practical approaches to sand management
TRANSCRIPT
10 Oilfield Review
Practical Approaches to Sand Management
Andrew AcockTom ORourkeDaniel ShirmbohAberdeen, Scotland
Joe AlexanderAbu Dhabi, United Arab Emirates
Greg AndersenUnocalSugar Land, Texas, USA
Toshinobu KanekoAdi VenkitaramanHouston, Texas
Jorge López-de-CárdenasRosharon, Texas
Masatoshi NishiIslamabad, Pakistan
Masaaki NumasawaKatsuhei YoshiokaJapan Petroleum Exploration Company, Ltd.(JAPEX)Tokyo, Japan
Alistair RoyAllan WilsonBPAberdeen, Scotland
Allan TwynamBPSunbury, England
For help in preparation of this article, thanks to Mark Alden,Houston, Texas, USA; Andrew Baker, Quito, Ecuador; Mario Ardila, New Orleans, Louisiana, USA; John Cook and Juliane Heiland, Cambridge, England; John Fuller,Gatwick, England; Anwar Husen, Cairo, Egypt; Andy Martin,Aberdeen, Scotland; and Juan Carlos Palacio, Stavanger,Norway. Thanks also to BP and their partners, Eni UK Limited, Noex UK Limited, Shell and ExxonMobil, for therelease of the Mirren field example.
Sand production is a serious problem in many oil and gas assets worldwide. It can
drastically affect production rates; it can damage downhole and subsea equipment
and surface facilities, increasing the risk of catastrophic failure; and it costs producers
tens of billions of dollars annually. Sand management is a complicated issue that
cannot be addressed by a one-size-fits-all approach. Instead, operators have
embraced a multifaceted approach, exploiting the vast array of technologies and
expertise available to manage this problem.
CHFR (Cased Hole Formation Resistivity), ClearPAC, CNL(Compensated Neutron Log), DataFRAC, DSI (Dipole Shear Sonic Imager), ECLIPSE, FMI (Fullbore FormationMicroImager), GVR (geoVISION resistivity sub), InterACT,LiteCRETE, MDT (Modular Formation Dynamics Tester),MudSOLV, OBMI (Oil-Base MicroImager), OrientXact, ProCADE, ProFIT, PropNET, PURE (Perforating for UltimateReservoir Exploitation), QUANTUM, RockSolid, RST (Reservoir Saturation Tool), SPAN (Schlumberger perforationanalysis), STIMPAC, TDT (Thermal Decay Time), USI (UltraSonic Imager) and WellWatcher are marks of Schlumberger. AllPAC is a mark of ExxonMobil and islicensed to Schlumberger.
Failure at the sand-grain scale during hydro-carbon exploitation can cause wellbore-stabilityproblems, casing collapse, reduced production,and in extreme cases, the loss of a wellbore.1
Loose sand grains are mobilized at certain pres-sure-drawdown levels, fluid velocities and fluidviscosities; once produced into the wellbore,these particles can create havoc downstream.
Produced in fast-flowing conditions or greatnumbers, sand grains erode tubulars and canbecome stationary or migrating obstructions. Theerosive capability of produced sand depends onmany factors, including the amount of sand
being produced, sand-particle velocity andimpact angle.2 Erosion from sand production—sanding—damages downhole tubulars, subseahardware, pipelines and other facilities, possiblycausing catastrophic well failure and harm topersonnel and to the environment.
Sand accumulations can choke off productionanywhere along the flowline, reducing produc-tion revenues and costing significant amounts oftime and money to clean out. Remedial opera-tions on subsea wells and fields are particularlyexpensive. Produced sand that reaches produc-tion facilities must be separated from produced
Spring 2004 11
fluids and disposed of. Although the exact cost isdifficult to quantify, experts agree that producedsand costs the oil and gas industry tens of billions of dollars annually.
Sand production has always been a problem,but the manner in which the exploration andproduction (E&P) industry manages this prob-lem has become more sophisticated. This articlebriefly reviews the basic principles of sand production and the technologies available tohelp predict, prevent and monitor sand produc-tion. Case studies show that sand management isbest achieved when operators understand sand-production mechanisms within the reservoir anduse an informed decision-making process toselect the appropriate technologies and methodsfor addressing the problem.
The Nature of Sand ProductionUnderstanding why reservoirs produce sand isthe crucial first step toward managing sand pro-duction. The installation of downhole completion
hardware may represent an important part of thesolution, but greater knowledge engenders amore thorough and longer-lasting solution. Forexample, the ability to model and predict thesand-production tendencies of a reservoir allowsengineers and scientists to move beyond a trial-and-error methodology to resolve sanding issues.A successful sand-management strategy can startduring the drilling stage and carry through toreservoir depletion.
In the subsurface, the main factors that control whether a reservoir will fail mechanicallyare rock strength, the effective stress on the formation—a combination of principal earthstresses acting on the rock minus pore pres-sure—and the stresses introduced by drilling,completion and production.3 Rock strength canbe determined through laboratory uniaxial andtriaxial tests, and can be represented graphicallyby a failure curve, or envelope. The shear andnormal stresses on a specified plane under threeperpendicular principal stresses are determined
by using Mohr’s circle. To determine the condi-tions at which failure occurs, the Mohr-Coulombfailure model is used to relate principal stressesand pore pressure to the cohesion and internal
1. Fjaer E, Holt RM, Horsrud P, Raaen AM and Risnes R:Petroleum Related Rock Mechanics, Developments inPetroleum Science, 33. Amsterdam, The Netherlands:Elsevier Science Publishers B.V. (1992): 257–267.
2. Selfridge F, Munday M, Kvernvold O and Gordon B:“Safely Improving Production through Improved SandManagement,” paper SPE 83979, presented at the SPEOffshore Europe 2003 Conference, Aberdeen, Scotland,September 2–5, 2003.
3. Desroches J and Woods TE: “Stress Measurements for Sand Control,” paper SPE 47247, presented at theSPE/ISRM Eurock 98, Trondheim, Norway, July 8–10, 1998.
friction angle of the rock (right). Failure occursunder tension, compression or, most commonly,when the difference between the maximum andminimum principal stresses becomes largeenough to produce excessive shear stress.
The strength of a rock under downhole condi-tions depends on several factors. The mostimportant are the cohesion, the internal frictionangle, the maximum and minimum principalstresses and the pore pressure. Cohesion isstrongly influenced by the degree of cementationof the rock. Well-cemented, consolidated sedi-mentary rocks tend to be stronger, while poorlycemented, unconsolidated rocks are weaker.Internal friction angle is influenced by the volume fraction of hard particles—typicallyquartz or feldspar grains—in the rock. Forma-tion grains in weak sandstone reservoirs becomedisaggregated, or loosened from the rock matrix,because of shear, tensile and volumetric failure.4
During production, shear failure caused byeither drawdown or depletion can result in acatastrophic quantity of produced sand. Increas-ing the drawdown generates higher effectivestresses around the well or perforation tunnel,and if these exceed the strength of the rock inthis geometry, the rock will fail and sand may beproduced. Increasing depletion can change thein-situ stresses in the Earth, which can also generate higher shear stresses around the bore-hole, possibly leading to sand production.
Tensile failure occurs in weak sandstones primarily because of a high fluid-flow rate, whichis a function of drawdown. This type of failure isoften sporadic, produces relatively low volumesof sand, is aggravated by rapid changes in wellproduction rates, and often stabilizes with time.
Volumetric failure, or pore collapse, is associ-ated with both drawdown and depletion andoccurs in high-porosity, low-strength reservoirs.In weak but consolidated rocks, this phenomenoncauses subsidence and has been studied exten-sively in North Sea chalk reservoirs.5
Not all sandstones yield disaggregated sandgrains under stress. Tests have shown that evenweak sandstones—as determined by uniaxial-compression tests and confined triaxialtests—can have wide-ranging sand-productionbehaviors that are primarily related to rock type.6
Many events in a reservoir rock’s history canchange its strength, eventually resulting in theonset of sand production. Additional stresses areplaced on the rock matrix when drilling, complet-ing and stimulating a reservoir. Also, rock strengthcan be reduced by production events, such as acidstimulation, reservoir compaction or increases inwater saturation.7 In weak and unconsolidatedrocks, rock strength generally decreases with
increasing water saturation, with the largestdecrease in strength occurring after only slightincreases in water saturation from a dry state.8
Not all disaggregated sand grains are mobi-lized by produced fluids.9 They may stay in theperforation, or in the well, and eventually coverthe producing interval. The degree to which sandgrains are mobilized depends on factors such asfluid viscosity and fluid velocity, in complex andrelatively poorly understood ways.10 When tryingto predict when and where sand production willoccur, the failure of a rock and the resulting disaggregation of sand grains must be consideredin conjunction with particle erosion and mobi-lization into the production stream.
There are many ways to avoid or minimizesand production. In very weak, unconsolidatedreservoirs, large-scale sand production may beinevitable, so downhole methods to exclude sandproduction or to consolidate the formation nearthe wellbore are practical. Sand-exclusion tech-niques include cased-hole gravel packs, high-ratewater packs, frac packing, openhole gravel packsand stand-alone screens—such as slotted linersand expandable screens.
Consolidation techniques involve the injec-tion of resins to stabilize the rock while leavingenough of the original permeability intact toallow the production of reservoir fluids. Theseresins are sometimes used prior to hydraulic-fracturing techniques for sand control.
Choosing a method to reduce or eliminatesand production in moderately weak reservoirsis less straightforward. Underestimating thesand-production potential may lead to costlysanding problems in the future, while overesti-mating the sand-production potential may resultin unwarranted and expensive installations ofdownhole hardware, or unnecessary reductionsin production rate. Predicting the extent of sandproduction in moderately weak reservoirs is crucial to minimizing uncertainty when design-ing a completion. Furthermore, correctlypredicting sand production can save operatingcompanies millions of dollars per well.
In many moderately weak reservoirs, screenless-completion methods provide an optimal solution.11 Techniques such as orientedperforating, selective perforating, screenlesshydraulic fracturing and consolidation treat-ments have reduced sand production, sometimesdramatically. There are also ways to manage sandproduction at the surface by using appropriatesand separators and through careful monitoringof erosion and accumulation. In such cases, theeconomics of cleanout and disposal of the sandmust be taken into account in the final choice ofsand-management techniques. In conjunctionwith all sand-management methods—exclusion,screenless and surface—producing the well atan optimal rate can be essential to controllingsand production.
12 Oilfield Review
(τ)
Shea
r stre
ss
β2
σ3 σn σ1
Principal effective stress
σn
β
σ3
σ1
τ
> Mohr-Coulomb failure criterion. The Mohr circle (red) represents the state of stress at anyorientation in a material body, ranging from the smallest principal effective stress, σ3 , to the largest,σ1. If the Mohr circle intersects the failure condition (blue), the material will fail in shear. Mohr’scircle also provides the normal stress (σn) and shear stress (τ) across the failure plane, and thefailure angle β, measured from the direction perpendicular to maximum principal stress (inset).
Spring 2004 13
A Need To KnowProper sand management seeks to optimize thecompletion of wells with sand-production problems. Accomplishing this goal requiresunderstanding the reservoir and the forces thataffect formation stability.
Earth-stress data have been compiled from avariety of sources. The magnitude and orienta-tion of horizontal stresses can be displayed onlocal or global stress maps (above).12 The pre-dominant source of horizontal stress information
(2003) World Stress Map
Regime
Thrust fault
Normal faultStrike slip
Unknown
MethodFocal mechanismsBreakoutsDrilling-induced fracturesBorehole slotterOvercoringHydraulic fracturesGeological indicators
>World stress map. Stress data are compiled from a variety of sources and displayed on stress maps. Downhole measurements, such as boreholebreakout and induced-fracture data, are an important source of this stress information. Hydraulic-fracturing data are also useful but often contain nostress orientation details.
4. Nouri A, Vaziri H, Belhaj H and Islam R: “A ComprehensiveApproach to Modeling Sanding During Oil Production,”paper SPE 81032, presented at the SPE Latin Americanand Caribbean Petroleum Engineering Conference, Port-of-Spain, Trinidad, West Indies, April 27–30, 2003.
5. Andersen MA: Petroleum Research in North Sea Chalk.Stavanger, Norway: Rogaland Research, 1995.
6. Nicholson ED, Goldsmith G and Cook JM: “Direct Observation and Modeling of Sand Production Processesin Weak Sandstone,” paper SPE/ISRM 47328, presentedat the SPE/ISRM Eurock 98, Trondheim, Norway, July 8–10, 1998.
7. Carlson J, Gurley D, King G, Price-Smith C and Waters F:“Sand Control: Why and How?” Oilfield Review 4, no. 4(October 1992): 41–53.
8. Han G, Dusseault MB and Cook J: “Quantifying Rock Capillary Strength Behavior in Unconsolidated Sandstones,” paper SPE/ISRM 78170, presented at theSPE/ISRM Rock Mechanics Conference, Irving, Texas,USA, October 20–23, 2002.Hawkins AB and McConnell BJ: “Sensitivity of Sand-stone Strength and Deformability to Changes in Moisture Content,” Quarterly Journal of Engineering Geology 25(1992): 115–130.Dyke CG and Dobereiner L: “Evaluating the Strength and Deformability of Sandstones,” Quarterly Journal ofEngineering Geology 24 (1991): 123–134.West G: “Effect of Suction on the Strength of Rock,”Quarterly Journal of Engineering Geology 27 (1994):51–56.
9. Tiffin DL, Stein MH and Wang X: “Drawdown Guidelinesfor Sand Control Completions,” paper SPE 84495, presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, USA, October 5–8, 2003.
10. Palmer I, Vaziri H, Willson S, Moschovidis Z, Cameron Jand Ispas I: “Predicting and Managing Sand Production:A New Strategy,” paper SPE 84499, presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, USA, October 5–8, 2003.
Vaziri H, Barree B, Xiao Y, Palmer I and Kutas M: “What Is the Magic of Water in Producing Sand?” paper SPE 77683, presented at the SPE Annual TechnicalConference and Exhibition, San Antonio, Texas, USA,September 29–October 2, 2002.Vaziri HH, Lemoine E, Palmer ID, McLennan J and Islam R: “How Can Sand Production Yield a Several-FoldIncrease in Productivity: Experimental and Field Data,”paper SPE 63235, presented at the SPE Annual TechnicalConference and Exhibition, Dallas, Texas, USA, October 1–4, 2000.
11. Acock A, Heitmann N, Hoover S, Malik BZ, Pitoni E, Riddles C and Solares JR: “Screenless Methods to Control Sand,” Oilfield Review 15, no. 1 (Spring 2003):38–53.Riddles C, Acock A and Hoover S: “Rigless, ScreenlessCompletions Solve Sand Control Problems in Two Offshore Fields,” Offshore 62, no. 6 (June 2002): 48–50, 98.Pitoni E, Ripa G and Heitmann N: “Rigless, ScreenlessCompletions Solve Sand Control Problems in Two Offshore Fields,” Offshore 62, no. 7 (July 2002): 64–68, 109.
12. Reinecker J, Heidbach O and Mueller B. The 2003release of the World Stress Map is available online atwww.world-stress-map.org (accessed February 18, 2004).
is earthquake focal mechanisms—compression,tension or strike-slip—determined from the seis-mic waves arriving from earthquakes. A smallamount of data comes from strain-relaxation andstress-metering techniques. Local stress informa-tion in oil and gas development areas oftencomes from boreholes and includes sonic logdata, borehole breakout patterns, induced-frac-ture directions, and hydraulic-fracturing andmicrohydraulic-fracturing data.
An important source of earth stress direc-tional data is wireline and logging-while-drilling(LWD) images and measurements.13 Typically,the largest principal stress is vertical andattributed to the weight of overburden. Sonic,density and pore-pressure data are used to gen-erate a vertical stress profile. Borehole imagingdevices, such as the FMI Fullbore FormationMicroImager, the OBMI Oil-Base MicroImagerand the GVR geoVISION resistivity tools, provideorientation of induced fractures and boreholebreakouts. The minimum principal-stress direc-tion is perpendicular to these fractures andaligned with the elongation of the boreholecaused by breakouts (above).
Accurate determination of stress directions iscrucial in the proper deployment of oriented per-forating gun systems. Perforating in the directionof maximum stress makes hydraulic fracturingmore efficient by reducing tortuosity effects dur-ing pumping. For sand prevention, orientedperforating in the direction of maximum stabilityhas produced good results. Oriented perforatingcan be achieved with wireline, coiled tubing or tubing-conveyed methods in vertical, deviated orhorizontal wells. Regardless of the method used,oriented perforating has helped minimize sand production, particularly in the presence of stress anisotropy.
Modeling a reservoir’s tendency to producesand also requires knowledge of principal stressmagnitudes. To physically measure the magnitude of horizontal stress downhole, ahydraulic-fracturing technique called theDataFRAC fracture data determination serviceis often used on wells requiring hydraulic-fracture stimulation. After hydraulic-fractureinitiation, pressure measurements record thefracture-closing pressure, which is related to theminimum in-situ stress acting perpendicular tothe fracture.
An alternative to this procedure was devel-oped using the MDT Modular FormationDynamics Tester tool on wireline.14 The MDT tooluses a straddle-packer arrangement to performopenhole microhydraulic-fracturing tests onsmall intervals. The MDT device injects fluid intoan interval at a constant rate until a fracture isinitiated. The fracture propagates perpendicularto the direction of the minimum in-situ stress.Similar to the DataFRAC service, this techniquemeasures pressure responses after fracture initi-ation to determine the minimum principal stressand can be used with other logging tools—forexample the DSI Dipole Shear Sonic Imager andFMI tools—to provide a more comprehensiveanalysis. Microhydraulic-fracturing tests havebeen used successfully to define the formationstresses prior to performing frac packing andscreenless hydraulic fracturing sand-controloperations. Stress information, along with otherdata, is used to build models of the minimumprincipal stress versus depth. These models areimportant in both the design and analysis of the
14 Oilfield Review
Maximum horizontalstress direction Minimum horizontal
stress direction
Inducedfracture
Boreholebreakout
deg0 90
BeddingTrue Dip
0 120 240 360
XX92
XX93
Dept
h, m FMI Dynamic Image
Resistive Conductive
Orientation North
Boreholebreakout N45E
Drilling-inducedfractures S45E
> In-situ stress direction from borehole images. Borehole imaging data provide detailed stress-direction information (right). For example, in a vertical well, borehole breakouts typically are orientedalong the minimum horizontal stress direction, while drilling-induced fractures are aligned with themaximum horizontal stress direction (left). Induced fractures frequently are near-vertical because theminimum stress is usually horizontal.
13. Anderson J, Simpson M, Basinski P, Beaton A, Boyer C,Bulat D, Ray S, Reinheimer D, Schlachter G, Colson L,Olsen T, John Z, Khan R, Low N, Ryan B andSchoderbek D: “Producing Natural Gas from Coal,” Oilfield Review 15, no. 3 (Autumn 2003): 8–31.Inaba M, McCormick D, Mikalsen T, Nishi M, Rasmus J,Rohler H and Tribe I: “Wellbore Imaging Goes Live,” Oilfield Review 15, no. 1 (Spring 2003): 24–37. Almaguer J, Manrique J, Wickramasuriya S, Habbtar A,López-de-Cárdenas J, May D, McNally AC andSulbarán A: “Orienting Perforations in the Right Direction,” Oilfield Review 14, no. 1 (Spring 2002): 16–31.Cheung P, Hayman A, Laronga R, Cook G, Flournoy G,Goetz P, Marshall M, Hansen S, Lamb M, Li B, Larsen M,Orgren M and Redden J: “A Clear Picture in Oil-BaseMuds,” Oilfield Review 13, no. 4 (Winter 2001/2002): 2–27. Peterson RE, Warpinski NR, Lorenz JC, Garber M, Wolhart SL and Steiger RP: “Assessment of the Mounds Drill Cuttings Injection Disposal Domain,” paper SPE 71378, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA,September 30–October 3, 2001.Bargach S, Falconer I, Maeso C, Rasmus J,Bornemann T, Plumb R, Codazzi D, Hodenfield K, Ford G,Hartner J, Grether B and Rohler H: “Real-Time LWD: Logging for Drilling,” Oilfield Review 12, no. 3 (Autumn 2000): 58–78.
14. Desroches J and Kurkjian AL: “Applications of WirelineStress Measurements,” paper SPE 58086, revised for publication from paper SPE 48960, prepared for presentation at the SPE Annual Technical Conferenceand Exhibition, New Orleans, Louisiana, USA, September 27–30, 1998.
15. Desroches and Woods, reference 3.16. 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 1998): 40–55.
17. Ali AHA, Brown T, Delgado R, Lee D, Plumb D, Smirnov N,Marsden R, Prado-Velarde E, Ramsey L, Spooner D,Stone T and Stouffer T: “Watching Rocks Change—Mechanical Earth Modeling,” Oilfield Review 15, no. 2(Summer 2003): 22–39.
Spring 2004 15
hydraulic-fracturing treatment. However,mechanically weak zones may fail due to thedrawdown between the MDT packers (see “Test-ing Weak Sands,” page 24). To avoid this, theMDT technique can be used in cased holes.15
To predict how a sand-management comple-tion will perform over the life of the reservoir,information is also needed about the impact ofdepletion on reservoir stresses. This information,usually a single number called the reservoir-stress path, can be calculated approximatelyfrom the elastic properties of the reservoir andsurrounding rock, or calculated more accuratelyusing a full-field geomechanical model, or mea-sured by examining hydraulic fracture recordsfrom different stages in the development of thefield, if such data exist.
Modern sonic logging devices, such as theDSI tool, measure shear-wave anisotropy todetermine in-situ stress directions in both hard,fast formations and soft, slow formations.16 Thesetools also provide crucial rock-mechanics param-eters to assess formation strength and predictsand-production problems. Measured values ofcompressional traveltime (tc) and shear travel-time (ts) are used to calculate dynamic elasticproperties, including Poisson’s ratio (ν) andYoung’s modulus (E).
Static rock properties are derived from labo-ratory tests. In the laboratory, the effective stresson the rock sample governs failure, but samplesize, shape, moisture content and defects alsoinfluence failure. A failure envelope is con-structed using data from several compressiontests, in which peak axial stress points are typi-cally plotted against the different confiningpressures used during the tests (below). Labora-tory test data greatly enhance the overallknowledge of reservoir rock strength and can beused to calibrate log-derived values. However,performing these tests requires specializedequipment, and acquiring representative rocksamples may be difficult, if not impossible.
Model BehaviorPredicting sand-production behavior starts withdeveloping a mechanical earth model (MEM) tounderstand a field’s geomechanics.17 Thesemodels are especially important when trying toassess the impact of a given completion methodon weak rocks. In its most basic form—onedimension (1D)—an MEM contains informationon vertical and horizontal stresses, pore pres-sure, rock strength, rock properties and geologicdata, such as formation dip. An MEM can useadditional inputs from geological and geophysi-
cal models that define tectonic features, such asfaults and folds. Reservoir models that describefield-depletion or pressure-maintenanceresponses can also be input to an MEM. A well-constructed three-dimensional (3D) MEM allowsengineers and geoscientists to determine thestate of stress in a reservoir and surroundingstrata at any location within a field.
Sand-prediction models focus on failure ofreservoir rock and migration of disaggregatedsand grains resulting from well-completion practices. Information about the mechanismsthat drive sand production is not easily obtainedfrom downhole observations, so much of theknowledge relating to sand prediction has comefrom laboratory research.
Scientists at Schlumberger CambridgeResearch Center (SCR) and SchlumbergerReservoir Completions Technology Center (SRC)conducted perforation-stability experiments onrock samples of different strengths, providingdata to develop simulation software that predictssand failure in weak rocks. These experimentsexamined sand-production tendencies at variousstresses and flow rates to study the effects of per-foration hole size, formation grain size andcompletion geometry—perforation and wellboreorientation—in relation to the principal stresses
Peak
axi
al s
tress
, MPa
Confining pressure, MPa
Red Hollington sandstone: porosity ~28%
100 20 30 400
50
100
50 60
150
200
250
Axial strain, %
Axia
l stre
ss, M
Pa
Red Hollington sandstone: porosity ~28%
100
150
50
0
200
250
0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6
0
5
10
20
3040
50
151174196224
Confining pressureMPa
Peak axial stressMPa
051020304050
3171100
> Constructing a failure envelope. Reservoir rocks are tested in the laboratory to acquire axial stress and strain data at differentconfining pressures (top left). Normally, each confining pressure used during testing is plotted against the peak axial stress thatoccurs before failure (right), allowing the internal friction angle to be estimated.
16 Oilfield Review
Rock
Endoscope
Pressure vesselKerosene in
Light guideand ring mirror
Kerosene out
> Laboratory testing designed to visualize sand disaggregation and sand transport mechanisms. A rock samplecontaining a simulated perforation tunnel is placed in a pressure vessel (top). A light guide and ring mirror are used incombination with an endoscope to observe the tunnel while kerosene flows through the tunnel. When possible, coresfrom representative reservoir outcrops have been used for axial flow testing, in which the displacement of the tunnelwalls was documented by imaging (bottom). Extensive work at SCR identified different mechanisms across a widerange of rock strengths. This information is compared to sand-production modeling results.
> Determining the critical drawdown limits. Sand prediction modeling in the Sand Management Advisor software calculatescritical drawdown pressure for different openhole or perforated completion options and orientations. Given certain reservoirpressure and bottomhole pressure ranges, the green region defines the sand-free window, while the red area signifies sandfailure. Uncertainties associated with input data (left) can be applied to the critical drawdown computation to generateuncertainties in the sand-free window. In addition, the cumulative uncertainty distribution is plotted to the right for a reservoirpressure of 4,500 psi [31 MPa].
Spring 2004 17
(previous page, top). This work has greatlyenhanced sand-prediction modeling, which isbased on the peak strength of a rock in a perfora-tion tunnel or wellbore. Schlumberger uses thisinformation to optimize completions to ensurethat wells produce at economic rates with anacceptable risk of sand production.
Similar to wellbore-stability analysis, sand-production analysis differs in that theperforation-tunnel pressure is less than reservoirpressure, allowing fluid flow. Or, in the case ofopenhole completions, wellbore pressure is lessthan reservoir pressure. Stress calculations aremade at the appropriate perforation orientationand phasing to determine minimum drawdownthat does not promote shear failure, or the maximum sand-free drawdown. This drawdown isthen used to calculate production rates and to establish whether minimum productionrequirements are achieved. If they are not, thecompletion design must be modified.
Schlumberger developed proprietary softwarecalled Sand Management Advisor to accomplishthis analysis. This 3D sand-prediction modelingsoftware requires MEM inputs and exploits theoutputs from other analysis tools, such as SPANSchlumberger perforation analysis and ProCADEwell analysis software tools. It also links to theFormation Completion Selection Tool (FCST), aproprietary knowledge-based completion-plan-ning tool, so that experts can optimizecompletions by screening and ranking the mostappropriate completion technologies available.
The sand-prediction tool calculates the critical drawdown pressure for different user-provided completion scenarios and identi-fies the sand-free production window. Twomodels are used in computing the critical draw-down pressure at which a formation will fail. Awide range of methods has been used in the pastfor sand production prediction, for example,using elastoplastic models.18 Sand ManagementAdvisor uses a proprietary method developed bySchlumberger that takes into account the well-known increase in the strength of holes inrocks as their diameters decrease. The sand-freewindow defines completion and artificial-liftdesign limits, for example the maximum allow-able drawdown produced by an electricalsubmersible pump (ESP). Uncertainty can alsobe considered on six input parameters: Poisson’sratio, unconfined compressive strength, mini-mum horizontal stress, minimum horizontalstress direction, ratio of the maximum and mini-mum horizontal stresses, and grain size. For agiven completion scenario, this sand-free windowis displayed graphically by plotting reservoirpressure versus bottomhole flowing pressure(BHFP), highlighting the sand-free drawdownwindow and the various levels of uncertainty(previous page, bottom). This and other tools can also be used in the selection of sand-management candidate wells.
From Prediction to PracticeWith knowledge of a reservoir, its stresses andthe probability of encountering sand production,operating companies can make informed deci-sions about the best approach to optimize wellcompletions and limit the impact of producingsand (above). Initially, the question is whether tocontrol or to prevent sand production. Sand-exclusion methods may be required when sandproduction is certain, or when the risk associatedwith unforeseen sand production is high—forexample, in subsea completions or high-rate gaswells. One of a variety of screenless-completionmethods may offer the best option when sandproduction can be avoided or at least limited.Regardless of the method, proper sand manage-ment is the vehicle needed to balance sandcontrol with the desired production resultsthrough optimized completions.
Gravel packing is a common sand-exclusiontechnique that has been used since the 1930s.19
This procedure involves pumping a designedslurry, comprising gravel of a specific size and anappropriate carrying fluid, to fill the annular
• Gravel pack• High-rate water pack• Frac and pack• Openhole gravel pack• Expandable screens
• Artificial lift• Downhole desander
• Oriented perforating• Selective perforating• Screenless fracturing• Consolidation
Sand exclusion
Customized integrated technologies
Manage sand at surface Screenless completions Natural Stimulated
Customized integrated technologies
Sand-management
method
Formation-stability issues
Completion optimization
Stimulatedor natural
Yes No
> Completion options to balance sand control with production requirements. If formation-stability concerns exist, operatorscan choose between downhole sand-exclusion technologies or screenless-completion methods. They may also choose tomanage existing sand production by careful selection of artificial-lift techniques and practices.
18. Bradford IDR and Cook JM: “A Semi-Analytic ElastoplasticModel for Wellbore Stability with Applications to Sanding,” paper SPE 28070, presented at the SPE/ISRMRock Mechanics in Petroleum Engineering Conference,Delft, The Netherlands, August 29–31, 1994.
19. Ali S, Dickerson R, Bennett C, Bixenman P, Parlar M,Price-Smith C, Cooper S, Desroches L, 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.Carlson et al, reference 7.
space between a carefully selected centralizedscreen and perforated casing, or the formation inthe case of an openhole gravel pack (above).
Cased-hole gravel-pack design should includeperforating optimization. The selection of themost suitable perforating-gun system and perfo-rating method can also improve gravel-packeffectiveness by minimizing perforation damage.20
In moderately competent reservoirs, the PUREPerforating for Ultimate Reservoir Exploitationsystem produces the optimum amount of under-balance for a given reservoir pressure, generatingimproved perforation cleanup.21
Openhole gravel packs require removal offiltercake from the completion in addition to thestandard design considerations. Careful selectionof proper drilling and completion fluids helpsensure adequate filtercake development and itssubsequent removal. It is imperative to removeas much filtercake as possible to maximizegravel-pack permeability. This is best accom-plished by using a fully integrated process suchas the MudSOLV filtercake removal service andantiswab tools to maintain hydrostatic pressureon the wellbore during the gravel-packing opera-tion. The MudSOLV service includes fullconsideration of the completion, selection of thechemistry with the lowest risk, the use of perfor-mance metrics, economic analysis and laboratoryverification testing.22
In low-permeability reservoirs, reservoirs pro-ducing high-viscosity fluids, or layered reservoirswith low net-to-gross pay intervals, the techniqueof frac packing has been widely successful.23 In
soft rocks, this method produces a short, widehydraulic fracture and relies on achieving a tipscreenout (TSO) fracture. Unlike conventionalhydraulic fracturing, TSO designs limit fracturelength by dehydrating the proppant pack withinthe fracture early in the treatment. This helpsprop the fracture near the tip, creating a shortbut conductive flow path to the wellbore.
This technique increases the effective com-pletion radius and the area open to flow, andreduces sand production associated with high
fluid velocities and unstable perforations. In thepast, separate operations included wellborecleanout, sand-exclusion screen installation andgravel packing, all conducted after fracturing.However, advances in downhole hardware associ-ated with the STIMPAC fracturing andgravel-packing service now allow the fracturingoperation to be completed with the screenalready in place, and then followed bygravel packing.
18 Oilfield Review
Perforations
Productioncasing
Gravel
Productioncasing
Gravel
Cased-Hole Gravel Pack Openhole Stand-Alone Screen Openhole Gravel Pack
Filtercake
Blank pipe
Screens
Screens
Open hole
> Cased-hole and openhole gravel packs. Cased-hole gravel packing requires perforating of the completion interval and is often used in vertical, or near-vertical, wells producing from laminated reservoirs (left). Openhole stand-alone screens are used to control sand production in clean reservoirs that haverelatively short production lives (center). Openhole gravel packs are common in horizontal wells, require no perforations, and are a viable option in highlyproductive, risky deepwater completions (right).
High stresson perforations
Near-Vertical Well
Wellboredamage
Maximumstress
Minimumstress
Minimumstress
Maximumstress
Damage occursat stressconcentrations
Borehole Stresses
> Stress concentration around a borehole. Perforated completion designs for sand control shouldconsider the stresses around the borehole to help prevent perforation-tunnel failure (left). Unlikeperforating for hydraulic fracturing, perforations should avoid the highly stressed regions typicallyaligned with the maximum horizontal stress in vertical wells, which is the vertical direction inhorizontal wells (right). Perforating in the minimum horizontal stress direction should also be avoidedto minimize perforation-tunnel failure. Oriented perforating allows the perforations to be alignedbased on perforation stability models to optimize a completion.
Spring 2004 19
There is also a screenless method of fracpacking that involves oriented perforating,injecting resin to stabilize the formation andusing resin-coated proppants and fiber technol-ogy to prevent proppant flowback (see “GoingScreenless in Japan,” page 21). This techniquejoins a growing list of screenless options whenoperators choose to prevent failure rather thanto exclude sand production.
In moderately weak but consolidated zones,screenless-completion techniques offer effectivesolutions to reduce or eliminate sanding, often atlower cost and risk and with increased hydro-carbon production.24 As an important part of sand management, screenless techniquesdraw from a range of individual or combinedtechnologies such as selective, dynamicallyunderbalanced, optimally phased and orientedperforating techniques, TSO fracturing designsand indirect vertical fracturing (IVF) techniques,proppant-flowback control, and resin injectionfor formation consolidation.
Extensive research and field experience havedemonstrated the importance of perforation orientation to perforation stability and sand pro-duction. When hydraulic fracturing is planned tohelp prevent sand production, perforationsshould be aligned with the preferred fractureplane (PFP), or parallel with the maximum in-situ stress direction.25 Orienting perforationsalong the maximum in-situ stress directionreduces tortuosity, or the restrictions on near-
wellbore flow during hydraulic fracturing. Today,unsurpassed accuracy, repeatability and verifica-tion are available with the OrientXacttubing-conveyed oriented perforating system(see “Perforations on Target,” page 28).
However, for wells with perforated-only com-pletions in weak reservoirs, alignment with thePFP will not necessarily result in the most stable perforation tunnels and may instead leadto increased sand production. With a 3D sand-prediction model, the state of stress—the magnitude and direction of the three principalstresses—around the wellbore is modeled,allowing completion experts to select the perfo-ration orientations that minimize stress contrastand maximize perforation stability (previouspage, bottom).26 New oriented perforating tech-nologies have allowed the industry to exploit anincreased understanding of the relationshipbetween near-wellbore stresses and sand pro-duction. This technique has now been appliedworldwide and its use continues to grow.
Oriented Perforating Success in the North Sea Stress contrasts, or high deviatoric stresses, arethe source of many borehole-stability and sand-production problems and can be made moresevere by local geologic features such as saltdiapirs. Given the complex state of stress in thestrata adjacent to a salt diapir, BP was concerned about the potential for sand produc-tion to jeopardize well productivity and integrity,and production facilities at Mirren field, east ofScotland in the North Sea. Moreover, as thewells produce, depletion causes the effectivestress in the reservoir to increase, raising thepotential for sand production. With only two sub-sea horizontal producing wells planned for fielddevelopment, BP needed to select a completionmethod that would avoid potential sand production and minimize future interventionrequirements.
To simulate the principal stress conditions inthe presence of a salt diapir, BP constructed acomprehensive MEM for the Mirren field (below).
20. Venkitaraman A, Behrmann LA and Chow CV: “Perforating Requirements for Sand Control,” paper SPE 65187, presented at the SPE European PetroleumConference, Paris, France, October 24–25, 2000.
21. Bakker E, Veeken K, Behrmann L, Milton P, Stirton G,Salsman A, Walton I, Stutz L and Underdown D: “The New Dynamics of Underbalanced Perforating,” Oilfield Review 15, no. 4 (Winter 2003/2004): 54–67.Stenhaug M, Erichsen L, Doornbosch FHC andParrott RA: “A Step Change in Perforating TechnologyImproves Productivity of Horizontal Wells in the North Sea,” paper SPE 84910, presented at the SPE International Oil Recovery Conference in Asia Pacific,Kuala Lumpur, Malaysia, October 20–21, 2003.
22. Ali et al, reference 19.23. Ali S, Norman D, Wagner D, Ayoub J, Desroches J,
Morales H, Price P, Shepherd D, Toffanin E, Troncoso Jand White S: “Combined Stimulation and Sand Control,”Oilfield Review 14, no. 2 (Summer 2002): 30–47.
24. Acock et al, Riddles et al, and Pitoni et al, reference 11.25. Behrmann L, Brooks JE, Farrant S, Fayard A,
Venkitaraman A, Brown A, Michel C, Noordermeer A,Smith P and Underdown D: “Perforating Practices That Optimize Productivity,” Oilfield Review 12, no. 1 (Spring 2000): 52–74.Almaguer et al, reference 13.
26. Sulbaran AL, Carbonell RS and López-de-Cárdenas JE:“Oriented Perforating for Sand Prevention,” paperSPE 57954, presented at the SPE European FormationDamage Conference, The Hague, The Netherlands, May 31–June 1, 1999.
Mirrenfield
U K
Norway
2000 miles
0 200km
N o r t h S e a
Offset, m0 1,000 2,000 3,000 4,000 5,000 6,000
Dept
h, m
4,000
3,000
2,000
1,000
0
Salt
0 to 1 MPa 1 to 2 MPa 2 to 5 MPa 5 to 10 MPa 10 to 20 MPa20 to 30 MPa 30 to 40 MPa >40 MPa Surfaces
Stress contrast
> Location of Mirren field (bottom). Complex stresses surround a salt diapir in Mirren field and mustbe considered in both drilling and completion operations (top). 3D modeling predicts that the maximumstress orientation near the diapir is tilted 20° to 40° from horizontal, making perforated completiondesign more complex.
This 3D model, originally developed to providewellbore-stability information, enabled the suc-cessful drilling of two wells in the field.27
Significantly, the 3D model predicts that themaximum stress orientation near the diapir istilted 20° to 40° from horizontal, potentiallyimpacting BP sand-avoidance efforts in twoplanned horizontal production wells, the Eastand West wells. Building on the MEM, BP con-structed a geomechanical model along theplanned trajectories of two of the wells using logdata—including gamma ray, compressional traveltime, tc, and density data—core measure-ments, leakoff tests and reservoir pressure measurements from offset wells. Shear data, orts, were estimated using compressional informa-tion from the sonic tool. The dynamic rockproperties calculated from the sonic and densitymeasurements were converted to static proper-ties and then calibrated to rock strengthsmeasured in cores from offset wells. In addition,BP analyzed the average grain size in cores of theMirren field reservoir rock.
20 Oilfield Review
0 500 1,000 2,000 3,000 4,0001,500 2,500 3,500 4,5000
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
Horizontalperforations
Openholecompletion
Verticalperforations
Criti
cal b
otto
mho
le fl
owin
g pr
essu
re, p
si
Reservoir pressure, psi
> Critical drawdown pressures for three scenarios of perforated completionsin a Mirren horizontal well. The first scenario considered an openholecompletion (red). The second scenario examined drawdown conditionswhen perforations are shot horizontally (green), and the third case showsthe drawdown conditions when vertical perforations are used (blue). Thevertical perforations clearly produce the largest sand-free window andsuggest the reservoir sand should not fail until the reservoir pressuredeclines to less than 500 psi [3.4 MPa].
Critical Drawdown at2,000-psi Depletion
Critical Drawdown atInitial Reservoir Pressure
Sandstone
Shale
Sandface Failure Sandface Failure Sandface Failure
1.95 2.95gm/cm3
Bulk Density
0 60,000
UnconfinedCompressive Strength
kPa
10 -90deg
VerticalPerforation Inclination
-1,000 5,000psi -1,000 5,000psi
Critical Drawdown Critical Drawdown
-1,000 5,000psi
Critical Drawdown
Horizontal Perforation Vertical PerforationOpenhole
Dept
h, m
3,300
3,400
3,500
Critical Drawdown atInitial Reservoir Pressure
Critical Drawdown atInitial Reservoir Pressure
Critical Drawdown at3,000-psi Depletion
Critical Drawdown at3,000-psi Depletion
> Continuous critical drawdown data. Track 1 displays vertical perforation orientation, computedunconfined compressive strength (UCS) and bulk density data. The three scenarios are presented inTracks 2, 4 and 5. The openhole case is run using a depletion of 2,000 psi [13.8 MPa], while theperforated scenarios use a depletion of 3,000 psi [20.7 MPa]. The light green area represents thecritical drawdown at depletion, and the critical drawdown at the initial reservoir pressure (dark green)is also presented.
Spring 2004 21
With the Schlumberger Sand ManagementAdvisor sand-prediction model, critical draw-down pressures were calculated across theanticipated completion intervals for three differ-ent horizontal completion scenarios: openholecompletion, horizontal perforations and verticalperforations (previous page, top). Results indi-cated that resistance to sand failure dramaticallyimproves for perforated completions and sandproduction could be delayed for several years.Additionally, perforations oriented verticallywere significantly more stable than those oriented horizontally.
The critical drawdown analysis showed thatunder openhole conditions, the reservoir sandscould withstand a drawdown of 2,175 psi[15 MPa] at the initial reservoir pressure of4,550 psi [31.4 MPa]. However, simulation pre-dictions for the field-development plan indicatedthat formation pressures would deplete to theextent that any amount of drawdown wouldcause sand failure after one year of production.Searching for an alternative to sand screens,which pose a high cost of installation and a riskof failure in later life, BP explored perforatedcompletion options.
Horizontal perforations—the worst of thecased-hole perforation scenarios—wouldimprove the resistance to failure compared withthe openhole case, allowing drawdown to3,150 psi [21.7 MPa] at the initial reservoir pres-sure. After four and a half years of production,once the reservoir pressure dropped below1,350 psi [9.3 MPa], sand failure would beexpected. When perforations are oriented in themore stable vertical direction, the 3D sand-prediction model suggests that the formationshould not fail until the reservoir pressuredeclines to less than 500 psi [3.4 MPa], which isbeyond the anticipated economic life of the field.The most stable perforation orientation is actu-ally angled slightly away from vertical to increasethe distance between perforations, therebyreducing the overlap of stress concentrationsaround each perforation.
The critical drawdown analysis was extendedto include the entire completion interval toexamine the long-term effects of reservoir deple-tion (previous page, bottom). The three scenarioswere again examined and compared at the ini-tial reservoir pressure, at 2,000-psi [13.8-MPa] depletion for the openhole case, andat 3,000-psi [20.7-MPa] depletion for both thehorizontal and vertical perforation scenarios.The weakest sands and shaly intervals withinthe section were predicted to fail regardless ofperforation orientation, so the completion
design recommended that engineers avoid perfo-rating them.
The East well was drilled and completed in2002. Critical drawdown pressures were recalcu-lated using the East well log data, whichincluded density and tc and ts from an LWD sonictool. A multidisciplinary team selected perfora-tion intervals from the revised analysis, and theoriented perforating job was completed success-fully. Later in 2002, the same procedure wasfollowed on the West well. The wells were put onproduction in November 2002 and exhibitedslightly negative skin values, indicating no forma-tion damage. With the exception of some initialfine-grained sand production resulting from per-foration cleanup, the wells are producing withonly minimal sand influx, matching expectationsfrom the modeling.
Going Screenless in JapanAmarume field, operated by the Japan PetroleumExploration Company, Limited (JAPEX), is anonshore oil field close to Niigata on HonshuIsland, Japan (right). Produced since the early1960s, the field has a reservoir pressure that hasdropped from 1,800 psi [12.4 MPa] to 650 psi [4.5 MPa]. Sand production observed in six wellsled JAPEX to reduce drawdown in all the wells to55 psi [0.4 MPa].
During the planning stages of Well SK 74D,Schlumberger proposed a completion solutionthat would help limit sand production. Prior toselecting the type of completion, the planningteam characterized reservoir stresses and completed a sand-prediction analysis.
Special software was used to translate thegamma ray, density and sonic—tc and ts—datafrom a vertical offset well, the AMR TRC-1, to theplanned deviated SK 74D well. RockSolid wellbore stability software was then used to construct a 1D MEM, which was calibrated withcore-strength data from multistage triaxial tests.Borehole images were not available, but becausethe zone of interest was shallow, it was thoughtthat the orthogonal horizontal stresses were sim-ilar in magnitude. However, a previously acquiredvertical seismic profile (VSP) and the DataFRACpressure data indicated stress anisotropy did exist.
The Sand Management Advisor sand-prediction software, using the 1D MEM as input,provided the critical drawdown pressures to iden-tify potential sand-production zones. A combination of low unconfined compressivestrength (UCS) between 100 and 500 psi [0.7 and 3.4 MPa] and 60% reservoir depletionmeant that shear failure could occur at the sand-face in the perforations. During the analysis,
perforated completion parameters were examined,including perforation deviation from vertical, perfo-ration diameter and perforation orientation. Plotsshow that sand failure would occur, regardless ofthe perforating job design. The critical drawdownplots predicted sand production at any drawdownpressure and indicated a need for sand control. Thelow reservoir pressure and predicted low well pro-ductivity made any sand-exclusion screencompletion uneconomical and instead suggestedthe need for a less expensive, screenless hydrauli-cally fractured completion.
For a screenless fractured completion in this well, the following steps were identified ascritical to treatment success:• High-quality well cementing ensures good
zonal isolation across weak and depletedzones. The success of any fracturing treatmentrequires good zonal isolation to help pumpfracturing fluid and proppant to the desiredzone. Achieving zonal isolation is even more ofa challenge when cementing across depletedreservoirs where loss of circulation is antici-pated. For this well, a two-stage cementingoperation with 1.6-specific gravity LiteCRETEslurry was used.28 Cement bond logs and USIUltraSonic Imager logs indicated good bondingover the cemented intervals.
• Optimized perforating helps ensure that for-mation fluid is filtered through the proppant
2000 miles
0 200km
S e ao f
J a p a n
Pa
ci f
ic
Oc
ea
n
Ea
st
Ch
i na
Se
a
Niigata
Amarumeoil field
J A P A N
> Location of Amarume field in Japan.
27. Ali et al, reference 17.28. Al-Suwaidi A, Hun C, Bustillos J, Guillot D, Rondeau J,
Vigneaux P, Helou H, Martínez Ramírez JA andReséndiz Robles JL: “Light as a Feather, Hard as a Rock,”Oilfield Review 13, no. 2 (Summer 2001): 2–15.
as channelized, siliciclastic turbidites thatformed interbedded to massive sandstones.Reservoirs range in porosity from 20 to 30%, havepermeabilities of 500 to 2,000 mD and produce26° API gravity oil. Reservoir characteristics,such as heterogeneity and varying productivity,contribute to wide-ranging reserve estimates. Inthe P110 well, the T25 reservoir target was bestexploited by completing a 3,075-ft [937-m] hori-zontal openhole section.
Completing the long, horizontal openholesection remained a challenge; even with precisewell placement, unstable shales and sand production can severely impact well and fieldeconomics in this area. A major concern for BPand Schlumberger was a 530-ft [162-m] unstableshale section between two sandstone reservoirs.This shale had the potential to slough into thehole during gravel-packing operations, possiblycausing screenout or damage to the gravel-packpermeability. In previous wells, to help addressstability issues, oil-base mud (OBM) was used todrill horizontal sections, and stand-alone screenswere installed for sand control. In certaininstances, particularly with high water cut,stand-alone screens required lower productionrates to keep sand production manageable and toreduce erosion rates. Also, limited core data fromthe previously undeveloped T25 reservoir sug-gested these sandstones were much finer grainedand less sorted than typical sandstones in theFoinaven field. For these reasons, the BP teamworked with Schlumberger to improve sand man-agement in the P110 well.
Several techniques contributed to a success-ful completion. To reduce formation damage,part of the solution included the first use of awater-base drilling mud (WBM) in the P110 hori-zontal well. After extensive testing, BP found aWBM that fulfilled the requirements for drillingthe Foinaven reservoirs.
Studies from earlier wells determined that astand-alone screen would be inadequate to con-trol sand production from the T25 reservoir, sothe new solution also involved an openholegravel pack (OHGP), the first ever for a deep-water Foinaven field horizontal completion. The
22 Oilfield Review
29. Acock et al, reference 11.30. Wilson A, Roy A, Twynam A, Shirmboh DN and Sinclair G:
“Design, Installation, and Results from the World’sLongest Deep-Water Openhole Shunt-Tube Gravel-PackWest of Shetlands,” paper SPE 86458, presented at theSPE International Symposium and Exhibition on FormationDamage Control, Lafayette, Louisiana, USA, February18–20, 2004.
31. Naturally occurring sand and synthetic proppants arespecified according to sieve analysis based on particle-size distributions and percentage of particles retained byscreens with standard US mesh sizes.
32. Ali et al, reference 19.
Proppant-flowback control
Proppant grains held in placeby PropNET fibers
Formation consolidation
Formationsand grain
ResinOil
> Screenless hydraulic fracturing for sand control. A combination of technologies is used to create astable propped fracture that provides sand control with minimal proppant flowback. The perforatingjob was designed to optimize the creation of the fracture. After perforating, injected resin was used toconsolidate the formation around the wellbore. A TSO fracture created a tightly packed fracturecapable of providing sand control and limiting proppant flowback.
pack in the fracture prior to exiting the perfo-rations. The perforated interval was limited to6 ft [1.8 m] at zero-degree phasing and oriented at 180 degrees on the low side of theborehole. The perforation entrance-hole sizewas selected to be less than the designed fracture width.
• In-situ consolidation stabilizes unconsoli-dated rock around the perforations by injectinga resin into the formation.
• Tip-screenout (TSO) fracturing ensures tightlypacked proppant from the fracture tip to thewellbore. This is essential for filtering any sandfrom fluids during production. A key to achiev-ing a TSO fracture is determining fluidefficiency, fluid-loss coefficient and closurepressure, which can be obtained fromDataFRAC calibration and step-rate tests. Alarge difference between the assumed values offluid efficiency, fluid-loss coefficient and closure pressure compared with the DataFRACresults demonstrated the importance of thiscalibration to the success of this screenlesssand-control method.
• Proppant-flowback control improvesthe longevity of the packed fracture. For thiswell, PropNET hydraulic fracturing proppantpack fibers were added to all stages of the proppant.29
At Well SK 74D, the upper and lower B2zones were completed using the screenlesshydraulic-fracturing technique (below). Earlyresults indicate sand-free production. JAPEXoperations, completions and reservoir teamsconsidered this a successful application for con-trolling sand production.
Integrating TechnologiesSuccessful sand management requires an integrated approach to problem-solving andappropriate utilization of the latest technology.This was clearly demonstrated by BP andSchlumberger on Well P110 in the deepwaterFoinaven field, West of Shetlands (next page,top).30 The Foinaven field is a faulted anticlinalstructure, featuring dip closure, faults and strati-graphic pinchouts as trapping mechanisms.Paleocene reservoir rocks have been classified
Spring 2004 23
viscoelastic surfactant (VES) ClearPAC fluid wasselected as the carrier fluid, reducing frictionwhile pumping the gravel-pack slurry, increasinggravel-carrying capacity and minimizing damageto the gravel pack. Schlumberger tested the VEScarrying fluid for compatibility and productivitywith the WBM. The treatment incorporated theMudSOLV service to ensure that cleanup wouldbe accomplished while gravel packing. The com-patibility test showed that the ClearPAC fluidmaintained its fluid properties when introducedto the filtercake cleanup chemicals and the dis-associated filtercake, which was essential for thesimultaneous treatment. Moreover, the ClearPACfluid provided excellent shear-thinning proper-ties to the combined treatment, helping it to flowacross the troublesome shale sections withoutcausing sloughing.
BP fully characterized the reservoir’s grain-size distribution to select the optimal gravel andscreen sizes. This study included sieve, laser andscanning electron microscope (SEM) analysis onsidewall cores of the T25 reservoir from a 1994appraisal well. The company developed an inte-grated model that utilized the three differentmethods for particle-size determination. The par-ticle-size distribution model was then used tocreate an artificial core pack to test sand reten-tion and define the requirements of both thegravel and screen to be used in the completion.BP selected 30/50-mesh synthetic gravel for itshigher permeability and superior performanceduring coreflood filtercake liftoff tests.31 BP alsodecided to run 8-gauge wire-wrapped screensbecause, unlike the finer screens, they retained96% of the solids and resisted the tendency to plug.
Another crucial aspect of installing thisOHGP completion was the need to maintain acontinuous overbalanced hydrostatic pressureduring the packer-setting process so that theoperation experienced no filtercake or formationcollapse. Schlumberger accomplished this, alongwith simultaneous filtercake-cleanup treatment,using the QUANTUM packer and the horizontalopenhole AllPAC screen system.32 The systemworked as designed, maintaining positive pres-sure on the formation and filtercake during the operation (left). The use of effective
800 miles
0 80km
Foinaven
Schiehallion
Clair
Scotland
OrkneyIslands
ShetlandIslands
FPSO
DC1 DC2
Reservoir
< Location of Foinaven field in the NorthSea, West of Shetlands (bottom). Sub-sea production and injection operationsare conducted in water depths from 400 to 600 m [1,310 to 1,970 ft] from twodrilling centers, DC1 and DC2, each having a gathering manifold and well-cluster arrangement (top). A floatingproduction, storage and offshore load-ing (FPSO) vessel receives theproduction volumes through flexible risers. The Foinaven field produces from five Paleocene reservoirs within a faulted anticlinal structure (center).
, Keeping up the pressure. The plot shows the surface pumping pressurerecorded during the installation of the openhole gravel pack in the P110 well.Maintaining positive pressure on the formation and filtercake while pumpingwas critical to the successful placement of an effective gravel pack. A totalof 527 barrels [83.8 m3] of slurry, carrying 100,000 lbm [45,360 kg] of gravelwas pumped in less than two hours and resulted in 100% pack efficiency.0
1
2
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4
5
6
7
Pum
p ra
te, b
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in
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sure
, psi
0
500
1,000
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9:24:43 9:39:48 9:54:53 10:09:58 10:25:03 10:40:09 10:55:15 11:10:29Time
Star
t add
ing
grav
el
Slur
ry to
scr
eens
Slur
ry a
t tot
al d
epth
Stop
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vel
Star
t dis
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emen
t
Pump pressurePump rateMoving averagepump pressure
technology, proper planning and an integratedapproach to sand management resulted in suc-cessful packing of the entire interval.
The new completion design in the Foinavenfield performed extremely well compared withthe average performance of more than 30 hori-zontal wells in the West of Shetlands area, forboth oil production and sand-control effective-ness. An early buildup test revealed not only azero skin compared with a 28-well average skinof +4.8, but also a higher productivity index(above). During the initial production test, theP110 well showed a rate of 20,500 B/D[3,260 m3/d] with a fully open choke. This wasattributed to improved sand control and thereduced damage associated with the drilling andcompletion operations.
Testing Weak SandsNew applications for predicting sand failure con-tinue to emerge with the growing understandingof the relationship between stresses, reservoirsand completions. Operators evaluating deep-water wells in the Gulf of Mexico rely on a varietyof downhole measurements to determine reser-voir characteristics, potential reserves, requiredproduction facilities and asset-developmentstrategies. In many deepwater fields, the MDTtool has become a crucial provider of importantreservoir information. Using this device, an oper-ator can determine reservoir pressure andpermeability, evaluate whether the reservoir isdamaged, and collect and analyze representativefluid samples.33
In one of its many configurations, the MDTtool deploys a small packer and probe device thatpresses against the borehole wall, isolating theprobe from hydrostatic pressure so that forma-tion pressure can be measured. In weak orunconsolidated formations, the probes canbecome clogged, hindering testing and sampling.Depending on the specific well and reservoir, adual-packer assembly may be preferable in weak
24 Oilfield Review
Average PI = 1.5
Production slots
0
1
2
3
4
5
P13
P17
P15
P16
P18
P21
P22
P24
P25
CP01
CP03
LP01 P2
3W
P02
CP05
CP02
CP09
LP03
CP08
WP0
3CP
06 P14
WP0
1W
P07
P26
P12
CP04 P1
1CP
07 P28
P41
P29
P210
P110
CP14
Initi
al p
rodu
ctiv
ity in
dex
(PI)
Productivity Index Comparison in the West of Shetlands Area
Average skin = +4.8
Production wells
0
-5
5
10
15
20
25
30
Skin
P15
P13
P17
P18
P22
P21
P25
P27z
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P210
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P110C01
C03
C06
C07 C0
5
W02 L01
C11
C10
W05
W04
C12x C13
Total Skin Comparison in the West of Shetlands Area
> Productivity index and skin comparison. After the new completion that included the MudSOLVfiltercake cleanup service, ClearPAC fluid system, the QUANTUM packer and the AllPAC screen system,the P110 well performed much better than the majority of the wells in Foinaven field. It exhibited a higherproductivity index (left) with a skin of zero (right). The productivity index comparison was made on 35production slots, while the skin comparison was made on 28 production wells. In this case, productionslots and production wells are not comparable.
Sand Safe Drawdown
Critical Drawdown Pressure
Mea
sure
d de
pth,
ft
X,500
X,000
X,500
X,000
X,500
X,000
Clay Volume
vol/vol0 1
Porosity
vol/vol 10
0 5106 psi
Young’s Modulus
0.2 0.5
Poisson’s Ratio
0 20,000
UnconfinedCompressive
Strength
psi 8,000 18,000psi
Pore Pressure
Principal Stress X
Principal Stress Y
Principal Stress Z
20,0000 psi
G zone
I zone
> Critical drawdown log for Trident Well 1. The data from the Trident Well 1indicated that the Wilcox G zone is a serious risk because of potential formationcollapse when exposed to excessive drawdown levels during MDT testing andsampling. The Wilcox I zone was substantially more competent. Clay volume andporosity are displayed in Track 1, computed Poisson’s ratio and Young’s modulusare presented in Track 2, calculated unconfined compressive strength (UCS) isshown in Track 3, and the computed principal stresses and pore pressure aredisplayed in Track 4. Track 5 shows the critical drawdown pressures calculatedfrom the sand-prediction modeling tool.
Spring 2004 25
33. Betancourt S, Fujisawa G, Mullins OC, Carnegie A,Dong C, Kurkjian A, Eriksen KO, Haggag M, Jaramillo ARand Terabayashi H: “Analyzing Hydrocarbons in theBorehole,” Oilfield Review 15, no. 3 (Autumn 2003): 54–61.
Ayan C, Hafez H, Hurst S, Kuchuk F, O’Callaghan A,Peffer J, Pop J and Zeybek M: “Characterizing Permeability with Formation Testers,” Oilfield Review 13,no. 3 (Autumn 2001): 2–23.Badry R, Fincher D, Mullins O, Schroeder B and Smits T:“Downhole Optical Analysis of Formation Fluids,” Oilfield Review 6, no. 1 (January 1994): 21–28.
9,500
8,500
7,500
6,500
Packerpretestbuildup
Packer pretestdrawdown
Verticalinterference
testdrawdown
Cleaning upSampling
12.56.25
0 1 2 3 4 5 6
Pres
sure
at p
acke
r, ps
ia
Verticalinterference
testbuildup
Time, hr
X,580
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X,560
X,550
X,540
X,530
X,520
X,510
0 150API
Gamma Ray
True
ver
tical
dep
th, f
t
0.1 100mD
Permeability
0.2 200ohm-m
Resistivity 90-in.
Resistivity 60-in.
Resistivity 30-in.
Resistivity 20-in.
Resistivity 10-in.
1.65 2.65g/cm3
Bulk Density
NeutronPorosity
OBMI Static ImageResistive Conductive
0 120 240 360
Orientation North
0.6 0vol/vol
< MDT testing in the Wilcox G zone. Well-logdata, including borehole image data, are displayed with the MDT test and sampling configuration (left). The pressure at the dual-packer module was recorded during the MDTtool testing and sampling sequence, and showsthat the total drawdown was kept below the limits that were established by sand-predictionmodeling (above). The testing and sampling operations were successful and provided Unocal with important data to help characterizethe Wilcox reservoirs for future development.
reservoirs to eliminate the clogging problem andbecause the operator can control the drawdownpressure during testing to prevent formation collapse. Moreover, the larger volume of investigation between the two packers yieldsmore representative test results.
In the deepwater Trident Gulf of Mexicoprospect, water depths reach 9,800 ft [2,990 m]and operating conditions are harsh. Unocal Corporation used the MDT probe to measure
reservoir pressure and to take fluid samples ontwo wells, Trident Well 1 and Trident Well 2. How-ever, because many of the Wilcox zones arelaminated and have low permeability, it was diffi-cult to acquire representative test data and fluidsamples using the MDT probe. Unocal investi-gated the dual-packer assembly for use on thenext well, Trident Well 3. To fully exploit the dual-packer capability and reduce risk of forma-tion collapse, Unocal asked Schlumberger experts
to perform sand-failure analyses on the first twowells to determine the critical drawdown pres-sures in the reservoir section prior to running theMDT dual packers in Well 3. The Wilcox G zone inTrident Well 1 was identified as potentially weak,and could fail under too much drawdown duringMDT testing (previous page, bottom).
Sand-prediction modeling was not possibleon the third well because DSI data were notacquired. Because the Unocal asset team wasconfident in the correlation between wells, thecritical drawdown pressures from the first twowells were used to design MDT tests in Well 3.With the drawdown limits defined for eachWilcox zone, the MDT dual packer was posi-tioned and the pressure tests and sampling wereconducted accordingly (left). During the testing,
the MDT drawdown pressures were kept withinsafe limits, as defined by the sand-failure analysis.
In combination with the dual packer, twoother MDT probes were positioned above thedual-packer module to conduct vertical interfer-ence tests. These tests determined verticalpermeability along with the standard horizontalpermeability. The MDT operations were com-pleted successfully and safely, with no evidenceof sand failure. Armed with the MDT test resultsand samples, Unocal is now better prepared to exploit the Wilcox reservoirs in the Trident prospect.
Monitoring Sand ProductionDetermining the critical drawdown for variousstages of reservoir depletion at which wellbore orperforation failure begins to occur is a primaryfunction of the 3D sand-prediction tool. An
important element of controlling the extent ofsand production is managing the pressure draw-down and production rate throughout the life ofa well. Monitoring sand-production rates helpsoptimize production rates, calibrate models,improve sand-control methods and assess theneed for remedial work. This practice is centralto proper reservoir management. But how do pro-ducing companies know if their sand-exclusionand sand-prevention efforts are paying off, orwhether and when remediation is required?
Several methods are used to monitor sandproduction, and the success of these depends onthe extent of the problem and the nature of thewell and the completion. Surface-detection methods use sensors located at strategic posi-tions in flowlines. For example, nonintrusiveultrasonic sensors that detect particles collidingwith the interior pipe wall can be installed afterbends in subsea gathering lines. Over time, theserecordings can be used to determine whether
26 Oilfield Review
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Interpretation Center
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Diameter ofperforation = 7.62 mm
Diameter ofperforation = 12.7 mm
Diameter ofperforation = 25.4 mm
Weak rock, UCS = 20 MPa with different perforation diameters
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> Real-time monitoring and control. The negative effects of producing sand and the impact of sand-control efforts can be observed by various downholeand surface measurements. In today’s connected oil field, massive amounts of data can be transmitted and sent directly to asset teams and Schlumbergerexperts for interpretation. The data can be used to update and verify sand-prediction models and reservoir simulators, and to facilitate complete and real-time production optimization.
sand production is increasing or decreasing, andcan facilitate the estimation of hardware erosion.
Periodic downhole measurements help evalu-ate the effectiveness of sand-prevention methodsover time. For example, production logs or welltests record pressure and flow-rate data to evalu-ate damage to the completion. Gravel-packcharacterization can be accomplished using oneor a combination of wireline measurements,including RST Reservoir Saturation Tool, CHFRCased Hole Formation Resistivity, TDT ThermalDecay Time and CNL Compensated Neutron Logdata. These devices allow completion and production engineers to locate the top of agravel-pack completion and determine its cover-age and quality.34
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Monitoring the effects of sand production ona more permanent basis is accomplished byinstalling downhole sensors that record bottom-hole flowing pressure and temperature, offeringreal-time monitoring and control capabilities(previous page).35 Real-time data from downhole,subsea and surface sensors can be deliveredusing the InterACT real-time monitoring anddata delivery system to update modeling and sim-ulation tools, such as ECLIPSE reservoirsimulation software.
When Reservoirs FailMany completed and producing wells are experiencing sanding problems. Sand productioncan be relentless, with damaging effects on production rates and hardware. Early detectionthrough monitoring can detect problems andprompt intervention before problems becomesevere. However, sometimes catastrophes occurunexpectedly and result in total well failure and a need for intervention. When inter-vention is necessary, comprehensive sand-management practices help determine the best action.
When appropriate data—production, well-test, core and log data—are coupled withsand-production and well-history information,the need for, and the value of, remediation andproduction-enhancement efforts can be evalu-ated. In wells with multizone completions,proprietary Schlumberger production-allocationsoftware allocates production for each zone usingproduction-log data. This allows engineers toevaluate each zone separately, making remedialtreatments more selective.
In hydraulically fractured wells, proprietaryProFIT production analysis software helps deter-mine fracture properties so that problems thatlimit fracture effectiveness can be diagnosed andremedied. Lastly, ProCADE software allows theanalysis of well-production data to determinenear-wellbore reservoir properties and to predictwell performance as the completion scenarioschange. These powerful software tools can predict the impact of remedial efforts to gaugeboth the economics and risks.
Well-intervention techniques vary in type andcost. An operator may choose a screenlessmethod that does not require a rig, such asadding perforations, reperforating or hydraulic-fracturing techniques.36 In some cases, ventscreens can be installed without a rig. Majoroperations requiring a rig, like gravel packing orinstalling expandable screens, may be needed toachieve the best result, but these operations add costs.
When well economics justify recompletions,many sand-exclusion and sand-prevention methods again become viable options. For thisreason, recompletions mark a new opportunityfor operators and service providers to incorporate the informed decision-making process associated with thorough sand-management practices.
The Sands of TimeSophisticated sand-screen and gravel-packingtool designs have drastically improved the sand-exclusion process, adding life to wells andreserves to assets. A new sand-exclusion systemcalled expandable sand screens represents a fun-damental shift in methodology. As part of thetrue monobore, or monodiameter, vision, expand-able completions provide an efficient, single-tripalternative by expanding out to the borehole wallto reduce the annular space, thereby reducingannular flow, maximizing borehole volume andstabilizing the borehole wall. The technologyeliminates the need for other tubulars and gravelpacking, and it potentially offers higher produc-tivity than cased-hole completions. While therehave been mixed results with expandable-screencompletions, the technology continues to evolverapidly, and so far, its applicability has primarilybeen in horizontal wells that produce from well-sorted sandstone reservoirs.
Technological advances across all facets ofsand management—prediction, prevention,monitoring and remediation—reflect the scale ofthe problem and the importance of solutions.Modeling tools that predict when reservoir sand-stones will fail help E&P companies addressproblems downhole by preventing sand failureusing screenless methods or by impeding themigration of sand into the flowstream. Schlumberger continues the quest to more fullyunderstand perforation and borehole geome-chanics, and to continue to develop innovativeperforating, fracturing and sand-control comple-tion solutions.
The ability to predict surface sand volumesaccurately would be helpful. However, thisremains a daunting challenge, especially inhighly deviated and horizontal wells, because itrequires that all modes of sand transport be con-sidered. Moreover, there are added complexitiesin accounting for completion types and for vary-ing flow regimes. Improving sand-monitoringtechniques and learning how to better exploitmonitoring data in models and simulators may bea more practical approach.
As with other oilfield challenges, addressingsand-production issues will require the collabo-ration of experts, the development of effectiveand efficient processes, and the appropriate useof technologies. Producing hydrocarbons fromweak reservoirs is a tricky business because theunknowns outweigh the knowns, but the balanceis clearly tipping towards more production withless sand. —MGG
34. Carlson et al, reference 7.Olesen J-R, Hudson TE and Carpenter WW: “Gravel PackQuality Control by Neutron Activation Logging,” paperSPE 19739, presented at the 64th SPE Annual TechnicalConference and Exhibition, San Antonio, Texas, USA,October 8–11, 1989.
35. Al-Asimi M, Butler G, Brown G, Hartog A, Clancy T,Cosad C, Fitzgerald J, Navarro J, Gabb A, Ingham J, Kimminau S, Smith J and Stephenson K: “Advances inWell and Reservoir Surveillance,” Oilfield Review 14,no. 4 (Winter 2002/2003): 14–35.
36. Acock et al, reference 11.