30 Oilfield Review

Combined Stimulation and Sand Control

Specialized fracturing treatments in conjunction with gravel packing create highly conductive propped fractures that yield

sustained production increases and control fines migration in weakly consolidated reservoirs. This “frac-packing” method,

which became increasingly popular in the past 10 years, bypasses formation damage and eliminates many productivity

impairments that are common in conventional cased-hole gravel packs.

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> Fracturing for sand control. Initial frac-pack results in the early 1990s indicated improved productivity compared with conventional gravel packing (left ).As a result, frac packing now represents more than 60% of the US sand-control market (top right ), and companies providing stimulation services investheavily in research and development. These investments included construction of purpose-built vessels with high-volume mixing equipment, high-pressurepumps and sophisticated monitoring systems, such as the Schlumberger Galaxy stimulation vessel (center ).

Syed Ali David Norman David Wagner ChevronTexaco Houston, Texas, USA

Joseph Ayoub Jean Desroches Sugar Land, Texas

Hugo Morales Houston, Texas

Paul Price Rosharon, Texas

Don Shepherd Saudi Aramco Abqaiq, Saudi Arabia

Ezio Toffanin Beijing, China

Juan Troncoso Repsol YPF Madrid, Spain

Shelby White Ocean Energy Lafayette, Louisiana, USA

For help in preparation of this article, thanks to Ernie Brown and Leo Burdylo, Sugar Land, Texas, USA; MehmetParlar and Colin Price-Smith, Rosharon, Texas; PedroSaldungaray, Jakarta, Indonesia; and Ray Tibbles, KualaLumpur, Malaysia. ClearFRAC, CoilFRAC, DataFRAC, FIV (Formation IsolationValve), MudSOLV, PropNET, QUANTUM, SandCADE andScalePROP are marks of Schlumberger. Alternate Path,AllPAC and AllFRAC are marks of ExxonMobil; this technol-ogy is licensed exclusively to Schlumberger.

Summer 2002 31

Hydraulic fracturing in high-permeability reser-voirs to stop sand production is an accepted well-completion technique. Today, one of the firstdecisions during development planning for fieldsthat produce sand is whether or not to fracpack—a combination of fracture stimulation andgravel packing. More than a decade of successproves that compared with conventional gravelpacking, this technique significantly improveswell productivity (previous page).

Frac packing as a percentage of sand-controltreatments and in terms of total jobs is growingsteadily. Use of this technique increased tenfold—from fewer than 100 jobs per year during the early1990s to a current rate of almost 1000 each year. InWest Africa, about 5% of sand-control treatmentsare frac packs, and operators frac pack at least 3%of the wells in Latin America.

Advances in stimulation design, well-completion equipment, treatment fluids andproppants continue to differentiate frac packingfrom conventional gravel packing and fracturing.US operators now apply this sand-control methodto complete more than 60% of offshore wells.

Shell used the term frac pack as early as 1960to describe well completions in Germany thatwere hydraulically fractured prior to gravel packing.1 In current usage, frac packing refers totip-screenout (TSO) fracturing treatments thatcreate short, wide fractures and gravel packingof sand-exclusion screens, both in a single oper-ation. The resulting highly conductive proppedfractures bypass formation damage and alleviatefines migration by reducing near-wellbore pres-sure drop and flow velocity.

An early application of frac packing occurredduring 1963 in Venezuela, where producing com-panies performed small fracturing treatmentsusing sand and viscous crude oil and then circu-lated screens into place downhole through sandremaining inside the casing.2 This approachproved successful, but was not applied in otherareas until almost 30 years later.

In the ensuing years, operators used variousfracturing techniques to address drilling andcompletion damage that often extends deep intohigh-permeability reservoirs. These small “slug-fracture,” or “microfracture,” treatments weredesigned to address formation damage that acidsor solvents would not remove and that reperfo-rating could not bypass, especially when perfora-tion-tunnel stability was questionable in weaklyconsolidated sands.

Interest in frac packing resurfaced in the early1980s when operators began to fracture high-permeability formations using TSO techniques.3

Wider propped fractures yielded sustained pro-duction increases in the Prudhoe Bay and Kuparukfields on the North Slope of Alaska, USA, and inchalk formations of the North Sea. These resultsattracted the attention of producers in otherareas and prompted evaluation of TSO fracturingfor sand control.

Interest in frac packing increased after 1985,driven by activity in the Gulf of Mexico, wheremany conventional gravel packs do not achieveadequate productivity. Induced formation dam-age from drilling or completion fluids, cement fil-trate, overbalanced perforating and finesmigration contribute to unsatisfactory results, asdoes mechanical skin damage created by theredistribution of stresses after drilling.4

Formation collapse and sand influx as a result ofincomplete gravel packing around screens orunpacked perforations also restrict production.

Frac packing reduces pressure drops causedby formation damage and completion restric-tions, which commonly are represented by adimensionless value called skin.5 Unlike gravelpacking, frac-pack skin decreases as wells pro-duce and treatment fluids are recovered, and productivity tends to improve over time.Consequently, the trend among operators is toapply this technique in most of the wells thatrequire sand control.

1. McLarty JM and DeBonis V: “Gulf Coast Section SPEProduction Operations Study Group—TechnicalHighlights from a Series of Frac Pack TreatmentSymposiums,” paper SPE 30471, presented at the SPEAnnual Technical Conference and Exhibition, Dallas,Texas, USA, October 22–25, 1995.

2. Liebach RE and Cirigliano J: “Gravel Packing inVenezuela,” presented at the Seventh World PetroleumConference, Mexico City, Mexico, 1967, ProceedingsSection III: 407–418.

3. Smith MB, Miller WK and Haga J: “Tip ScreenoutFracturing: A Technique for Soft, Unstable Formations,”paper SPE 13273, presented at the SPE Annual TechnicalConference and Exhibition, Houston, Texas, USA,September 16–19, 1984; also in SPE ProductionEngineering 2, no. 2 (May 1987): 95–103. Hannah RR and Walker EJ: “Fracturing a High-Permeability Oil Well at Prudhoe Bay, Alaska,” paperSPE 14372, presented at the SPE Annual TechnicalConference and Exhibition, Las Vegas, Nevada, USA,September 22–25, 1985. Martins JP, Leung KH, Jackson MR, Stewart DR and Carr AH: “Tip Screenout Fracturing Applied to theRavenspurn South Gas Field Development,” paper SPE 19766, presented at the SPE Annual TechnicalConference and Exhibition, San Antonio, Texas, USA,October 8–11, 1989; also in SPE Production Engineering7, no. 3 (August 1992): 252–258.

Reimers DR and Clausen RA: “High-PermeabilityFracturing at Prudhoe Bay, Alaska,” paper SPE 22835,presented at the SPE Annual Technical Conference andExhibition, Dallas, Texas, USA, October 6–9, 1981. Martins PJ, Bartel PA, Kelly RT, Ibe OE and Collins PJ:“Small, Highly Conductive Hydraulic Fractures NearReservoir Fluid Contacts: Applications to Prudhoe Bay,”paper SPE 24856, presented at the SPE Annual TechnicalConference and Exhibition, Washington, DC, USA,October 4–7, 1992. Martins JP, Abel JC, Dyke CG, Michel CM and Stewart G:“Deviated Well Fracturing and Proppant ProductionControl in Prudhoe Bay Field,” paper SPE 24858, pre-sented at the SPE Annual Technical Conference andExhibition, Washington, DC, USA, October 4–7, 1992.

4. Carlson J, Gurley D, King G, Price-Smith C and Walters F:“Sand Control: Why and How?” Oilfield Review 4, no. 4(October 1992): 41–53.

Mechanical skin consists of localized formation damageresulting from redistribution of in-situ stresses after theremoval of rock during the drilling process, especially inextremely permeable reservoirs. Formation stresses originally supported by drilled material concentrate nearthe borehole wall, compressing or crushing the rockmatrix within a cylindrical ring around the wellbore. Thiseffect restricts pore throats and reduces near-wellborepermeability, potentially trapping fine particles thatmigrate toward the well during production. For more about mechanical skin damage: Morales RH,Brown E, Norman WD, BeBonis V, Mathews MJ, Park EIand Brown R: “Mechanical Skin Damage in Wells,”paper SPE 30459, presented at the SPE Annual TechnicalConference and Exhibition, Dallas, Texas, USA, October22–25, 1995; also in SPE Journal (September 1996): 275–281.

5. Negative skin indicates stimulation; positive skin indi-cates damage.

In the Gulf of Mexico, frac packing becameincreasingly popular beginning in the late 1980s.Amoco, now BP, performed five frac-pack com-pletions in the Ewing Bank area during 1989 and1990 by batch mixing up to 6 pounds of proppantadded (ppa) per gallon of treatment fluid.6 In1991, ARCO, now BP, performed frac packing inthe South Pass area.7 Pennzoil, now DevonEnergy, used this technique in the Eugene Islandarea.8 At about the same time, Shell began fracpacking inland wells from barges in Turtle Bayou field, Louisiana, USA. Later, Shellexpanded the use of this technique in the NorthSea and to offshore wells in Borneo, and also toonshore wells in Colombia, South America andnorthwest Europe.9

Frac-packing success led to increased use,and this technique soon became the preferredsand-control method in the Gulf of Mexico,where several thousand oil and gas leases lie inwater deeper than 3000 ft [914 m]. During 1992,BP completed frac packs in Mississippi CanyonBlock 109, where water depths range from 850 to1500 ft [260 to 460 m].10 A few years later, Shelland Chevron used frac packing to develop fieldsin water up to 3000 ft deep.

Technology transfer and frac-packing successin other areas, such as Indonesia, the North Sea,the Middle East, West Africa and Brazil, are furtherexpanding the worldwide application of this tech-nique. Operators plan to frac pack Gulf of Mexicowells in more than 4000 ft [1220 m] of water, and

in the North Sea and offshore Brazil, intend to pushthe frontier of frac packing into water as deep as6000 ft [1830 m]. Fracture stimulation and fracpacking in high-permeability reservoirs now repre-sent 20% of the fracturing market.

This article reviews the evolution of fracpacking and discusses developments in stimula-tion fluids, proppants, downhole equipment,design simulation, job execution and post-stimulation evaluation. Case histories illustrateapplication of this technique to enhance wellproductivity while preventing proppant flowbackand sand production.

Tip-Screenout FracturingGravel packs typically have some degree of damage—positive skin—and rarely achieve lowskin values consistently. Frac-pack completions,on the other hand, often result in higher produc-tivity wells than gravel packs performed below orabove fracture-initiation pressure, either byslurry packing or high-rate water packing(HRWP).11 Evaluations of wells completed duringthe past 10 years with these sand-control tech-niques show the dramatic impact of frac packingon total completion skin (below).12

The permeability contrast between forma-tions and propped fractures determines requiredfracture length for optimal reservoir stimulation.In lower permeability reservoirs, there is a largepermeability contrast, and therefore, greater relative fracture conductivity.13 In high-permeability

reservoirs, there is less contrast, and the relativeconductivity of a narrow fracture is reduced byseveral orders of magnitude. This negates thevalue of fracture extension away from a well andunderscores the need for wide fractures becauseconductivity is also directly proportional topropped width.

Short, wide fractures stimulate well produc-tivity even in high-permeability formations.These highly conductive fractures alleviate sandproduction associated with high flow rates, per-foration collapse in weakly consolidated forma-tions and fines migration in formations withpoorly sorted grain sizes by reducing near-wellbore pressure drop and flow velocity. Thesefactors also defer critical stress conditions thatcrush formation grains until a lower reservoirpressure is reached.

Hydraulic fracturing in low-permeability, ortight, formations creates narrow propped frac-tures about 0.1 in. [2.5 mm] wide, extending1000 ft [300 m] or more from a wellbore (next page,top left).14 A TSO treatment generates proppedfractures with widths up to 1 in. [2.5 cm] or morein soft-rock formations and wellbore-to-tip half-lengths of about 50 ft [15 m], depending on for-mation characteristics.15 For conventionaltreatments, final proppant concentrations interms of fracture surface area are less than2 lbm/ft2 [10 kg/m2]. This contrasts with 5 to10 lbm/ft2 [24 to 49 kg/m2] concentrations forTSO designs.

A propped fracture increases completionradius and area open to flow. Compared withradial inflow, the resulting bilinear flow patternreduces flow convergence and turbulence at theperforations, which enhances productivity. Forexample, a propped fracture with a 50-ft half-length and height of 22 ft [7 m] has 4000 sq ft[372 m2] of surface area; a gravel-pack comple-tion in a 9-in. borehole has a maximum surfacearea of about 50 sq ft [5 m2] open to radial flow.The effective completion radius for each of thesehypothetical frac-pack and gravel-pack comple-tions is 50 ft and 4.5 in. [11.4 cm], respectively.

The tip of a hydraulic fracture is the final areapacked by proppant during conventional fractur-ing of low-permeability, hard-rock formations. Incontrast, TSO designs limit fracture length, orextension, by achieving fluid-leakoff rates thatdehydrate the proppant slurry early in a treat-ment. This dehydration causes proppant to packoff near the peripheral edge, or tip, of a dynamicfracture. The hydraulic fracture inflates like a bal-loon as additional proppant-laden fluid is injected,creating a wider, more conductive pathway as prop-pant packs toward the well (next page, top right).

32 Oilfield Review

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> Completion damage. Evaluation of sand-control completions performed inthe Gulf of Mexico during the past 10 years show the dramatic impact of fracpacking on dimensionless skin, and therefore, well productivity and ultimatehydrocarbon recovery. Operators report average skins of 12 and 8 for gravel-pack completions performed by viscous-slurry and high-rate water pack(HRWP) techniques, respectively. Frac packing consistently delivers loweraverage skins, typically about 3.

Summer 2002 33

6. McLarty and DeBonis, reference 1.7. Hainey BW and Troncoso JC: “Frac-Pack: An Innovative

Stimulation and Sand Control Method,” paper SPE 23777,presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 26–27, 1992.

8. Monus FL, Broussard FW, Ayoub JA and Norman WD:“Fracturing Unconsolidated Sand Formations OffshoreGulf of Mexico,” paper SPE 24844, presented at the SPE Annual Technical Conference and Exhibition,Washington, DC, USA, October 4–7, 1992. Mullen ME, Stewart BR and Norman WD: “Evaluation ofBottom Hole Pressures in 40 Soft Rock Frac-PackCompletions in the Gulf of Mexico,” paper SPE 28532,presented at the SPE Annual Technical Conference andExhibition, New Orleans, Louisiana, USA, September 25–28, 1994.

9. Wong GK, Fors RR, Casassa JS, Hite RH andShlyapobersky J: “Design, Execution, and Evaluation ofFrac and Pack (F&P) Treatments in Unconsolidated SandFormations in the Gulf of Mexico,” paper SPE 26563, pre-sented at the SPE Annual Technical Conference andExhibition, Houston, Texas, USA, October 3–6, 1993. Roodhart LP, Fokker PA, Davies DR, Shlyapobersky J andWong GK: “Frac and Pack Stimulation: Application,Design, and Field Experience From the Gulf of Mexico to Borneo,” paper SPE 26564, presented at the SPEAnnual Technical Conference and Exhibition, Houston,Texas, USA, October 3–6, 1993.

10. Hannah RR, Park EI, Walsh RE, Porter DA, Black JW andWaters F: “A Field Study of a Combination Fracturing/Gravel Packing Completion Technique on the Amberjack,Mississippi Canyon 109 Field,” paper SPE 26562, pre-sented at the SPE Annual Technical Conference andExhibition, Houston, Texas, USA, October 3–6, 1993; alsoin SPE Production & Facilities 9, no. 4 (November 1994):262–266.

11. Slurry-packing techniques use viscous polymer-base fluids to place high gravel concentrations, while HRWPtechniques use lower gravel concentrations transportedin a less viscous fluid, usually brine.

Dynamic fracture

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> Tip-screenout (TSO) fracturing. In high-permeability reservoirs, fracturestimulations require fluid systems that leak off early in a treatment. Dehydra-tion of the slurry causes proppant to pack off at the fracture tip, halting fur-ther propagation, or extension (top). As additional slurry is pumped, biwingfractures inflate and proppant packs toward the wellbore (middle). A TSOtreatment ensures wider fractures and improves conductivity by promotinggrain-to-grain contact in the proppant pack. This technique also generatesenough formation displacement to create an annular opening betweencement and formation that becomes packed with proppant. This “external”pack connects all perforations and further reduces near-wellbore pressuredrop (bottom).

Low-Permeability Formations Bilinear Flow

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> Fracture geometry. In low-permeability formations, viscous fracturingfluids generate long, narrow fractures; less viscous fluids, such as water,leak off quickly and create shorter fractures (top left). Hydraulic fractur-ing increases effective completion radius by establishing linear flow intopropped fractures and dominant bilinear flow to a wellbore (top right). Inhigh-permeability formations, fracturing treatments create short, widepropped fractures that provide some reservoir stimulation and mitigatesand production by reducing near-wellbore pressure drop and flowvelocity (bottom left). In low-strength, or soft, formations, proppant con-centration after fracture closure must exceed 2 lbm/ft2 [10 kg/m2] toovercome proppant embedment in fracture walls (bottom right).

12. Mullen ME, Norman WD and Granger JC: “ProductivityComparison of Sand Control Techniques Used forCompletions in the Vermilion 331 Field,” paper SPE27361, presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 7–10, 1994. Monus et al, reference 8. Fletcher PA, Montgomery CT, Ramos GG, Miller ME andRich DA: “Using Fracturing as a Technique forControlling Formation Failure,” paper SPE 27899, pre-sented at the SPE Western Regional Meeting, LongBeach, California, USA, March 23–25, 1994; also in SPEProduction & Facilities 11, no. 2 (May 1996): 117–121. Hannah et al, reference 10. Papinczak A and Miller WK: “Fracture Treatment Designto Overcome Severe Near-Wellbore Damage in aModerate Permeability Reservoir, Mereenie Field,Australia,” paper SPE 25379, presented at the SPE AsiaPacific Oil & Gas Conference and Exhibition, Singapore,February 8–10, 1993.

Stewart BR, Mullen ME, Howard WJ and Norman WD:“Use of a Solids-Free Viscous Carrying Fluid in FracturingApplications: An Economic and Productivity Comparisonin Shallow Completions,” paper SPE 30114, presented atthe SPE European Formation Damage Conference, TheHague, The Netherlands, May 15–16, 1995.

13. Fracture conductivity is a measure of how easily producedor injected fluids flow within a propped hydraulic fracture.

14. Hydraulic fracturing begins with injection of a proppant-free fluid stage, or pad, at pressures above formationbreakdown stress to initiate a crack in the rock andcool-down the near-wellbore region. This pad stage cre-ates two fracture “wings” 180 degrees apart that propa-gate in the preferred fracture plane (PFP). The PFP liesin the direction of maximum horizontal stress, perpendic-ular to the least horizontal rock stress. Proppant-ladenfluid stages follow to generate a required geometry—height, width and length—and pack the biwing fracturewith proppant. Proppants ensure that a conductive path-way remains open after fluid injection stops anddynamic fractures close.

15. Hanna B, Ayoub J and Cooper B: “Rewriting the Rulesfor High-Permeability Stimulation,” Oilfield Review 4, no. 4 (October 1992): 18–23.

Fracture conductivity and reservoir stimula-tion do not account for all of the resulting pro-ductivity increase. Another factor is eliminationof flow restrictions through the perforations.Aggressive frac packing opens a dynamic frac-ture up to 2 in. [5 cm] wide across all or most ofthe completion interval. The principles of rockmechanics dictate that the amount of subsurfacemovement required to generate wide TSO fractures also must create an annular openingoutside of the cement sheath. This opening thenis packed with proppant to form a ring, or “halo,”around the wellbore.

This “external” pack provides a more effec-tive hydraulic connection between propped frac-tures and all the perforations, which furtherreduces pressure drop across completion inter-vals. Computer simulations indicate that perfora-tions that are not aligned with propped fracturecan contribute up to 50% of fluid flow into a well-bore in high-permeability formations (below).16

The proppant halo is a key factor in frac-packsuccess and the basis for screenless completionsthat control sand without mechanical screensand internal gravel packs (see “EmergingTechnologies,” page 45 ).

Frac packing is a frontline defense againstsand production, and properly designed TSO fracturing treatments are vital to the success of this important well-completion technique.Conventional cased-hole gravel packs oftenexperience progressive loss of productivity, butproduction from properly designed and executed

frac packs tends to improve over time as treat-ment fluids are recovered and wells clean up.17

Treatment ExecutionInitially, operators performed frac packing in mul-tiple steps—a TSO fracturing treatment followedby wellbore cleanout, installation of sand-exclu-sion screens and separate gravel-packing opera-tions.18 However, high positive skins and limitedproductivity indicated damage between thepropped fracture and internal gravel pack. Fracpacking was simplified into a single operation tofurther improve well production and reduce oper-ational costs.19 The TSO fracturing treatment nowis pumped with screens in place. Gravel packingof screen assemblies is accomplished at the endof a treatment.

Like conventional gravel packing, fluids andproppants for frac packing are injected throughtubing and a gravel-pack packer with a servicetool in squeeze or circulating configuration (right).However, to withstand higher pressures duringTSO fracturing, service companies adapted stan-dard gravel-packing assemblies. Modificationsinclude increased metal hardness, larger cross-sectional flow areas and minimizing suddenchanges in flow direction to reduce metal erosionby fluids and proppants.

Squeeze configuration is used for most frac-pack treatments, especially in wells with produc-tion casing that cannot handle high pressures.Circulating position provides a path for fluidreturns to surface through the tubing-casing

annulus, or communication—a “live” annulus—to monitor pressure at surface independent offriction in wellbore tubulars, depending onwhether the annular surface valve is open orclosed. Friction pressures generated by pumpingproppant-laden slurry through tubing and com-pletion equipment often mask true downholepressure responses when monitoring treatingpressure on the tubing.

34 Oilfield Review

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> Perforation contributions. Inflow is not limited to the propped fracture cross-sectional area and perforations aligned, or connected, with the fracture wings.Computer simulations indicate that unaligned perforations contribute almost50% of the inflow from high-permeability formations, underscoring the impor-tance of TSO fracturing and creation of an external pack.

QUANTUMgravel-pack packer

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> Downhole tools. In gravel packing and fracpacking, a service tool directs fluid flow througha gravel-pack packer and around the screenassembly. Squeeze configuration is establishedby closing the annular blowout preventer (BOP)and the tubing-casing annulus surface valve(left), or by closing the ball valve downhole(right). Shutting in the annulus with the downholeball valve open allows bottomhole pressure to bemonitored independent of friction in the tubing.Closing the downhole valve prevents fluid returnsto surface and protects weak casing from highpressures; pressure also can be applied to theannulus to offset high pressure in the tubing.Mechanical devices such as flapper valves orthe FIV Formation Isolation Valve system preventexcess fluid loss into formations after the servicetool is retrieved.

Summer 2002 35

Early service tools used a conventional checkvalve, which prohibited pressure declines frombeing observed after fracturing. More recentdesigns of QUANTUM gravel-pack packer toolseliminate the check valve, replacing it with animproved downhole ball valve that allows pres-sure fluctuations to be monitored in real time dur-ing treatments when the ball valve is open. A liveannulus allows more accurate evaluation of treatments.20

Frac packing usually begins in squeeze con-figuration. After tip screenout occurs, establish-ing circulating configuration ensures completepacking of the screens and grain-to-grain prop-pant contact. The service tool then is shifted toclean out excess slurry by pumping fluid downthe annulus and up the tubing. The amount ofupward movement required to shift some servicetools pulls reservoir fluids into a wellbore. Thisswabbing effect can bring formation sand intoperforation tunnels before a fracture is com-pletely packed or reduce conductivity betweenfractures and the internal gravel pack, which canlimit frac-pack productivity.

Set-down service tools, such as the QUANTUM gravel-packing system, close thedownhole ball valve and shift tool configurationwith upward movement. This type of tool also isused for deep completions and treatments con-ducted from floating rigs or drillships.

In addition to a variety of reservoir conditionsand of fracturing and gravel-packing requirements,treatment execution must address the complexityof completing multiple zones and long intervals.Even the best frac-pack designs end in failure ifexcess fluid loss into formation causes proppantbridges to form between screens and casing,restricting or blocking annular flow. Annular prop-pant packoff, or bridging, results in early treatmenttermination, low fracture conductivity and anincomplete gravel pack around screens.

Placing proppant with sand-exclusion screensin place requires close attention to annular clear-ances. As frictional pressure increases, there ispotential for fluid from slurry in the screen-casingannulus to pass through the screens into thewashpipe-screen annulus. Fluid bypass worsensas the slurry dehydrates, and proppant concentra-tion increases to an unpumpable state, causingproppant to bridge in the screen-casing annulus.

Annular blockage near the top of a comple-tion interval prevents continued fracturing ofdeeper zones or zones with higher in-situ stressand inhibits subsequent packing of the screens.Even a partial flow restriction in the annulusincreases frictional pressure drop, restricts ratedistribution and limits fracture-height growth

across the remainder of the completion interval.Annular voids below a proppant bridge increasethe likelihood of screen failure from erosion byproduced fluids and fine formation sand.

For homogeneous reservoirs where pay inter-vals are less than 60 ft [18 m] thick, fracture-height growth typically covers the entire zone. Inlonger intervals, the probability of complete frac-ture coverage decreases, and risk of proppantbridging increases dramatically. Long intervalscan be split into stages and treated separately.This requires more downhole equipment, such astwo stacked frac-packing assemblies, and addi-tional installation time, but increases frac-pack-ing effectiveness (see “Conventional andAlternate Path Screens,” next page).

Alternate Path technology is also available togravel pack and frac pack longer intervals (right).AllFRAC screens use hollow rectangular tubes, orshunts, welded on the outside of screens to pro-vide additional flow paths for slurry. Exit portswith carbide-strengthened nozzles located alongthe shunt tubes then allow fluids and proppant toexit below annular restrictions, which allowsfracturing and annular packing to continue afterrestrictions form in the screen-casing annulus.AllFRAC screens for frac packing use slightly

Screen

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> Alternate Path technology. Proppant bridges, ornodes, that form in the screen-casing annulus,commonly as a result of slurry dehydration orpremature fracture screenout in zones withlower in-situ stress, cause early treatment termi-nation. In wells with conventional sand-exclusionscreens, this limits fracture height and frac-packefficiency. Alternate Path technology uses shunttubes with strategically located exit nozzleswelded on the outside of conventional screens(top and middle). Shunt tubes provide a flow pathfor slurry that bypasses annular restrictions toallow continued treating of lower intervals andpacking of voids around the screens (bottom).

16. Burton RC, Rester S and Davis ER: “Comparison ofNumerical and Analytical Inflow Performance Modellingof Gravelpacked and Frac-Packed Wells,” paper SPE31102, presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 14–15, 1996. Guinot F, Zhao J, James S and d’Huteau E: “ScreenlessCompletions: The Development, Application and FieldValidation of a Simplified Model for Improved Reliabilityof Fracturing for Sand Control Treatments,” paper SPE68934, presented at the SPE European FormationDamage Conference, The Hague, The Netherlands, May 21–22, 2001.

17. Stewart BR, Mullen ME, Ellis RC, Norman WD and MillerWK: “Economic Justification for Fracturing Moderate to High Permeability Formations in Sand ControlEnvironments,” paper SPE 30470, presented at the SPEAnnual Technical Conference and Exhibition, Dallas,Texas, USA, October 22–25, 1995.

18. Monus et al, reference 8. 19. Hannah et al, reference 10. 20. Mullen et al, reference 8.

larger shunt tubes than AllPAC screens for gravelpacking to accommodate higher injection ratesfor fracturing.

Shunt tubes provide conduits for slurry tobypass collapsed hole and external zonal isola-tion packers as well as annular proppant gravelbridges at the top of intervals or adjacent tohigher permeability zones with high fluid leakoff.If annular restrictions form, injection pressureincreases and slurry diverts into the shunt tubes,the only open flow path. This ensures fracturecoverage and complete gravel packing aroundscreens across an entire perforated interval.

Conventional and Alternate Path ScreensIn the late 1990s, Saudi Aramco chose frac pack-ing to control sand in oil wells about 200 km[124 miles] southeast of Riyadh, Saudi Arabia(below).21 This new field in the Central Provinceencompassed two heterogeneous Permian-agereservoirs comprising high-permeability sand-stones at 8700 to 9000 ft [2650 to 2740 m] thatare interbedded with shale and siltstone.

The deeper B reservoir was a high-qualitysandstone interbedded with thin, low-permeabil-ity siltstone. Reservoir thickness varied from 20

to 65 ft [6 to 20 m]. Well tests indicated perme-ability from 0.5 to 2 darcies; air-derived core per-meabilities were 3 to 4 darcies. The A reservoirwas a sequence of slightly more heterogeneousindividual sandstones between lower permeabil-ity siltstone strata. This overlying reservoir wasup to 200 ft [61 m] thick with net pay up to 75 ft[23 m]. Permeabilities from well tests were 0.1 to2.5 darcies; air-derived core permeabilities wereabout 2 darcies.

A well completed without sand-control mea-sures produced for less than six months beforesand influx and suspected perforation collapsestopped production. If completion practicesinduced a significant pressure drop downhole, itwould be difficult to control sand at oil rates andwellhead pressures that met production targetswhile allowing wells to flow naturally into exist-ing facilities 50 km [31 miles] away. Frac packingsatisfied well-completion requirements for boththe A and B reservoirs.

Long completion intervals necessitated differ-ent frac-packing techniques for each reservoir(next page, top). Saudi Aramco used conventionalscreens in the B reservoir where pay zones wereless than 60 ft thick. For longer perforated inter-vals in the A reservoir, the operator chose

AllFRAC Alternate Path screens with three shunttubes, each designed for 6 bbl/min [1 m3/min], toachieve required injection rates (next page, bottom).

Wells with an oil-water contact near the bot-tom perforations required close control of frac-ture height to avoid early water breakthrough. Inother wells, perforations extended over longintervals and individual zones were spaced farapart. Engineers selected a stacked-screen com-pletion to meet frac-packing objectives in thesewells. Dividing the productive interval into twosections allowed Saudi Aramco to optimize treat-ment designs for each zone and avoid fracturinginto water-bearing zones.

Typically, these frac-packing treatmentsincluded the pad, an initial low-concentrationstage with 0.5 lbm/gal [0.06 kg/L], or pounds ofproppant added (ppa) per gallon of fracturingfluid, and additional proppant stages ramped upto 3, 6 or 9 ppa [0.36, 0.72 or 1 kg/L]. In a fewwells, 9-ppa stages were pumped successfully.Higher proppant concentrations were difficult toplace in more permeable zones, but placing 3 and6 ppa in the formation yielded good results.

Saudi Aramco and Schlumberger modified ini-tial fracturing designs based on minifractureanalysis using the Schlumberger DataFRAC frac-ture data determination service (see “Design andImplementation,” page 38). Fracture-closurestress, fluid-leakoff coefficient and fractureheight from these pretreatment injectivity testshelped ensure that the main treatments achieveda tip screenout. The operator adjusted pad andproppant stages as needed and accounted forhigh fluid leakoff in the B sand by increasing the maximum injection rate to 18 bbl/min [2.9 m3/min]. Engineers also restricted pumprates to 16 bbl/min [2.5 m3/min] for the A-reser-voir Alternate Path completions to limit friction pressure in the shunt tubes.

The operator performed post-treatmenthydrochloric [HCl] acid jobs on some wells toreduce cleanup time. Other wells cleaned upwithin two months without acid treatments.Overall well productivity continued to improve astreatment fluids were recovered. Experience fromthe first wells helped optimize frac-packing pro-cedures. Saudi Aramco reduced polymer concen-trations in treatment fluids and includedslow-release encapsulated breakers to optimizefracture placement and post-treatment cleanup.

36 Oilfield Review

21. Shepherd D and Toffanin E: “Frac Packing UsingConventional and Alternative Path Technology,” paperSPE 39478, presented at the SPE InternationalSymposium on Formation Damage Control, Lafayette,Louisiana, USA, February 18–19, 1998.

Riyadh

Welllocations

Saudi Arabia

EUROPE

AFRICA

SAUDI ARABIA

IRAN

IRAQ

SUDAN

ERITREA

EGYPT

YEMEN

OMAN

UAE

Re

dS

e a

Th e

G u l f

A r a b i a nS e a

0

0 300 600 900 km

200 400 600 miles

> Sand-control completions onshore. In the late 1990s, Saudi Aramco beganfrac packing new oil-well completions in central Saudi Arabia about 200 km[124 miles] southeast of Riyadh. These frac packs controlled sand influx andreduced downhole pressure drop, allowing the wells to flow naturally intofacilities 50 km [31 miles] away under existing intake-pressure conditions.

Summer 2002 37

0Gamma Ray, API Depth, ft

8800

8850

8900

8950

9000

9050

Resistivity, ohm-m200 2 3

Perforations

Flapper valve

Washpipe

Tubing

Bottompacker

Conventional

Gravel-packpacker

< B-sand completions. A typical well log indi-cates a maximum pay interval of about 65 ft withclosely spaced perforations in the B reservoir(left). Relatively short perforated intervals allowedSaudi Aramco to install a single completion andfrac pack these lower sands using standardscreens (right).

0Gamma Ray, API Depth, ft

8800

8850

8750

8900

8950

9000

Resistivity, ohm-m100 2 3

Perforations

Tubing

Gravel-packpackerFlapper valve

Gravel-packpacker

Flapper valve

packer

< A-sand completions. A typical well log showsperforations across a 180-ft [55-m] interval of theA reservoir (left). Saudi Aramco performed twoseparate treatments using a stacked-screenassembly to frac pack these longer intervals(right). Standard screens were used for the low-est zone, which was shorter. AllFRAC screenswith shunt tubes were installed to complete thelonger upper zone.

The initial group of wells included five com-pletions with conventional screens in the Breservoir and five completions in the A reservoirwith AllFRAC screens that successfully treatedintervals up to 200 ft. Two completions in the Areservoir used stacked-screen assemblies.Treatments were pumped through 9000 ft of 3-in.outside diameter (OD) tubing at surface injectionpressures below 10,000 psi [69 MPa] and pumprates of 14 bbl/min [2.2 m3/min] to 18 bbl/min.

The operator performed well tests by flowingthrough surface facilities or with downhole pro-duction logging tools to evaluate 12 frac-packingtreatments on the first 10 completions in thisfield (left). Except for two, these frac-pack completions yielded low completion skin andgood sand control in formations with up to 3-darcy permeability.

A positive frac-pack skin is caused by inade-quate connectivity between propped fracturesand wellbores, incomplete zone coverage or fail-ure to achieve a high-conductivity TSO fracture. Ifthese conditions produce a completion skin of 8or more, well productivity may be no better thanthat of a conventional gravel pack. Achievingoptimal frac-pack performance, as in the case ofthese Saudi Aramco wells, requires detailed pre-liminary designs, careful proppant and fluidselection, accurate pretreatment injectivity test-ing and treatment optimization as needed.

Design and ImplementationDuring the initial design of frac-packing treat-ments, completion engineers determine requiredfracture geometry based on reservoir conditions,rock properties and barriers to fracture-heightgrowth. Fracture length and, more importantly forhigh-permeability formations, fracture widthenhance well productivity. Operators select anoptimal TSO fracture design by maximizing thenet present value (NPV) from enhanced well pro-ductivity (left).22

Proppant selection—The type of proppantchosen to keep fractures open and form a granularfilter is an important design consideration. Frac-packing success is due, in part, to larger proppantsizes than those commonly used in gravel packing.High concentrations of large, spherical proppantsminimize embedment and offset the effects of tur-bulent flow in propped fractures.

Operators use various grain sizes and proppant types, including natural sand, custom-sieved sand, resin-coated sand and intermediateor high-strength man-made ceramic proppants,depending on formation stress and fracture-closure pressure. Proppants for frac packingshould accomplish four fracturing objectives:

38 Oilfield Review

20

Well

Dim

ensi

onle

ss s

kin

0

-5

10

15

5

1

11

3

0

2

20

53 3

1

-1

2 3 4 5 6 7 8 9 10

> Frac-pack performance. Saudi Aramco has frac packed 23 wells in the Cen-tral Province of Saudia Arabia and published results from an initial group of10 wells completed with 12 frac packs. In Wells 6 and 7, the operator usedstacked-screen assemblies and divided the completion intervals into twostages to optimize treatment designs and avoid fracturing into an underlyingwater-bearing zone. Premature screenout and early treatment termination inWells 2 and 5 contributed to high skins and poor productivity, confirming thatfracture conductivity and connectivity with the wellbore are critical factors.Eight wells had skins below those expected in conventional gravel packs andtypical frac packs.

3.520

2030 40

50 6070 6

7

8

9

Proppant concentra

tion, lb

m/ft2

Fracture half-length, ft

Optimal

10

11

3.53

3.54

3.55

3.56

Net

pre

sent

val

ue (N

PV),

mill

ions

of d

olla

rs

3.57

3.58

3.59

3.60

> Frac-pack economics. Optimal fracture half-length and width maximize netpresent value (NPV). In this example, the optimal fracture length and width, orproppant concentration, are 30 ft [9 m] and 7 lbm/ft2 [34 kg/m2], respectively.Discounted operating costs and incremental income are expressed in pre-sent-day value. Completion and stimulation investments and discounted oper-ating costs are subtracted from discounted incremental income to arrive atthe NPV for a treatment. Incremental income increases for longer and widerfractures, but at some point increasing costs for larger treatments yielddiminishing returns.

Summer 2002 39

• provide an effective permeability contrast• control sand influx and fines migration• minimize proppant embedment in soft rock• maintain fracture conductivity without

proppant crushing.In the past, gravel-packing considerations

dominated proppant selection.23 Gravel packsrequire gravel, or sand, sized to prevent forma-tion particles and fines from invading the annularpack. The widely accepted Saucier rule dictatesthat sand, or gravel, particles be five to six timesthe mean particle diameter of formation grains.24

Fracture permeability and conductivity improveas proppant sizes become larger, but productionof formation sand grains and fine particles thatreduce pack permeability also increases. Fracpacks require proppants sized to optimize frac-ture permeability.

In the early 1990s, operators began evaluat-ing larger sizes of stronger proppants to increasefracture permeability and relative conductivity inhigh-permeability reservoirs.25 For example,larger 20/40-mesh proppants were used used forfrac packing instead of smaller 40/60-mesh prop-pants often required for gravel packing.26

Experience indicated that proppant sizes dictatedby gravel-packing criteria could be increased tonext larger size for frac packing.

Saucier criteria for sizing proppants in relationto formation grain size were relaxed in frac-packdesigns because the large flow area of hydraulicfractures mitigates formation failure and sandinflux. Balancing the mechanisms of sand produc-tion—flow velocity, proppant particle sizes andfluid properties—allows operators to increasefracture conductivity and improve frac-pack performance by using larger proppant sizes.

Completing deeper wells with high fracture-closure stresses led operators to use more man-made ceramic proppants because they arestronger and their consistent spherical shapereduces embedment, which also increases frac-ture conductivity (above right). The majority offrac packs use ceramic 20/40-mesh intermedi-ate-strength proppant (ISP) when reservoirs havegood pressure support and closure stresses arenot excessive.

Fluid selection—After evaluating reservoircharacteristics, engineers choose an optimalfluid for combined stimulation and gravel pack-ing. The polymer-based hydroxyethylcellulose(HEC) fluids used in gravel packing, hydroxypropylguar (HPG) fracturing fluids with a boratecrosslinker for additional viscosity, and morerecently, viscoelastic surfactant (VES) fracturingfluids, all are applicable. Frac-packing fluids musthave a variety of properties.27

Fluid selection depends primarily on TSO frac-turing criteria. Unlike massive hydraulic fracturestimulations in low-permeability formations, alow leakoff rate, or high fluid efficiency, is lessdesirable for frac packing. In fact, a somewhatinefficient fluid helps achieve tip screenout andpromote grain-to-grain proppant contact fromfracture tip to wellbore.

However, frac-packing fluids also must maintain sufficient viscosity to create widedynamic fractures and place high proppant con-centrations that ensure adequate conductivityafter fracture closure.28 After tip screenout, fluidsystems transport proppant in the low-shearenvironment of a wide dynamic fracture, but alsomust suspend proppant under higher shear ratesin tubing, around screen assemblies, through the perforations and during fracture initiation and propagation.

Fluid viscosity should break easily to minimizeformation and proppant-pack damage after treat-ments. Optimal fluids need to be compatible withformations and chemicals such as polymer break-ers; they must also produce low friction and cleanup quickly during post-treatment flowback. To max-imize retained fracture conductivity, operators

exercise great care with viscosity breakers oracid treatments after frac packing to optimizepost-treatment cleanup for maximum productiv-ity and hydrocarbon recovery. Finally, frac-pack-ing fluids should be safe, cost-effective and easyto mix, especially in offshore applications.

22. Morales RH, Norman WD, Ali S and Castille C: “OptimumFractures in High Permeability Formations,” paper SPE36417, presented at the SPE Annual TechnicalConference and Exhibition, Denver, Colorado, USA,October 6–9, 1996; also in SPE Production & Facilities 15,no. 2 (May 2000): 69–75.

23. Monus et al, reference 8. 24. Saucier RJ: “Considerations in Gravel Pack Design,”

Journal of Petroleum Technology 26, no. 2 (February1974): 205–212.

25. Hainey BW and Troncoso JC: “Frac-Pack: An InnovativeStimulation and Sand Control Technique,” paper SPE23777, presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 26–27, 1992.

26. Naturally occurring sand and man-made ceramic prop-pants are specified according to sieve analysis based onparticle-size distributions and percentage of particlesretained by screens with standard U.S. mesh sizes.

27. Hainey and Troncoso, reference 25. 28. Morales RH, Gadiyar BR, Bowman MD, Wallace C and

Norman WD: “Fluid Characterization for Placing anEffective Frac/Pack,” paper SPE 71658, presented at theSPE Annual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 30–October 3, 2001.

1000

Perm

eabi

lity,

darc

ies

0 2 4 6 8 10 12Closure stress, 1000 psi

100

10

30/50 Ceramic20/40 Natural sand40/60 Natural sand

20/40 ISP ceramic20/40 Ceramic

> Proppant specifications. In the mid-1990s, operators began using larger,stronger and more conductive proppants in frac-pack completions. Man-made ceramic materials have since become the proppant of choice in the USGulf of Mexico to maintain fracture conductivity at higher closure stress indeeper formations. For example, switching from smaller 40/60-mesh sand(green) to a larger intermediate-strength 20/40-mesh ceramic proppant (yel-low) increases proppant permeability and fracture conductivity by a factor ofsix in laboratory tests at 2000 psi [13.8 MPa] of closure pressure (inset ). Anintermediate-strength proppant (ISP) is priced competitively with custom-sieved natural sands.

Fluids based on HEC have many preferredfrac-packing characteristics, but also severaldrawbacks. Systems based on HEC exhibitincreased friction pressures compared withdelayed crosslinked HPG or VES fluids, and fric-tional losses become significant in deeper wellsor smaller diameter tubulars. In addition, prop-pant transport characteristics for HEC fluids arenot as good as those of crosslinked HPG or VESfluids. High temperatures cause HEC fluids to thin,and viscosity is not as high at low shear rates.

High-viscosity crosslinked HPG systems leavesome polymer residue, but maximize fracture-height growth in moderate- to high-permeabilityformations. They also perform well in longerintervals and transport higher proppant concen-trations for greater fracture conductivity.Pumping pressures increase with HPG systems,but service companies can used a delayedcrosslinker to reduce tubular friction.

Delayed-crosslink HPG fluids start at a lowerviscosity and require less hydraulic horsepowerto pump downhole. Prior to reaching the perfora-tions, temperature in the wellbore and fluid pHcause the viscosity of these fluids to increase inorder to achieve low fluid-leakoff rates. Themajority of frac packs are pumped withcrosslinked or delayed-crosslink HPG fluids.

Viscoelastic ClearFRAC polymer-free fracturingfluids, introduced in the mid-1990s, use a VES liq-uid-gelling agent to develop viscosity in lightbrines. This type of fluid provides low friction pres-sures while pumping, enough viscosity at lowshear rates for good proppant transport, adequateleakoff rates to ensure tip screenout and highretained permeability for better fracture conduc-tivity. Field data also indicate that fracture con-finement using VES fluids is better than withconventional fracturing fluids, which is an advan-tage when frac-packing near water-bearing zones.

These VES systems mix easily and do notrequire additives such as bactericides, breakers,demulsifiers, crosslinkers, chemical buffers ordelayed-crosslink agents. Systems based on VESalso are not susceptible to bacterial attack. Ifwells must be shut in for extended periods beforeflowback and cleanup, solids-free ClearFRAC flu-ids are recommended to avoid precipitation ofdamaging polymer materials.

Fluids based on HEC and VES systems mini-mize formation damage in zones with low to mod-erate permeability, but high leakoff rates anddeeper invasion often result in slower recovery oftreatment fluids.29 Adding enzyme or oxidizingbreakers to frac-packing fluids reduces formationdamage and improves well cleanup. Slow-release

40 Oilfield Review

Shea

r rat

e, s

ec1

Visc

osity

, cp

0 10 20 30 40100

1000

10,000

45 ppt

40 ppt

35 ppt

Fluid shear

Time, min

Fracture extension Tip screenout0.1

1

10

100

1000

> Fluid viscosity versus typical shear rate (blue) in laboratory tests.Under frac-packing conditions of fracture extension and tip screenoutin an Amoco, now BP, Matagorda Island field in the US Gulf of Mexico,a 35-ppt crosslinked HPG fracturing fluid (green) exhibited adequateviscosity behavior, while 40- and 45-ppt systems (red and gold, respec-tively) had unneccessarily high viscosities.

70

60

50

40

30

Gas

rate

, MM

scf/

D

20

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01 2 3 4

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50 ppt 35 ppt

> Improving frac-pack productivity. Production from frac-pack completions ina field of the Gulf of Mexico Matagorda Island area doubled after Amoco,now BP, began using an optimized 35-ppt crosslinked HPG fluid (Wells 5–7)instead of an initial fluid system with 50-ppt polymer concentration (Wells 1–4).Well 7 also had a high productivity ratio, but output was limited by small pro-duction tubing.

Summer 2002 41

encapsulated breakers deposited in the proppantpack allow higher breaker concentrations to beused without sacrificing fluid efficiency.

In addition to fluid leakoff and friction pres-sure considerations, shear rate and temperatureare critical in selecting frac-packing fluids andpolymer concentrations.30 The first frac-packtreatments were performed using the same HECfluid systems as gravel-packing operations. Later,a shift to more conventional fracturing fluidsoccurred because of increasing temperaturerequirements and the need to maximize fractureconductivity in high-permeability formations.

Initially, selection criteria for these fluidswere similar to those of conventional fracturingapplications in which narrow hydraulic fracturesin consolidated, low-permeability formations cre-ate high shear rates with low fluid-leakoff rates.These factors result in breakdown of fluid viscos-ity and less cooling of formations, and greaterpolymer concentrations are required to maintainviscosity throughout a treatment. The use ofhigher polymer concentrations carried over intofracturing and frac-packing designs for high-permeability reservoirs.

In frac packing, however, fractures are widerwith lower fluid velocities and shear rates.Pretreatment fluid injection also decreases for-mation temperature near the wellbore. Pumpinglarge volumes of treatment fluid decreases heattransfer from a reservoir, resulting in cooler tem-peratures inside a fracture. Failure to considerthese effects results in use of higher polymerconcentrations than actually required. Thisincreases the potential for formation damage anddecreases the likelihood of a tip screenout.

For example, because of differences in shearrate, a crosslinked fluid with a polymer loading of 20 lbm/1000 gal (ppt) [2.4 kg/m3] of base fluid can have the same viscosity in a high-permeability formation as a 40-ppt [4.8-kg/m3]fluid in a low-permeability formation. Proper fluidselection and specification dramatically increasefrac-packing efficiency and well productivity.

In 1996, Amoco, now BP, completed fourMatagorda Island wells in the western Gulf ofMexico by frac packing.31 The reservoir tempera-ture was 300ºF [150ºC], so the operator chose ahigh-viscosity 50-ppt [6-kg/m3] crosslinked HPGfluid that was also used in fracture-stimulationtreatments for low-permeability reservoirs.Production from these frac-pack completions wascomparable to that of gravel-packed wells. Theoperator attributed the relatively poor perfor-mance to lack of tip screenout because ofimproper fluid design.

The operator and Schlumberger evaluated theeffects of shear rate on fluid properties in orderto remedy poor performance (previous page,top).32 Based on the results of this investigation,frac-pack treatments on the next three wellsused a 35-ppt [4.2-kg/m3] fluid. Fluid efficiencydecreased because of lower viscosity, allowingbetter slurry dehydration, which achieved desiredTSO results. Average daily production from thesewells doubled compared with the initial fourwells (previous page, bottom).

Pretreatment testing—Laboratory testingand history matching of previous treatments pro-vide insight into stress profiles and the perfor-mance of treatment fluids, but in-situ formationproperties vary significantly in high-permeabilityunconsolidated reservoirs. After developing preliminary stimulation designs, engineers per-form a pretreatment evaluation, or minifracture,to quantify five critical parameters, includingfracture-propagation pressure, fracture-closurepressure, fracture geometry, fluid efficiency and leakoff.33

This procedure consists of two tests, a stresstest and a calibration test, performed prior to themain treatment to determine specific reservoirproperties and establish the performance charac-teristics of actual treatment fluids in the payzone. A stress, or closure, test determines mini-mum in-situ rock stress, which is a critical refer-ence pressure for frac-pack analysis andproppant selection (above).

A calibration test involves injecting actual frac-turing fluid without proppant at the design

treatment rate to determine formation-specificfluid efficiency and fluid-loss coefficients.Fracture-height growth can be estimated by tag-ging proppants with radioactive tracers and running a post-treatment gamma ray log. A pressure-decline analysis confirms rock prop-erties and provides data on fluid loss and fluid efficiency.

An integral part of pretreatment testing is live-annulus monitoring and real-time measurementsfrom downhole quartz gauges to obtain pressureresponses independent of frictional pumping pres-sures. Accurate analysis using DataFRAC servicesensures that the current frac-pack design and sub-sequent treatments achieve wide fractures with atip screenout for optimal results.

Surface data from pretreatment tests com-bined with bottomhole injection pressures arehistory matched using a computer simulator,such as the SandCADE gravel-pack design andevaluation software, to calibrate the fracturingmodel and finalize treatment design. Calibrateddata from DataFRAC analysis are also used toassess stimulation effectiveness during post-treatment evaluations.

29. Monus et al, reference 8. 30. Morales et al, reference 28. 31. Norman WD, Mukherjee H, Morales HR, Attong D,

Webb TR and Tatarski AM: “Optimized Fracpack DesignResults in Production Increase in the Matagorda IslandArea,” paper SPE 49045, prepared for presentation at the SPE Annual Technical Conference and Exhibition,New Orleans, Louisiana, USA, September 27–30, 1998.

32. Morales et al, reference 28. 33. Monus et al, reference 8.

Botto

mho

le p

ress

ure

Time

Increasinginjection

rate

Constantinjection

rate

Constantflowback

Shut in Constantinjection rate

Net pressure

Fracture closure pressure

Instantaneous shut-inpressure (ISIP)

Fracture-extensionpressure

Reboundpressure

Pressurefalloff

> Pretreatment minifracture testing. Stress, or closure, tests involve injecting low-viscosity, nondam-aging fluid at increasing rates to initiate a fracture and determine the pressure required to propagate,or extend, fracture length. Fracture-closure pressure is determined by monitoring pressure declineduring a slow, constant-rate flowback.

Treatment design, particularly TSO fracturestimulation, is critically important to successfulfrac packing. If premature screenout or failure toachieve a tip screenout results in insufficientfracture width to overcome proppant embedmentin the formation, well productivity may, at best,be equivalent to that of a conventional gravelpack. Standard frac-packing practice is toredesign treatments on-site after minifracturetesting and analysis are complete.

Treatment design—Previously, frac packs,which sometimes failed because of prematurefracture screenout or early annular packoff, were designed solely using hydraulic-fracturingsimulators that neglected gravel-packing andcompletion equipment inside the wellbore, suchas crossover ports in gravel-pack packers, blankpipe, screens and washpipe. With the SandCADEsimulator, engineers now specify tip-screenoutdesigns and simulate frac-packing treatmentsusing coupled wellbore and hydraulic-fracturingsimulators.34 This software also simulates slurryflow including the effects of well inclination,gravel setting and bridging around screens, andfluid flow through packer and screen assemblies.

The fracture simulator supports tip-screenoutdesigns in high-permeability formations. Inducing

gravel packoff in wellbores by deliberately reduc-ing pump rate or shifting service tools to circulateat the end of a treatment also can be modeled.The SandCADE simulator also models fracturingof multiple layers and shunt-tube flow (below).

Well-Completion ApplicationsFracturing designs based on TSO technology,larger proppant particle sizes, advances in frac-turing fluids and improved treatment evaluationcombined with more robust and versatile pump-ing equipment and downhole tools make fracpacks a viable completion alternative in manywells. Experience from more than 4000 Gulf ofMexico frac packs in formations with permeabil-ities ranging from 3 mD to 3 darcies helps oil andgas producers identify frac-pack candidate wells(next page, left). Frac-packing well-completionapplications include the following:• wells prone to fines migration and sanding• high-permeability, easily damaged formations• high-rate gas wells• low-permeability zones requiring stimulation• laminated sand-shale sequences• heterogeneous pay zones• low-pressure and depleted reservoirs.35

Today, operators select sand-control methodsby determining first if conditions justify frac packing. There are 11 major advantages to frac packing:• bypass formation damage• increase completion radius and flow area• reduce pressure drop and fluid velocity• connect individual laminated zones• re-stress borehole relaxation after drilling• alleviate fines migration and sand production• improve well productivity• achieve consistent low-skin completions• sustain increased production• maintain completion longevity• reduce the likelihood of sand-control failure.

Most wells requiring sand control benefitfrom frac packing. Exceptions include locationswhere high-pressure pumping equipment isunavailable, wells with casing sizes that are lessthan 5 in., wells with weak casing when there isa risk of failure and loss of wellbore integrity orcompletions with a possibility of fracture-heightgrowth into water or gas zones. Frac packing alsomay not be economical for low-rate wells, water-source or injection wells that do not pro-duce revenue directly, and reservoirs with

42 Oilfield Review

35603580360036203640366036803700

37803800382038403860388039003920

38803900392039403960398040004020

-0.1 0Fracture widthat wellbore, in.

Fracture half-length, ft Fracture widthat wellbore, in.

Fracture half-length, ft0.1 0 10

Dept

h, ft

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20 30 40 50 60 70 80 90

35603580360036203640366036803700

37803800382038403860388039003920

38803900392039403960398040004020

-0.1 0 0.1 0 10 20 30 40 50 60 70

Proppantconcentration,lbm/ft2

0–22–44–66–88–1010–1212–14>14

> Modeling frac-packing treatments. The Schlumberger SandCADE simulator is the only commercially available software that accounts for completion andgravel-packing equipment. A hydraulic-fracturing simulator that calculates fracture geometry, proppant distribution in fractures, and two-dimensional fluidflow as boundary conditions is coupled to wellbore simulator, which models fluid and slurry flow in the screen-casing annulus and Alternate Path shunttubes. A special feature simulates fracturing of multiple layers with or without shunt tubes. This example illustrates simultaneous frac packing of threezones. Without shunt tubes, the treatment places most of proppant in the middle zone (left). Alternate Path screens ensure treatment of the entire comple-tion interval as well as more uniform fracture lengths and widths (right).

Summer 2002 43

limited reserves or homogeneous thick zoneswhere horizontal gravel packing in openhole ismore appropriate.36

In more prolific reservoirs, flow turbulenceassociated with perforated casing restricts pro-duction, so operators often drill and completeopenhole horizontal wells to optimize productiv-ity. Stand-alone screens, openhole gravel packsor expandable screens are sand-control optionsin these settings, especially for thick reservoirsections. Frac packing in openhole completions isthe next logical step to provide long-term sandcontrol without sacrificing productivity.

Openhole Frac PackingWiduri field, operated by Repsol YPF, lies off-shore in the Java Sea, Indonesia (above). Drilledin an area scheduled for waterflooding, Well B-28 targeted a thin sandstone of the Talang Akarformation at 3500 to 3600 ft [1067 to 1097 m]with 29% porosity and 1- to 2-darcy perme-ability.37 Original reservoir pressure was 1350 psi [9.3 MPa], but solution-gas drive andweak aquifer support resulted in rapid depletionto 600 psi [4 MPa]. Moderate consolidation and atendency to produce sand mandated sand-controlcompletions. Initially, wells were completed ascased-hole gravel packs. Because of lower reser-voir pressure, the operator planned cased-holefrac packs for new wells.

34. Sherlock-Willis T, Romero J and Rajan S: “A CoupledWellbore-Hydraulic Fracture Simulator for RigorousAnalysis of Frac-Pack Applications,” paper SPE 39477,presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 18–19, 1998.

35. Hannah et al, reference 10. Ayoub JA, Kirksey JM, Malone BP and Norman WD:“Hydraulic Fracturing of Soft Formations in the GulfCoast,” paper SPE 23805, presented at the SPEInternational Symposium on Formation Damage Control,Lafayette, Louisiana, USA, February 26–27, 1992. DeBonis VM, Rudolph DA and Kennedy RD:“Experiences Gained in the Use of Frac Packs inUltralow BHP Wells, U.S. Gulf of Mexico,” paper SPE

High-Permeability Reservoirs

Low-Permeability Reservoirs

Laminated Sand-Shale Sequences

WellboreShaleSand

Proppant

> Frac-pack applications. Frac packing is aviable completion alternative for many wells inreservoirs with sand-production tendencies.

In reservoirs with moderate to high permeabil-ity that are susceptible to drilling and completiondamage that extends deep into the formation,frac packing and wide TSO fractures connectreservoirs and wellbores more effectively.

For reservoirs with heterogeneous pay or lami-nated sand-shale sequences, frac packing pro-vides an effective hydraulic connection acrossmost of a completion interval. When perforated-interval length is limited, frac packing connectsmore pay with fewer perforations.

In low-permeability reservoirs, fracture exten-sion increases the wellbore drainage radius, andbilinear flow stimulates well productivity. In for-mations with low bottomhole pressures, fractur-ing bypasses perforating debris and damage,mitigating the impact of overbalanced perforat-ing. Frac-pack completions also improve hydro-carbon recovery from low-pressure anddepleted reservoirs by minimizing completionskin across the pay interval, thus reducing draw-down and ultimate abandonment pressure.

MALAYSIA

Singapore

JakartaINDONESIA

BORNEOAndaman Sea

Timor Sea

Widuri field

0

0 300 600 900 km

200 400 600 miles

ASIA

AUSTRALIA

Indonesia

> Openhole frac packing. Repsol YPF chose to frac pack an openhole com-pletion located north of Jakarta, Indonesia, in the offshore Widuri field tomaximize well productivity.

27379, presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 7–10, 1994.

36. Ali S, 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.

37. Saldungaray PM, Troncoso J, Sofyan M, Santoso BT,Parlar M, Price-Smith C, Hurst G and Bailey W: “Frac-Packing Openhole Completions: An Industry Milestone,”paper SPE 73757, presented at the SPE InternationalSymposium and Exhibition on Formation DamageControl, Lafayette, Louisiana, USA, February 20–21, 2002.

An unexpected low bottomhole pressure of390 psi [2.7 MPa] resulted in complete fluid losswhile drilling the B-28 well. A high-pressure,reactive shale above the pay zone required thatthe operator set 7-in. casing to isolate this poten-tially unstable section. Hole collapse caused thiscasing string to be set high, leaving 70 ft [21 m]of shale exposed after drilling deeper. Repsol YPFsuspended the well temporarily after attempts torun a screen assembly failed.

After five months of waterflooding, reservoirpressure increased enough to hold a water col-umn and maintain hole stability. Repsol YPFdecided to attempt an openhole frac packbecause running 5-in. casing was too restrictivefor an internal gravel pack. This approach presented several challenges, including openholestability, screen deployment, fracturing a longhigh-permeability section, proppant slurry con-tamination in exposed shale and annular packingefficiency in a 70º inclined wellbore. Incompletepacking and completion failures on other comple-tions raised concerns about frac-packing effec-tiveness in high-angle wells.

Repsol YPF chose an innovative combinationof Alternate Path screens and a multizone (MZ)isolation packer to avoid fluid contamination,facilitate effective fracturing and ensure com-plete packing of the long openhole section (left).Two shunt tubes designed for pumping15 bbl/min [2.4 m3/min] extended through thepacker, across the reactive shale section and the entire pay interval. The design incorporatedan inner washpipe that conveyed drilling fluid toa drilling motor. This motor could rotate a bit on the bottom of the assembly if required todeploy the completion equipment. An outershroud with holes protected screens from damage in the openhole.

Elastomer cups on the MZ packer preventedannular flow and diverted fluid to the shunttubes. Exit nozzles on the shunt tubes did notbegin until just above the screens to avoid anyinjection across the shale. Slurry bypassed theshale section, exiting through nozzles along thescreens to fill gaps in the pack below proppantbridges that might form. This configuration preserved fracture and proppant conductivity by eliminating fluid contamination from the reac-tive shale.

Frac-pack execution went smoothly despiteconcerns about the high-angle wellbore, multiplecompeting fractures and excessive fluid leakoffthrough 225 ft [69 m] of openhole interval with47 ft [14 m] of high-permeability net sand.

44 Oilfield Review

Drilling bit

Drilling motor

AllFRAC screenswith nozzles

AllFRAC blank pipewithout nozzles

Reactive shale

MZ isolationpacker with

bypass shunts

Shunttubes

QUANTUMgravel-pack

packer

QUANTUMservice tool

Washpipe

>Widuri Well B-28 completion. Run as part of the completion assembly, amultizone (MZ) isolation packer was located below the QUANTUM gravel-pack packer inside the 7-in. casing. Two large shunt tubes extending throughthe packer bypassed the reactive shale section. A protective shroud coveredthe AllFRAC screens and shunt tubes to prevent mechanical damage fromhole instability or assembly rotation to reach total depth. The shroud alsocentralized the screens for a more complete annular pack. To reach bottom,this assembly could ream and clean out the hole if necessary using a posi-tive-displacement motor and bit at the end of the screen assembly. An innerwashpipe conveyed fluid to the motor.

Summer 2002 45

Treatment simulation indicated a final fracturehalf-length of 18 ft [5.5 m] with a propped widthof 1 in.

Initial production of 2000 B/D [318 m3/d] totalfluid with 500 B/D [79 m3/d] of oil from an elec-trical submersible pump exceeded operatorexpectations. Post-treatment skin was not mea-sured by pressure-buildup analysis, but a sensoron the electrical submersible pump monitoreddownhole flowing pressures, which indicated asmall pressure drop at the completion face.

Well performance was evaluated by calculat-ing a productivity index (PI) based on net reser-voir thickness from flowing bottomholepressures, reservoir pressure and productionrates (below). Well B-28 outperformed mostwells in the field and compared favorably withwells completed by openhole horizontal gravelpacking. Considering the excessive fluid lossesduring drilling, this level of productivity demon-strates the feasibility of openhole frac packing asa sand-control alternative in extremely perme-able reservoirs with high mobility ratios.

Emerging TechnologiesNew developments continue in all aspects of fracpacking, from improved sand prediction andtreatment modeling, to new fluids that reducedamage in both propped fractures and annular

packs. New placement techniques improve fracpacking by applying new downhole equipment oreliminating subsurface hardware entirely. Fluidadditives that are in testing promise to minimizeproduction declines by reducing fines migrationand preventing scale deposition.

Frac-pack placement data generally indicatecreation of a fracture and subsequent tip screen-out, but post-treatment pressure data often indicate positive skin values and some remainingdamage, raising questions about the effective-ness of propped fractures. More realistic modelshave been developed to resolve discrepanciesbetween geophysical evaluations, well-log interpretation, fracturing data from frac-packingtreatments and well-test pressure analysis(right).38 Generating consistent solutions andresolving discrepancies require measurement ofmultiple parameters within a discipline, and inte-gration across disciplines.

Differential stresses make uniform hydraulicfracture diversion and complete coverage diffi-cult in long intervals of heterogeneous forma-tions, even when Alternate Path technology isused. This is particularly true if stress profilesvary significantly when high-permeability zoneswith lower stresses occur at the top of a longinterval. Preferential propagation of fractures inzones with lower in-situ stresses results in sub-optimal reservoir stimulation. Ocean Energy used an innovative technique in

the Gulf of Mexico to ensure uniform stimulationand annular packing across long intervals in afield in the Eugene Island area.39 The operatorpumped more than one pad-slurry sequence dur-ing a treatment without shutting down tosequentially increase the resistance to fractureextension, or fracture stiffness, in each zone fromlowest to highest in-situ stress. As proppantpacked toward a well, fractures became moredifficult to propagate, and the next pad-slurrysequence diverted into other zones of long heterogeneous intervals.

In this application, AllFRAC screens improvedfrac-pack treatment diversion across long intervals. Multiple temperature gauges withelectronic memory placed strategically in thewashpipe monitored slurry diversion through

38. Ayoub JA, Barree RD and Chu WC: “Evaluation of Fracand Pack Completions and Future Outlook,” paper SPE38184, presented at the SPE European FormationDamage Conference, The Hague, The Netherlands, June 2–3, 1997; also in SPE Production & Facilities 15,no. 3 (August 2000): 137–143.

39. White WS, Morales RH and Riordan HG: “ImprovedFrac-Packing Method for Long HeterogeneousIntervals,” paper SPE 58765, presented at the SPEInternational Symposium on Formation Damage Control,Lafayette, Louisiana, USA, February 23–24, 2000.

Cased-hole frac-pack average = 0.17

Spec

ific

prod

uctiv

ity in

dex

(PI),

B/D

/psi

/ft

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.40

0.45

1 2 3 4 5 B-28 6Well

7 8 9 10 11 12

> Openhole frac-pack performance. Inflow-performance calculations yieldedaverage and maximum specific productivity index (PI) values of 0.17 and 0.39B/D/psi/ft [0.013 to 0.03 m3/d/kPa/m] for 12 Widuri field cased-hole frac packs,respectively. Only two cased-hole wells in this field performed equal to orbetter than the Well B-28 openhole frac pack, which had a specific PI of 0.28B/D/psi/ft [0.021 m3/d/kPa/m].

Welltest (T)

T1

T2

T3

F1

F2

L1 G1

L1

G1

F1

G1

L1 G1

F2

G2

Fractureplacement (F)

Interpretationand Simulation

Models

Model Results andMatching Solutions

Well logs (L)

Geology andGeophysics (G)

> Post-treatment evaluations. Solutions from geo-logical and geophysical modeling, well-log inter-pretation, fracture-placement evaluation and well-test analysis are not unique. Various combinationsof input data—length of pay interval, reservoirpressure, porosity, permeability, and fracturelength, width or height—often generate multiplesolutions and different results from each model.Better simulation and interpretation software helpestablish a match among all of the different models,such as T2, F1, L1 and G1 in this depiction.

shunt tubes to other zones (above). Temperaturedecreases indicated fluid flow past a gauge, andtemperature increases corresponded to reducedflow or no fluid movement at a gauge.Temperature responses at the gauges confirmedcomplete interval coverage and diversion oftreatment fluids into individual target zones. Netpressure developed during the treatment indi-cated a tip screenout.

Individually frac packing multiple zones in asingle wellbore is time-consuming and expensive.An alternative to stacked frac-pack completionsuses Alternate Path screens and MZ isolationpackers with bypass shunt tubes to completemore than one zone in a single pumping operationwith the same gravel-pack packer (next page,left). This diversion technique uses pressure dropin the shunt tubes to control fluid flow. Changingthe number and length of shunt tubes going toeach zone controls pressure drop. Engineers varyshunt-tube configurations to achieve the desiredrate distribution. This system potentially allowsup to three zones to be completed at reduced costand improved profitability.

Operators often bypass many marginal, orsecondary, pay intervals. These zones may neverbe exploited because of the mechanical risk ofextending the frac-pack interval length up ordown and the cost of mobilizing a rig to recom-plete the well, especially offshore where the vastmajority of frac packs are performed. Recently,new technologies have been introduced that

promise to speed routine application of “rigless” completions.

Coiled tubing-conveyed fracturing technology,including CoilFRAC stimulation through coiledtubing service, is rapidly becoming a viable toolfor exploiting bypassed pay.40 This new technol-ogy has been applied successfully onshore inmultilayered, low-permeability reservoirs, butthe next step is to take this technology offshore.Accessing offshore wellbores in a workover envi-ronment and placing a frac pack or screenlesscompletion in a new zone without using a costlyconventional drilling or workover rig opens upcountless future opportunities. Significant fric-tion reduction with VES fluids may increaseapplication of coiled tubing-conveyed fracturingby allowing this type of rigless completion to be performed at greater depths.

Operators recently began evaluating andinstalling sand-exclusion screens that expandagainst the borehole wall. An annular gravelpack is not required to achieve wellbore stability.Expandable compliant screens also could beinstalled after frac-packing treatments to elimi-nate internal annular packs.

Emerging screenless techniques potentiallyproduce completions with a negative skin andreduce completion costs while maintaining effec-tive sand control.41 In this case, TSO fracturingand the proppant ring around a wellbore act as a

sand filter. However, any area not covered leavesperforations open to produce sand. This tech-nique requires various combinations of orientedperforating, injection of organic resins to holdformation grains in place and resin-coated prop-pants or fiber technology to prevent proppantflowback (next page, right). Porous ScalePROP scale-inhibitor-impregnated proppants can improveinhibitor placement and ensure uniform chemicalrelease for extended protection against scalebuildup in completion equipment and tubulars.

46 Oilfield Review

105

110

115

120

125

130

Pres

sure

, psi

Tem

pera

ture

, deg

rees

F

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75Time, min

Bottomhole pressureupper and lower gauges

Bottomhole temperaturelower gauge

Bottomhole temperatureupper gauge

3000

5950

5900

Temperature and pressure gauges

1 100Gamma Ray, APIDepth, ft Resistivity, ohm-m

2 3

6000

6050

6100

6150

6200

3500

4000

4500

5000

Perforations

> Frac-pack diversion. By injecting two separate pad-slurry sequences, Ocean Energy treated four zones over 240 ft [73 m] in the firstof two wells (left). Two memory gauges in the washpipe recorded downhole temperatures and pressures (right). Temperaturedecreased initially at the upper gauge because of fluid flow past the top zone (green). Pump problems halted injection between pad-slurry sequences. After injection resumed, temperature at the upper gauge stabilized, then increased, because a proppant bridge pre-vented annular flow. Temperature at the lower gauge decreased as flow diverted into the AllFRAC screen shunt tubes and reached thelower zones (blue). Temperature at the upper gauge decreased again as the bridge broke down and annular flow resumed.

40. Degenhardt KF, Stevenson J, Gale B, Gonzalez D, Hall S,Marsh J and Zemlak W: “Isolate and Stimulate IndividualPay Zones,” Oilfield Review 13, no. 3 (Autumn 2001): 60–77.

41. Kirby RL, Clement CC, Asbill SW and Ely JW:“Screenless Frac Pack Completions Utilizing ResinCoated Sand in the Gulf of Mexico,” paper SPE 30467,presented at the SPE Annual Technical Conference andExhibition, Dallas, Texas, USA, October 22–25, 1995. Pitoni E, Devia F, James SG and Heitmann N: “ScreenlessCompletions: Cost-Effective Sand Control in the AdriaticSea,” paper SPE 58787, presented at the SPEInternational Symposium on Formation Damage Control,Lafayette, Louisiana, USA, February 23–23, 2000; also inSPE Drilling & Completions 15, no. 4 (December 2000):293–297. Guinot et al, reference 16. Solares JR, Bartko KM and Habbtar AH: “Pushing theEnvelope: Successful Hydraulic Fracturing for SandControl Strategy in High Gas Rate Screenless Completionsin the Jauf Reservoir, Saudi Arabia,” paper SPE 73724,presented at the SPE International Symposium andExhibition on Formation Damage Control, Lafayette,Louisiana, USA, February 20–21, 2002.

42. Guichard JA III and Stewart B: “Field Experience FracPacking Near Gas/Water Contacts,” paper SPE 73776,presented at the SPE International Symposium andExhibition on Formation Damage Control, Lafayette,Louisiana, USA, February 20–21, 2002.

43. Ali et al, reference 36.

Summer 2002 47

Future TrendsEngineers recognize that conventional fracturingsimulators based on linear elastic fracturemechanics do not adequately model frac packing.Current research is evaluating new modelingconcepts that account for differences in elasticand plastic behavior between hard and soft for-mations. Effects of fluid injection during pretreat-ment minifracture tests on potential fluid lossduring the main treatment also are being studied.Future frac-packing simulators will account forfluid-injection behavior to further improve frac-pack designs.

A better understanding and modeling of fluidrheology, with control of fracturing net pressure,may help companies fracture small zones withoutbreaking into nearby barriers or into water andgas zones, especially when combined with frac-pack designs that control net-pressure increase.42

Recent advances in fluids promise additionalimprovement in frac-pack productivity. Theseinclude low-polymer crosslinked HPG, delayed-crosslinker and polymer-breaker improvements,and extension of temperature limits for solids-free VES systems beyond 300ºF. Alternatives tocurrent polymer systems are also being evalu-ated. Finding or creating new polymers may bethe key to developing a completely new fractur-ing fluid.

MudSOLV filter-cake removal services cur-rently used for simultaneous gravel packing andcleanup in openhole gravel packs may find simi-lar application in openhole frac packing.43

Incorporating aggressive breakers and filter-cake

removal chemicals into fracturing fluids withoutaffecting base properties would be advanta-geous during frac-pack treatments to ensurechemical contact with the entire openhole sec-tion and provide a uniform production profile.

The increasing use of synthetic oil-base mud,especially in high-permeability reservoirs, willrequire compatible fracturing fluids. This needwill become increasingly important as operatorsperform more openhole frac packs. Fluid compat-ibility, formation wettability and filter-cakecleanup have to be addressed in the context ofexpensive displacement to water-base systemsand oil-base fluid handling.

Some of these techniques require furtherdevelopment, but as frac-packing treatments areimplemented in a wider range of reservoirs andsubsurface conditions, new ideas and techniqueswill be developed to fully realize the benefits ofcombined stimulation and sand-control techniques.

—MET

Upper MZisolation packer

Shunt tubewith nozzlesfor upperzone

Lower MZisolation packer

Shunt tubeswith nozzlesfor lowerzone

Shunt tubeswithoutnozzles forlower zone

Perforations

Perforations

> Frac packing and gravel packing multiple zonesin a single trip. Multizone (MZ) isolation packerswith shunt tubes allow more than one interval tobe treated with the same gravel-pack packerduring one pumping operation in a single trip intothe wellbore. Treatment fluids pass throughshunt tubes in MZ packers located at the top andbottom of a completion interval to isolate individ-ual zones. Shunt-tube size and configuration bal-ance flow between the zones to create two orthree fractures simultaneously. This capabilityreduces the incremental cost to access addi-tional reservoirs.

Screenless completion

Resin-coated proppant orsand held in place by

PropNET fibers

10,000

Scal

e-in

hibi

tor c

once

ntra

tion,

par

ts p

er m

illio

n (p

p m)

0

10

100

1000

Water production

End of scale squeeze life

Scale-inhibitor squeeze

Required protection

ScalePROP impregnated proppant

Scale-inhibitortreatment

Formation or propped fracturecontaining scale-inhibitorliquid preflush or ScalePROP proppant impregnated with a solid-phasescale inhibitor

> Screenless completions. Combined with frac packing, resin consolidation, resin-coated proppants orPropNET hydraulic fracturing proppant-pack additives (top right) potentially control proppant and sandproduction without sand-exclusion screens and internal gravel packs (top left). Cost savings includeelimination of the screens, associated rig time for screen installation and placing an annular pack. Inaddition, porous ScalePROP scale-inhibitor-impregnated proppants contain a solid phase of scaleinhibitor (bottom left). This method distributes the chemical throughout a proppant pack to avoid lossof inhibitor and scale protection during initial well flowback and cleanup of treatment fluids; slow dis-solution ensures uniform inhibitor release during production (bottom right).