.

Analysis showed that with 4-ppa maximumproppant concentration and 0.06-in. [1.5-mm]fracture width, the ETA-4 well should produce 2.2 MMscf/D [63,000 m3/d] at 1280-psi FTP. If thefracture width is 0.15 in., production increases to3 MMscf/D [85,000 m3/d] with 1280-psi FTP. Thewell actually produced more, suggesting aslightly wider fracture. Oriented perforatingallowed a higher proppant concentration to be used while avoiding premature screenout andthe need to clean out wells after fracturing. This resulted in an additional 1.3 MMscf/D[34,000 m3/d] and a three-day payout for incre-mental perforating costs.

In some areas, fracturing applications includecompletion objectives other than just fracturing toenhance productivity. Operated by Amerada Hess,the Scott field in the central North Sea UK sectoris subject to impaired productivity from scale andasphaltene deposits in and around the well-bores.12 Reperforating, injecting scale dissolvers,and creating short fractures with explosive pro-pellants were unsuccessful remedial treatmentsdue to the severity of this damage. A fracturestimulation, which is expensive in offshoreenvironments, was the only remaining option tobypass formation damage.

This challenge, however, encouraged investi-gation of new methods and novel technologies toensure success. A joint Amerada Hess andSchlumberger Production Enhancement Group(PEG) identified Well J9 as a fracture-stimulationcandidate based on existing production versuspotential productivity, drainage area, pressure

26 Oilfield Review

Dept

h, ft

Dept

h, ft

Stress, 1000 psi Fracture width at wellbore, in.

4 ppa

6 ppa

Fracture half-length, ft

Proppantconcentration

8 9 10 0.1 0 0 200 400 6000.1

0.1 0.10 0 200 400 600

< 0.0 lbm/ft2

0.0-0.10.1-0.2 0.2-0.3 0.3-0.4 0.4-0.5 0.5-0.6 0.6-0.7 0.7-0.8 > 0.8

< 0.0 lbm/ft2

0.0-0.1 0.1-0.2 0.2-0.3 0.3-0.4 0.4-0.5 0.5-0.6 0.6-0.7 0.7-0.8 > 0.8

X1900

X2000

X2100

X2200

X2300

X2400

X1900

X2000

X2100

X2200

X2300

X24008 9 10

Stress, 1000 psi Fracture width at wellbore, in. Fracture half-length, ft

Proppantconcentration

Greatest concentrationof proppant

Greatest concentrationof proppant

300-ft half-length

400-ft half-length

> Fracture conductivity. Oriented perforating is instrumental in the design and implementation of fracturingtreatments that generate wider, more conductive fractures. Alternative fracture designs for the ETA-4well had similar fracture half-lengths and fracture heights, but the fracture with 4 pounds of proppantadded (ppa) is less than half as wide (top) as the one with 6 ppa (bottom).

51381schD2R1.p26.ps 04/24/2002 07:52 PM Page 26

Spring 2002 27

support from a nearby injection well and well-bore access.13 Oil production peaked at 5700 B/D[906 m3/d], but declined steadily in spite ofincreasing reservoir pressure. Pressure in thefault block rose from about 4000 psi [27.6 MPa]to more than 9000 psi [62 MPa] after water injec-tion began.

A production log spinner survey and cased-hole caliper revealed that production wasprimarily from an upper zone and there waswater holdup as well as scale buildup acrosslower perforations. The operator suspected acombination of sulfate-scale buildup prevalent inother parts of the field, fines migration and pos-sible asphaltene deposition. Reperforating theentire interval had no effect on production.

Hydraulic fracturing was the only practicaloption remaining. However, the complex faultedstructure and extreme tectonic forces create con-ditions for potentially narrow hydraulic fracturesand possible premature screenout. High wellboredeviations further exacerbate near-wellborerestrictions and complicate fracturing operations.

A limited interval was reperforated using theWOPT system to align guns with 180° phasing inthe maximum stress direction to minimize pres-sure losses from fracture tortuosity. A PFPazimuth of 46° was obtained from shear-waveanisotropy, four-arm caliper measurements inopenhole and borehole-imaging logs. The opera-tor selected big-hole PowerFlow charges at 6 spfto reduce uncertainty about perforation align-ment with the PFP and minimize perforation

friction. This choice also helped ensure thewidest possible fracture to mitigate post-stimulation skin from flow turbulence duringsubsequent production.

Even with a wellbore azimuth across the tar-get interval of 40°, engineers estimated that ahydraulic fracture would propagate almost in-linewith the wellbore. Despite a favorable wellboreazimuth, Amerada Hess decided to mitigate thepossibility of a screenout due to narrow fracturewidth or multiple fractures near the wellbore.This was accomplished by reperforating only 10 ft and plugging back to reduce the injectioninterval, even though this could result in conver-gent, possibly turbulent, flow under producingconditions (above right).

Achieving adequate fracture conductivity andmaintaining productivity were major concernsgiven the high propensity for scale deposition inwellbores and the formation matrix. Hydraulicfracture treatments reduce pressure drops dur-ing production, which reduces the potential forscale deposits to form. In addition, a specialproppant impregnated with a scale-inhibiting

12. Norris MR, Gulrajani SN, Mathur AK, Price J and May D:“Hydraulic Fracturing for Reservoir Management:Production Enhancement, Scale Control and AsphaltinePrevention,” paper SPE 71655, presented at the SPEAnnual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 30–October 3, 2001.

13. For more on the Production Enhancement Group (PEG):Bartz S, Mach JM, Saeedi J, Haskell J, Manrique J,Mukherjee H, Olsen T, Opsal S, Proano E, Semmelbeck M,Spalding G and Spath J: “Let’s Get the Most Out ofExisting Wells,” Oilfield Review 9, no. 4 (Winter 1997): 2–21.

7000

8000

5000

6000

3000

4000

1000

0

2000

35

40

25

30

15

20

5

0

10

84 87

Pres

sure

, psi

Pum

p ra

te, b

bl/m

in

90 93 97 100 103Pump time, min

106 109 113 116 119 122 125 129

Treating pressure–conventionalTreating pressure–oriented

Conventional–4 ppa

Oriented–6 ppa

Pump rateETA-4 well,orientedPump rateETA-3 well,conventional

> Comparison of conventional and oriented fracture treatments. The mostsignificant improvement is in surface treating pressure. While proppant con-centrations increase from 1 to 4 ppa on offset Well ETA-3 and from 1 to 6 ppaon the ETA-4 well, treating pressures are significantly lower on the ETA-4 well(purple) than on the ETA-3 well (blue). This improvement resulted from orient-ing perforations with the maximum stress direction, or PFP.

> Fracturing high-angle wells. As wellbores turn away from the preferredfracture plane (bottom), the perforations should be oriented and clusteredover shorter intervals to optimize communication with one dominant fracture(middle). Because the wellbore azimuth was 40º and the PFP azimuth was46º, Amerada Hess elected to use this strategy to fracture stimulate theScott field J9 well in the North Sea (top) to reduce the possibility of a screenoutresulting from multiple fractures initiating near the wellbore and a correspond-ing narrow fracture width.

51381schD2R1.p27.ps 04/24/2002 07:52 PM Page 27

chemical was used to provide long-term protec-tion for the propped fracture and wellboretubulars. Placing inhibitor along with theproppant ensured distribution deep into theformation, and less inhibitor was lost whileflowing back and cleaning up treatment fluids.The scale inhibitor does not react with fracturingfluids and remains dormant on proppant surfacesuntil activated by formation water.

A step-rate injection test prior to fracturingindicated extremely low friction from near-wellbore tortuosity, only 200 psi [1.4 MPa] duringfracture initiation. The actual proppant treatmentalso exhibited negligible near-wellbore effectsand did not require acid or proppant slugs duringpad injection to break down the formation anderode restrictions. This indicated that orientedperforating eliminated flow restrictions, and thatopposing fracture wings were properly alignedwith the wellbore.

The combination of oriented perforating andfracturing with scale-inhibitor-impregnated prop-pant resulted in an increase in oil productionfrom 120 B/D [19 m3/d] to more than 2500 B/D[397 m3/d], a 20-fold improvement (above left).The fracture stimulation resulted in skin of –2compared with the pretreatment skin of 80. Thescale-inhibitor-impregnated proppant preventedthe rapid decline in productivity that the wellexhibited when originally placed on injectionsupport. Sustained high productivity resulted in a14-day payout for this intervention.

As a result of the treatment performed onWell J9, the PEG group initiated a candidate-recognition program to evaluate the potential forfracture stimulation of other wells in the Scottfield. This program is helping Amerada Hess offset declining field output and potentiallyrecover additional reserves. Oriented-fracturingstrategies and WOPT perforating techniques alsohave been applied successfully in Canada andthe Gulf of Mexico.

Sand Prevention Although sand-control methods are required inmany completions, restricted flow rates maymake mechanical screens and gravel packing forsand control impractical or uneconomical in high-productivity wells.14 In some weakly consolidatedreservoirs and formations with anisotropicstresses, oriented perforating and specializedscreenless technologies can maximize perfora-tion-tunnel stability and reduce or eliminate sandproduction without restricting well output (left). By determining in-situ stress magnitudes

28 Oilfield Review

14. Carlson J, Gurley D, King G, Price-Smith C and Walters F:“Sand Control: Why and How?” Oilfield Review 4, no. 4(October 1991): 41–53. Syed A, Dickerson R, Bennett C, Bixenman P, Parlar M,Price-Smith C, Cooper S, Desroches J, Foxenberg B,Godwin K, McPike T, Pitoni E, Ripa G, Steven B, Tiffin Dand Troncoso J: “High-Productivity Horizontal GravelPacks,” Oilfield Review 13, no. 2 (Summer 2001): 52–73.

15. Sulbaran AL, Carbonell RS and López-de-Cárdenas JE:“Oriented Perforating for Sand Prevention,” paper

Oil a

nd w

ater

pro

duct

ion,

B/D

4000

Janu

ary

Febr

uary

Mar

ch

April

May

June

July

Augu

st

Sept

embe

r

Octo

ber

Nov

embe

r

Dece

mbe

r

3500Pretreatment

Oil

Post-treatment

3000

2500

2000

1500

1000

500

0

Well J9 Production, Year 2000

Water

> North Sea stimulation success. The productivity of Amerada Hess’s Well J9 in the Scott field, a cen-tral North Sea development, increased as the result of an optimized fracture treatment that includedoriented perforating of a limited interval and injection of scale-inhibitor-impregnated proppant. Produc-tion rose from 120 B/D [19 m3/d] to more than 2500 B/D [397 m3/d] of sustained output. This interventionpaid out within 14 days.

Perforations

Chemical-inhibitortreatment

Formation or propped fracturecontaining scale-inhibitor preflush or

proppant impregnated with a scale inhibitor

Resin-coated proppant or sandheld in place by PropNET fibers

Screenless completion

CementBorehole

CasingCharges at 180° phasing

Fracture

Minimum horizontalstress (Sh)

Maximumhorizontalstress (SH)

SH

Sh

> Screenless completions. When combined with oriented perforating and fracturing strategies, noveltechnologies, such as resin-coated and scale-inhibitor-impregnated proppants (left), and PropNETfibers (right), control proppant flowback and sand production to provide effective sand preventionwithout downhole mechanical screens and gravel packing.

SPE 57954, presented at the SPE European FormationDamage Conference, The Hague, The Netherlands, May 31–June 1, 1999.

16. Solares JR, Bartko KM and Habbtar AH: “Pushing theEnvelope: Successful Hydraulic Fracturing for SandControl Strategy in High Gas Rate Screenless Comple-tions in the Jauf Reservoir, Saudi Arabia,” paper SPE73724, presented at the SPE International Symposiumand Exhibition on Formation Damage Control, Lafayette,Louisiana, USA, February 20–21, 2002.

51381schD2R1.p28.ps 04/24/2002 07:52 PM Page 28

Spring 2002 29

and directions, completion engineers target morestable areas of the formation around a well withminimum stress contrast and avoid less stablesectors with large contrasts between horizontaland vertical stresses.

Smaller diameter perforations, higher shotdensity, optimal gun phasing and maximum spac-ing between holes, and oriented perforating aidin preventing sand production from weakly con-solidated reservoirs. When high shot densitiesare required, gun phasing is adjusted to orientperforations slightly to either side of theminimum stress contrast direction to maximizeperforation-to-perforation spacing. This opti-mizes well productivity and helps prevent ordelay sand production throughout the life of awell. Geomechanical models and laboratory test-ing determine the acceptable deviation from atarget azimuth, typically about 25° to 30°, or less.

Using knowledge about the in-situ stress dis-tribution and directions from a detailed geome-chanical study, Petróleos de Venezuela S.A.(PDVSA) applied optimal phasing and orientedperforating to prevent sanding.15 Sand productionis a major problem in the Eocene C reservoir ofLake Maracaibo, Venezuela. This sandstone iscompetent and consolidated, but as a result ofcomplex tectonics, maximum horizontal stress issignificantly greater than the vertical stress,which is similar in magnitude to the minimumhorizontal stress. The large contrast betweenmaximum and minimum horizontal stresses gen-erates significant produced sand in vertical wells.

During the 1990s, PDVSA used several tech-niques, including hydraulic fracturing and high-angle drilling, to reduce sand production.Production averaged 1500 B/D [240 m3/d] perwell, but sand influx remained at about 14 lbm/1000 bbl [4 kg/100 m3] per well, whichwas still considered excessive. To address thisproblem, PDVSA turned to oriented perforatingfor sand prevention in vertical wells.

Faults and tectonic effects influence stressdirection variations in the Eocene C reservoir.PDVSA used borehole-image data and laboratorycore measurements to estimate maximumhorizontal stress directions. Investigators alsoevaluated the stability of a single perforation tun-nel using an elastic-plastic model, finite-elementanalysis and material-failure criteria. The criticalangle from the direction of maximum stress whereperforation tunnels remain stable was used toselect gun phasing and perforation orientation.

Geomechanical studies by PDVSA and exper-iments at the Schlumberger ReservoirCompletions (SRC) Center in Rosharon, Texas,USA, resulted in the following perforating strate-gies and recommendations: • Determine stress magnitudes and directions. • Define the critical angle at which perforations

are stable. • Select appropriate deep-penetrating PowerJet

charges. • Use sufficient shot density for optimal

productivity. • Use a shot phasing for maximum perforation-

to-perforation distance. • Avoid shooting in directions where perforation

tunnels are less stable. • Perforate with a sufficient pressure

underbalance. Initially, four jobs were performed using

oriented TCP techniques. In all of these wells,sand production was reduced significantly com-pared with the field average of more than 14 lbm/1000 bbl (above). Because of the sand-prevention success in these Eocene C wells,PDVSA performed additional oriented perforatingin other fields using TCP and WOPT systems.

Shot densities below 6 spf reduced produc-tivity. Above 8 spf there was essentially noproductivity increase, but the risk of perforationfailure and sand production increased. PDVSAselected 6 to 8 spf to satisfy all the above condi-tions. The first three wells were perforated withconventional guns using 6 spf. The fourth wellwas perforated with a customized gun to provide

8 spf while still satisfying the original require-ments of maximum perforation-to-perforationdistance, and more uniform distribution of perfo-rations within the allowable perforation angle.

Sand production is a problem in many areas.During 1995, Saudi Aramco began extensivedevelopment of nonassociated gas reserves inGhawar field. The Jauf reservoir was part of theendeavor.16 This unconsolidated sandstoneproduces sweet gas from 13,500 to 14,400 ft[4115 to 4390 m] deep, has low to moderatepermeabilities and a high potential for sand pro-duction at elevated pressure and temperature—8750 psi [60 MPa] and 300°F [150°C].

Jauf wells produce 10 to 60 MMscf/D [28,600 to 1.7 million m3/d], but it is difficult toachieve these high rates without producing sig-nificant volumes of formation sand. This sandinflux results in repeated workover interventionsto clean out wellbores and creates severepipeline corrosion by stripping away chemicalinhibitor from the inside of gathering and trans-mission lines.

Some Ghawar field wells were completedwith 41⁄2-in. casing, which ruled out rate-restricted, gravel-packed mechanical screens.Frac packing was considered, but low perme-abilities from core analysis and openhole well-testing data indicated a need for longerhigh-conductivity fractures to achieve target gasrates. As a result, Saudi Aramco decided topursue screenless technologies with hydraulicfracture stimulations.

Venezuela

NORTHAMERICA

SOUTHAMERICA

Field average Well 1 Well 2 Well 3 Well 4

1500

240

Initial oil rate

B/D

m3/d

4000

635

2200

350

700

111

1100

175

14

4

Stabilized sand rate

lbm/1000 bbl

kg/100 m3

0.5

0.14

3

0.86

3

0.86

0.4

0.11

> Eocene C reservoir pre- and post-oriented-perforating production results.

51381schD2R1.p29.ps 04/24/2002 07:52 PM Page 29

The newly built Hawiyah gas plant, with atotal capacity of 1.6 Bscf/D [46 million m3/d],required 400 MMscf/D [11.5 million m3/d] ofsand-free, sweet gas from Jauf wells. However,four fracture stimulations pumped in 1999 and2000 failed to prevent sand production, and con-sequently were largely ineffective. With plantstartup less than a year away, the operatorassembled a team of experts in petrophysics,geology, reservoir engineering and stimulationdesign under a Saudi Aramco manager and aSchlumberger coordinator. Along with represen-tatives from field operations, this groupaddressed proppant flowback and sand pro-duction, optimizing fracture treatments andimproving wellbore cleanout procedures.

This team identified 10 wells that were can-didates for screenless completions. To achieve astep change beyond conventional designs, aPowerSTIM well-optimization process was

implemented to integrate petrophysics, forma-tion evaluation, reservoir characterization andwell testing with stimulation design, executionand post-treatment evaluation.17 In addition tobetter formation evaluation and reservoir charac-terization, recommendations for improvinghydraulic fracture stimulations included orientedperforating to reduce treating pressures and create wider fractures, which reduce turbu-lent, nondarcy flow during production.Perforations properly aligned with the PFP alsoeliminate unpacked tunnels that contribute tosand production.

Borehole breakout identified on FMI logsconfirmed an east-west maximum stress and PFPorientation in the Jauf formation at an azimuth of about 80°, or 260° (left). The revised com-pletion strategy avoided perforating within 10 to 20 ft [3 to 6 m] of weaker intervals identi-fied by stress profiles. Perforated intervals werekept to a minimum of 30 or 40 ft [9 or 12 m] toensure fracture coverage at the wellbore andprevent sand flux from untreated open perfora-tions. The WOPT system and guns with 180°phasing were used.

In the initial application of oriented perforat-ing, the well produced 2 MMscf/D [57,000 m3/d]with a 3800-psi [26-MPa] FTP before stimulation.A step-rate injection test prior to the fracturingtreatment verified oriented-perforating effective-ness. Friction pressures during fracture initiationwere only 300 psi [2 MPa], significantly less thanthe average of 900 psi [6 MPa] in previous wellsconventionally perforated with 6 spf and 60° phasing. After stimulation, the well flowed30 MMscf/D [860,000 m3/d] at a 5200-psi [36-MPa] FTP, but continued producing solids.

Optimized screenless technologies wereemployed in the first well assigned to the jointPowerSTIM team. To stop the production ofproppant and sand, a stable 30-ft interval wasperforated with the WOPT system. Engineersdesigned a tip-screenout fracture with high-tem-perature PropNET fibers for flowback control. Thewell produced 1.6 MMscfd [45,800 m3/d] with a550-psi [3.8-MPa] FTP after perforating. Pressurefrom tortuosity effects was 450 psi [3.1 MPa],still half the level of wells without orientedperforations. A post-fracture rate of 37 MMscf/D[1 million m3/d] achieved solids-free productionafter only 11 days, significantly less than the 47-day average for previous wells.

Screenless completions were optimized overthe remaining nine wells of this program. Theteam developed a refined petrophysical modelbased on cores from offset wells, openhole logsand post-fracture data, and introduced a more

accurate model to predict sand production.Completion engineers used SPAN SchlumbergerPerforating Analysis modeling software topredict entrance-hole diameters and optimizeselection of proppant sizes.

Before the Jauf PowerSTIM program, wellstook as long as 55 days to achieve solids-freeproduction. Optimized screenless technologiesand improved flowback procedures reduced thiscleanup period to between three and five days.Saudi Aramco now routinely uses limited perfo-ration intervals and oriented perforating in Jaufreservoir wells. To date, all wells completed withscreenless techniques have achieved sand-freegas rates even at maximum production potentialand after cycling on- and off-line a number oftimes over several months.

If not addressed, problems associated with sand influx adversely affect well andreservoir productivity, jeopardize future remedial-intervention options and limit field profitability.Ensuring that perforation tunnels and the sur-rounding formation remain stable over the life ofa well is an important element of sand manage-ment. Improved sanding models, enhanced riskassessment and increasingly sophisticated per-forating techniques address these problems byproviding alternative strategies to manage andeliminate sand production.

Additional Applications and Developments Is premature screenout common during fracture-stimulation treatments? Are injection pressureshigher than expected? Is treatment implementa-tion rate or pressure limited by casing conditionsor the use of coiled tubing for selective stimula-tion of individual zones? Should less damagingfluids be used? Are final proppant concentrationstoo low? Do wells have sand-production orproppant-flowback problems? Are there indica-tions of scale and asphaltene deposition? If the answer to any of these questions is yes,oriented perforating may be a key element of theoilfield services solution.

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

18. Morita N and McLeod HO: “Oriented Perforations to Prevent Casing Collapse for Highly Inclined Wells,”paper SPE 28556, presented at the SPE Annual Tech-nical Conference and Exhibition, New Orleans,Louisiana, USA, September 25–28, 1994.

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> Typical wellbore breakout in the Jauf formation.FMI logs identified north-south borehole breakoutof about 25% in the Jauf formation of Saudi Arabia.This confirmed a maximum formation stress direc-tion of approximately east to west at azimuth 80º,or 260º. The current perforating strategy is to ori-ent perforations along the preferred fractureplane using guns with 180º phasing and 6 spf. Thisapproach helps prevent solids production andreduce near-wellbore friction pressures duringfracturing operations.

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Carefully planned oriented perforating deliv-ers optimal results, in most cases, at negligibleincremental costs compared with the additionalvalue generated. Detailed analysis and candidateselection are vital parts of the planning processfor oriented perforating (above). The latest log-ging tools and interpretation techniques facili-tate this process by measuring and evaluatingrock properties beyond drilling-induced formationdamage. Combined with integrated reservoircharacterization, these services provide data andinput for developing accurate earth models tosimulate, design and evaluate stimulation opti-mization and sand-management solutions that oiland gas operators need to enhance production.

Oriented-perforating operations are tech-nique-sensitive, and currently require more timethan conventional perforating, particularly in ver-tical wells with little inclination. Because theWOPT relies on repeatability of tool-string orien-tation, care must be taken during each step of jobexecution. In addition, if the tool assumes a dif-ferent orientation during a perforating run, theguns must be pulled back out of the well andreindexed accordingly.

A system that allows rotation, or indexing, ofguns downhole would greatly reduce techniquesensitivity and further improve the overallefficiency of oriented perforating. Downholereorientation would be particularly beneficial inwellbores with inclinations greater than 3°where inclination measurements are more reli-able. The additional capability to selectively firemore than one detonator, and therefore, severalguns in a single trip also will drastically reducethe number of runs required to perforate longerintervals or multiple zones. In any case, a gyro-scope run is required when directional-surveydata are not available.

The need to perforate without damagingcables, control lines and other hardware inincreasingly complex, instrumented wellbores isa growing application for wireline-conveyedoriented perforating. The number of intelligentcompletions being deployed is expected toincrease at a rate of about 30% per year.Installation of fiber-optic systems that allowoperators to monitor downhole well performanceand evaluate stimulation-treatment effective-ness over time is growing even faster.Techniques to detect and map downhole comple-tion components, and monitor gun orientationwhile perforating will help meet this need.

Other applications for oriented perforatinginclude intersecting natural fractures or boreholesectors with minimal formation damage forenhanced well productivity, repairing channels in cement behind casing and activating reliefwells during pressure-control operations.Oriented perforations that avoid exposing perfo-ration-weakened casing to extreme stressconcentrations also prevent casing collapse in high-angle wellbores or wells drilled in tecton-ically active areas.18 In the future, this techniquealso may find applications in complex, highly faulted geological structures where in-situ stress conditions complicate fracturedesign, treatment implementation and stimula-tion effectiveness.

These requirements and increasinglydemanding well completions are driving develop-ment of the next generation of perforating systemsand techniques, aimed primarily at increasingwellsite efficiency and reducing the time requiredto implement perforating services and solutions.When commercial, these tool enhancements andthe new perforating systems that use them willfurther expand the flexibility and effectiveness oforiented perforating. —MET

Oriented perforating

Sand management

Sand prevention• Mitigate sand influx• Stop proppant flowback• Use screenless completions• Reduce scale and asphaltene deposition

Hydraulic fracturing• Minimize screenouts• Increase proppant concentration• Reduce injection pressures - Pump down casing - Pump down small tubing - Use selective coiled tubing stimulation

Well-log and offset data• Regional data• Openhole wireline logs - DSI tool - FMI tool - UBI tool - Caliper survey

Perforating techniques• Orient with TCP or wireline • Align with PFP

Well data• Wellbore trajectory and inclination

• Intersect natural fractures• Penetrate minimal damage

• Optimize perforations - Tunnel diameter - Penetration depth - Phasing - Shot density - Spacing

Interpretation services• Log evaluations• Stress profiles - Mechanical earth models - Stress magnitudes and directions - Formation competency

Stimulationoptimization

Formation evaluation

Reservoircharacterization

Well-completionobjectives and

parameters

or

> Planning and implementing oriented perforating. Accomplishing perforating, fracturing and sand-managementobjectives involves identifying the problem, assessing the applicability of oriented perforating, running required welllogs, developing appropriate geomechanical models and addressing well-completion operational aspects in advance.Accurate problem diagnosis may suggest modifications to drilling, logging and completion programs during well plan-ning that can streamline implementation of oriented-perforating solutions.

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