38 Oilfield Review

Screenless Methods to Control Sand

Andrew Acock Aberdeen, Scotland

Norbert Heitmann Caracas, Venezuela

Steve Hoover Houston, Texas, USA

Badar Zia Malik Stavanger, Norway

Enzo Pitoni Eni S.p.A. E&P DivisionMilan, Italy

Claud Riddles J.M. Huber Corp.Houston, Texas

J. Ricardo Solares Saudi Aramco Udhailiyah, Saudi Arabia

ClearFRAC, CoilFRAC, CoilFRAC ST, DataFRAC, DSI (Dipole Shear Sonic Imager), FMI (Fullbore FormationMicroImager), HSD (High Shot Density), NODAL,OrganoSEAL, OrientXact, PowerSTIM, PropNET, SandCADE, SANDLOCK, SPAN (Schlumberger Perforating Analysis) and SqueezeCRETE are marks of Schlumberger.

Combining proven oilfield technologies allows operators to achieve solids-

free production in many of today’s challenging oil and gas developments.

This approach provides viable, cost-effective alternatives to conventional

sand-control methods for completion or rehabilitation of wells that produce

sand, especially when applied rigless—without conventional rigs.

Produced sand causes various problems fromremoval, handling and disposal of fill inside cas-ing or surface equipment to serious well-comple-tion failures. These problems often compound,jeopardizing future remedial well interventionsand long-term wellbore viability. Leaks, produc-tion delays, low hydrocarbon recovery factors orloss of well control may occur if sand erodes well-bore equipment or surface wellheads, pipes andfacilities. In a catastrophic failure, access toreserves can be lost if costs to sidetrack or drill anew well are prohibitive.

In some reservoirs, weakly consolidated, butrelatively competent zones can be completedwithout installing mechanical screens to keepsand—formation grains and migrating fines, orsmall rock particles—from entering a wellbore.In the past, operators have used gravel packingor frac packing in formations of this type. Thesetwo methods rely on the particle-bridging char-acteristics and filter mechanisms of sand-exclu-sion screens in open hole or inside casing withannular gravel packs and also propped hydraulicfractures in the case of frac packs.

Screenless completions use techniques otherthan conventional “internal” packs to prevent

perforation failure and subsequent production offormation solids (next page). Screenless meth-ods maintain well productivity and sand-freeinflow by combining one or more of the followingsix field-proven technologies: • optimal perforation phasing, orientation and size • wide tip-screenout (TSO) fractures across all

perforations• proppant-flowback control • chemical formation consolidation, or stabilization • cementing unwanted permeable gravel-pack

intervals• selective coiled tubing treatments.

When planned and implemented carefully,these techniques control sand, reduce overallcost and risk, enhance productivity and improvehydrocarbon recovery.

This article reviews screenless methods andassociated rigless techniques that came intomore widespread use during the mid-to-late1990s. We present results from applications inSaudi Arabia, the Gulf of Mexico and Italy toillustrate the effectiveness of oilfield technolo-gies, new and old, in innovative combinationsthat prevent sand production.

For help in preparation of this article, thanks to JosephAyoub, Ernie Brown, Leo Burdylo, Jorge Manrique, Lee Ramsey and Saliya Wickramasuriya, Sugar Land,Texas, USA; Simon James, Clamart, France; and Hugo Morales, Houston, Texas.

Spring 2003 39

OilResinFormation

sand grain

Formation consolidation

Proppant-flowback control

Proppant grains held inplace by PropNET fibers

Propped fracture Cement Casing Perforations

“External” pack

> Screenless completions. Rigless methods prevent sand influx without screens or annularpacks by combining optimized perforating, chemical formation consolidation, or stabilization,and tip-screenout (TSO) fracturing with proppant-flowback control fibers to create an "external"pack (top left). Resin-coated proppants (RCP), PropNET hydraulic fracturing proppant-packadditives, or both, help stop proppant and formation sand production (top right). Formation consolidation involves injection of a resin system into the formation to form a stronger bondbetween individual grains (bottom left).

Rigless Interventions Screenless completions avoid the limitations andproductivity restrictions of internal gravel packsand screens. Screenless completions do notrestrict wellbores across pay intervals. This full-bore access provides additional flexibility forsubsequent well logging and data gathering,remedial repairs and recompletions, reservoirmonitoring and production management, andcontrol of water or gas inflow.

In addition to simplifying completion opera-tions and reducing installation risks, thisapproach decreases cost by eliminating screenassemblies and associated equipment, complexdownhole tools, and the fluid volumes andpumping operations that are required to placegravel around screens (above).

Screenless completions can provide primarysand control in newly drilled wells or lateral side-tracks, especially for casing sizes and wellboreconfigurations that preclude the installation ofmechanical sand-exclusion screens. In addition,they are used to complete bypassed zones inexisting wellbores. Wells without screens andgravel packs that begin to produce sand can berecompleted using screenless techniques.

Screenless techniques do not require drillingor workover rigs. These methods can be per-formed using coiled tubing, which furtherreduces completion and remedial interventioncosts. This makes screenless methods particu-larly attractive and cost-effective for initial com-pletion of bypassed zones. These methods arealso applicable for repairing wells with pluggedgravel packs or eroded screens.

Evolving Techniques In the early 1990s, companies began evaluatingmethods to prevent sand influx by mitigating for-mation failure and perforation breakdown inunstable formations. Since that time, operatorsand service companies have worked together todevelop and optimize rigless sand-control tech-niques. These efforts led to optimized perforatingpractices for sand management—control andprevention—as well as increased hydraulic frac-turing and frac packing for sand control.1

Amoco used “up-and-under” fracturing in theNorth Sea Valhall field during the 1980s.2 Statoilapplied a similar technique called indirect verti-cal fracturing (IVF) to control sand in the NorthSea Gullfaks field without installing screens andgravel packing.3 These methods involve perforat-ing competent shale or other high-strength

intervals adjacent to weaker target pay zones,followed by fracturing treatments designed togrow vertically into the producing formation(next page). Initiating hydraulic fractures froma strong, stable zone delays or prevents theonset of sand production resulting from pressuredepletion.4 The IVF technique requires detailedformation lithology and in-situ stress data, but iseffective when applied judiciously.

Dalen Resources Oil & Gas Company and Ely& Associates perforated limited 30-ft [9-m] inter-vals at 0° phasing and used TSO fracturing toprevent sand production.5 The objective was tocreate a wide, stable hydraulic fracture packedwith resin-coated proppant (RCP) to reducesandface drawdown pressure and stop proppantflowback as well as produced sand. PT. CaltexPacific Indonesia, now a division of ChevronTex-aco, used a similar technique and a 180° perfora-tion phase angle in Duri field, a heavy-oil steam-flood project in Indonesia.6 During themid-1990s, Amoco Norway, now called BP Norge,successfully used the same general approach toprevent chalk production from more than 70 hori-zontal wells in weak North Sea chalk formations.7

Perforating short intervals—5 ft [1.5 m] or

40 Oilfield Review

0

100

200

300

400

500

600

Thou

sand

dol

lars

Rigless completionwithout screens

Frac pack withscreens

Fracturing Tools Pumping Coiled tubing Perforating Rig

> Screenless completion versus frac packing with internal screens. Rigless sand-control methodsrequire additional pumping and coiled tubing services, but elimination of mechanical screen assem-blies, more complex downhole equipment and conventional rig operations reduces costs significantly.

Spring 2003 41

less—at the beginning, or heel, and the bottom,or toe, of horizontal sections induced hydraulicfractures across all perforations. Rigorous testingconfirmed that, within certain limitations, RCPcould control proppant flowback.

Fracture conductivity—width—affects thepressure drawdown that can be applied beforeformation sand is produced from perforationsnot covered by the fracture and proppant pack.Arco E&P Technology, Arco Indonesia, Inc. andVastar Resources, an Arco subsidiary at thattime, developed and applied a technique to pre-dict fracture geometries and properties that pre-vent sand production.8 Corpoven, formerly a unitof Petróleos de Venezuela S.A. (PDVSA), alsoapplied this concept to control sand productionfrom deep wells in high-stress formations.9 Inaddition, forcing dynamic fractures to closeimmediately after stimulation operations mini-mized early onset of sand production.

Subsequently, operators placed greateremphasis on controlling production rates anddrawdown pressures during cleanup and recoveryof treatment fluids, well testing and initial pro-duction to ensure successful fracturing treat-ments. Because perforation failures initiate at acritical pressure, keeping differential pressuresbelow that critical level during production helpsmaintain long-term stability. Operators can estab-lish production rates that optimize drawdownpressures during treatment cleanup and hydro-carbon production to prevent formation and per-foration failure that might initiate sand produc-tion immediately after completion operations.

These techniques contribute to successfulscreenless completions. However, optimizingcleanup procedures after hydraulic fracturingrequires careful consideration of several factors.Flow regime—two- or three-phase flow—viscos-ity of returning stimulation and reservoir fluids,maximum allowable flow velocity in perforationtunnels and proppant type play important rolesin maintaining screenless completion integrityafter treatment execution.

Results vary from application to application,but screenless methods generally provide effec-tive sand control. Operators attribute this suc-cess to teamwork, efficient completion practicesand lessons learned from worldwide experience,in addition to effective fracturing treatmentdesigns and execution, and willingness to trynew technology and combinations of techniques.Screenless techniques create a variety of well-completion opportunities that vastly outweighany limitations from the physical absence ofmechanical screens.

1. 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. Behrmann L, Brooks JE, Farrant S, Fayard A,Venkitaraman A, Brown A, Michel C, Noordermeer A,Smith P and Underdown D: “Perforating Practices ThatOptimize Productivity,” Oilfield Review 12, no. 1 (Spring2000): 52–74.

2. Moschovidis ZA: “Interpretation of Pressure Decline forMinifrac Treatments Initiated at the Interface of TwoFormations,” paper SPE 16188, presented at the SPEProduction Operations Symposium, Oklahoma City,Oklahoma, USA, March 8–10, 1987.

3. Bale A, Owren K and Smith MB: “Propped Fracturing asa Tool for Sand Control and Reservoir Management,”paper SPE 24992, presented at the SPE EuropeanPetroleum Conference, Cannes, France, November16–18, 1992.

4. Morita N, Burton RC and Davis E: “Fracturing, Frac-Packing and Formation Failure Control: Can ScreenlessCompletions Prevent Sand Production?” paper SPE36457, presented at the SPE Annual TechnicalConference and Exhibition, Denver, Colorado, USA,October 6–9, 1996; also in SPE Drilling & Completions 13,no. 3 (September 1998): 157–162.

5. Kirby RL, Clement CC, Asbill SW and Ely JW: “ScreenlessFrac Pack Completions Utilizing Resin Coated Sand in theGulf of Mexico,” paper SPE 30467, presented at the SPEAnnual Technical Conference and Exhibition, Dallas,Texas, USA, October 22–25, 1995.

6. Putra PH, Nasution RDj, Thurston FK, Moran JH andMalone BP: “TSO Frac-Packing: Pilot Evaluation to Full-Scale Operations in a Shallow Unconsolidated

Weak layer

Competent layer

Competent layer

Propped fracture

Casing

Cement

Perforations

> Early screenless completion in the North Sea. The "up-and-under," or indirectvertical fracturing (IVF), technique was used by Amoco in the Valhall field tocontrol chalk production, and by Statoil in the Gullfaks field to control sand inreservoirs with relatively thick, interbedded sandstones and shale layers.Hydraulic fracture treatments designed to propagate into a nearby hydrocarbon-bearing formation are initiated by perforating a shale or stronger zone. Fractureheight and length grow rapidly through the weaker producing interval, with the initial fracture section in the more competent layer acting to exclude formationsand from the wellbore.

Heavy Oil Reservoir,” paper SPE 37533, presented at the SPE International Thermal Operations & Heavy OilSymposium, Bakersfield, California, USA, February 10–12, 1997. Malone BP, Moran JH, Nasution RDj, Putra PH andThurston FK: “Start-Up of a TSO Fracturing Campaign ina Shallow, Heavy Oil Steamflood,” paper SPE 38096, pre-sented at the SPE Asia Pacific Oil and Gas Conference,Kuala Lumpur, Malaysia, April 14–16, 1997.

7. Norris MR, Berntsen BA, Myhre P and Winters WJ:“Multiple Proppant Fracturing of a Horizontal Wellbore:An Integration of Two Technologies,” paper SPE 36899,presented at the SPE European Petroleum Conference,Milan, Italy, October 22–24, 1996. Norris MR, Berntsen BA, Skartveit L and Teesdale C:“Multiple Proppant Fracturing of Horizontal Wellbores ina Chalk Formation: Evolving the Process in the ValhallField,” paper SPE 50608, presented at the SPE EuropeanPetroleum Conference, The Hague, The Netherlands,October 20–22, 1998.

8. Fletcher PA, Montgomery CT, Ramos GG, Miller ME, Rich DA, Guillory RJ and Francis MJ: “Using Fracturingas a Technique for Controlling Formation Failure,” paperSPE 27899, presented at the SPE Western RegionalMeeting, Long Beach, California, USA, March 23–25,1994.

9. Ortega L, Brito L and Ben-Naceur K: “HydraulicFracturing for Control of Sand Production andAsphaltene Deposition in Deep Hot Wells,” paper SPE36461, presented at the SPE Annual TechnicalConference and Exhibition, Denver, Colorado, USA,October 6–9, 1996.

Perforating and Fracturing For new wells and bypassed zones in existingwells, screenless completions begin with opti-mized perforating practices. This first stepaddresses perforation phase angle and orienta-tion, perforated interval length, and the size andnumber of holes, or shot density.10 For successfulsand control and fracturing treatments, perforatingstrategies should be designed so that perfora-tions lie in or near the preferred fracture plane(PFP), or maximum in-situ stress direction.

After perforating, TSO fracture treatmentsare performed to inflate dynamic fractures andcreate wider propped widths that generate a proppant ring, or “external pack” (right).11

These specialized fracture treatments bypassnear-wellbore damage and stimulate well pro-ductivity by connecting individual formationlaminations or layers and establishing a conduc-tive, stable and long-lasting flow path fromreservoir to wellbore.

Screenless methods achieve success onlywhen well-developed TSO fractures with stableproppant packs cover all perforations and pre-vent sand from entering the wellbore. Untreatedperforations that are not optimally aligned anddirectly connect formation and wellbore leavepotential pathways for sand production.

If stress directions are unknown, a 0° phaseangle maximizes the number of perforations thatcommunicate with a hydraulic fracture (nextpage, top). If stress directions are known, perfo-rating guns with 0° or 180° phasing oriented inthe PFP mitigate tunnel failure and sand influx,both with and without consolidation treatments(next page, bottom). Optimal phasing or orientedperforations also reduce near-wellbore flow-pathrestrictions, or tortuosity. Tortuosity increasesfracture-initiation pressure and pressure dropsacross completion intervals that occur duringinjection of fracturing fluids and proppants.

Orienting perforations in the proper direc-tion requires knowledge about formation in-situstresses and directions along with the technicalcapability to economically orient perforatingguns. Special tools such as the oriented four-armcalipers, DSI Dipole Shear Sonic Imager andFMI Fullbore Formation MicroImager tools, sup-plemented with local knowledge and regionalstress maps, help engineers determine stressmagnitudes and directions.

In the past, only motorized downhole wire-line tools or tubing-conveyed perforating (TCP)systems rotated from surface could actively ori-ent guns. Recently, however, Schlumbergerdeployed the Wireline Oriented Perforating Tool(WOPT) to orient guns in near-vertical and high-

angle wells—inclination angles from about 0.3°up to about 60°—and the OrientXact tubing-conveyed oriented perforating system for near-horizontal wells.12

Because of the emerging status of screenlesstechniques, perforations in vertical wells shouldbe restricted to a maximum interval of 20 to40 ft [6 to 12 m] at least until experience dic-tates that this interval can be extended confi-dently. For high-angle wells with inclinationsgreater than 10°, where multiple fractures maydevelop, perforated intervals should be less than6 ft [1.8 m]. Limiting perforated-interval lengthsimproves fluid placement, and increases theprobability that TSO fractures will cover the per-forations and form an effective external packcompletely around the wellbore.13 Shorter inter-vals also improve proppant packing by providinghigh net pressure near the wellbore.

Completion engineers select perforatingcharge type and shot density based on requiredpressure drops while pumping the fracture treat-ment and producing the well. Perforation diame-ter must be sufficiently large to avoid proppantbridging and premature screenouts, but smallenough so that after the dynamic fracturecloses, the propped width at the wellbore com-pletely covers the entrance holes in casing walls,thus blocking sand influx. Limiting the numberof shots minimizes untreated perforations.

Hydraulic fracturing reduces the pressuredrop across completion intervals, which mini-mizes perforation failures and sand production.The external pack and large surface area ofproppant packs created during TSO fracturingalso prevent sand from entering a well. Mostscreenless stimulations include additional mea-sures to stabilize the proppant pack.

42 Oilfield Review

Dynamic fracture

Fracture inflation

Annular opening

Cement

Perforation

Casing

Propped fracture

“External” proppant pack

Tip screenout

Proppant

> Fracturing for screenless completions. Specialized stimulation designs generate tip-screenout (TSO)fractures using proppant-carrying fluids that leak off early in a treatment. Dehydration of this slurrycauses proppants to pack off at biwing fracture tips, halting length propagation, or extension (top).Pumping additional slurry causes dynamic fractures to inflate as proppants pack back toward the well(middle). This promotes grain-to-grain contact after fracture closure and creates wide, high-conductiv-ity fractures that connect discrete formation layers and establish linear flow to the well. A TSO treat-ment causes enough formation displacement over short intervals to create an annular opening aroundthe wellbore. This "external pack" becomes packed with proppants and covers perforations that are notaligned with the PFP. This prevents sand production from nonaligned perforations, and further reducesnear-wellbore pressure drop (bottom).

Spring 2003 43

Controlling Proppant Flowback Propped fractures extend past near-wellboredrilling and completion damage that reduces per-meability to create a conductive, linear flow pathto the well. Like produced sand, proppant flow-back is detrimental to well productivity and pro-ducing operations, and also fracture stability.Screenless completions lack internal annulargravel packs and mechanical screens inside thecasing to stop sand from entering the wellborewith produced fluids. It is imperative that prop-pants remain inside hydraulic fractures, especiallywhen formations must be chemically consolidated.

Proppants flowing at high rates erode com-pletion equipment, tubulars, control valves andwellheads. In low-rate wells, proppants movingback into a wellbore can settle inside the casingand cause production to cease if productiveintervals become completely covered. Proppantflowback also contributes to formation failureand perforation collapse, creates pathways forformation sand influx, and reduces production.Specialized materials, such as resin-coated prop-pant (RCP) and Schlumberger PropNEThydraulic fracturing proppant-pack additives, orboth applied together, help maintain fracturestability and integrity.

Several types of RCP are available, but only afew are suitable for screenless completions. Cur-able RCP interacts with treatment fluids andmay set up in the casing after a prematurescreenout, making removal difficult. PrecuredRCP does not provide sufficient flowback controland should not be used in screenless comple-tions in any case because the resin functions pri-marily to increase crush resistance. In general, apartially cured RCP is preferred because it mini-mizes fluid interactions and provides fracturestability while lowering the risk of proppantpacking off and setting up inside the wellbore.

10. Behrmann et al, reference 1. 11. In standard fracturing, the fracture tip is the final area

that is packed with proppant. A tip-screenout designcauses proppant to pack, or bridge, near the end of thefractures in early stages of a treatment. As additionalproppant-laden fluid is pumped, the fractures can nolonger propagate deeper into a formation and begin towiden or balloon. This technique creates a wider, moreconductive pathway as proppant is packed back towardthe wellbore. For more about frac packing: Ali et al, reference 1.

12. Almaguer J, Manrique J, Wickramasuriya S, Habbtar A,López-de-Cárdenas J, May D, McNally AC and SulbaránA: “Orienting Perforations in the Right Direction,” OilfieldReview 14, no. 1 (Spring 2002): 16–31.

13. Upchurch ER: “Near-Wellbore Halo Effect Resulting fromTip Screenout Fracturing: Its Direct Measurement andImplication for Sand Control,” paper SPE 56589, pre-sented at the SPE Annual Technical Conference andExhibition, Houston, Texas, USA, October 3–6, 1999; alsoin SPE Drilling & Completion 16, no. 1 (March 2001):43–47.

Preferred fractureplane (PFP)

PFP0° perforations Maximumhorizontalstress (SH)

SH

Cement

CasingTSO fracture wing

External pack

Sh

Minimum horizontalstress (Sh)

> Optimal perforation phase angle. From rock mechanics, we know that hydraulic fractures propagate inthe direction of maximum horizontal stress (SH), or along the preferred fracture plane (PFP). When in-situ stress directions are unknown, a 0° perforating-charge phasing increases the probability that allperforations will connect with the TSO fracture. Perforations at other angles—30, 60 and 90° phasing—may not intersect the fracture.

Sh

SH

Maximumhorizontalstress (SH) Preferred fracture

plane (PFP)

External pack

PFP

180°

Minimum horizontalstress (Sh)

BoreholeCement

Casing

Charges at 180° phasing

Perforations

TSO fracture wing

> Orienting perforations in the right direction. If in-situ stress directions are known, perforating gunswith charges at 0° or 180° can be aligned in the preferred fracture plane (PFP), perpendicular to theminimum horizontal stress direction (Sh), so that the TSO fracture will cover all perforations. Properorientation reduces or eliminates complex near-wellbore flow, or tortuosity, which increases fractureinitiation and treatment pressures.

PropNET fiber technology uses randomly ori-ented carbon fibers that create a physical,rather than chemical, barrier that reinforcesproppant packs and inhibits flowback (belowleft).14 The fibers are added continuously to frac-turing fluids at the wellsite and mix with prop-pants during pumping. Experience indicatesthat PropNET fibers allow immediate flowbackto improve treatment-fluid recovery after frac-turing. This capability is attributed to the build-ing of a mechanically reinforced network thatinterlocks proppant grains. Unlike RCP, thistechnology does not depend on temperature-sen-sitive curing processes or other chemical reac-tions. The fibers are inert and compatible withall fracturing fluids, including ClearFRAC poly-mer-free frac fluids based on viscoelastic surfac-tants (VES).

PropNET fibers and proppants are easier toremove than RCP alone, which can cure andbond together inside the wellbore under certainconditions. These specialized fibers do not havetemperature, closure-stress or shut-in time limi-tations before, during or after fracturing.Because PropNET fibers do not bond with prop-

pants, performance is not affected by reservoirdepletion, crushing of individual grains or clo-sure-stress cycling from producing and shuttingin wells.

When high production rates and maximumproppant-flowback control are required, fiberscombined with resin-coated proppant providereliable proppant-flowback control under awider range of conditions than either RCP orPropNET fibers alone. PropNET fibers reinforcethe RCP to provide additional resistance to ratechanges, production cycling and increasing clo-sure stress as reservoirs deplete, especially forextremely high-rate wells.15 PropNET fibers alsoimprove proppant suspension and transport inwellbore tubulars and dynamic fractures, andreduce frictional pressures during pumpingoperations as verifed by field measurements.

Saudi Arabia: Fracturing for Sand Control. In 1995, Saudi Aramco began developing nonas-sociated gas reserves in the Ghawar field of SaudiArabia, including construction of gas-handlingfacilities (below).16 The newly built Hawiyah gasplant, with processing capacity of 1.6 billion scf/D[46 million m3/d], required 400 MMscf/D[11.5 million m3/d] of “sweet” gas with no hydro-gen sulfide [H2S] to operate efficiently.Production from wells in the Jauf reservoir, aweak sandstone with bottomhole pressure andtemperature of 8750 psi [60 MPa] and 300ºF[149ºC], was critical in meeting this requirement.

This formation lies at a depth of 13,500 to14,400 ft [4115 to 4390 m]. Wells produce sweetgas at 10 to 60 MMscf/D [286,000 to 1.7 millionm3/d], but it is difficult to maintain solids-freeoutput at these high rates. Excessive sand influx

necessitates repeated wellbore cleanouts andcauses internal pipeline corrosion by strippingchemical inhibitors off pipe walls.

Conventional sand-control methods were notconsidered as part of the field-developmentplan. Gravel-packed screens would restrict pro-duction rates and the wells could not have metplant production targets, requiring SaudiAramco to drill additional wellbores. In addition,TSO fracture stimulations were not always suc-cessful because misaligned perforations causednear-wellbore tortuosity, or flow-path restric-tions, that increased fracture-initiation andinjection pressures. This limited net fracturingpressure and the capability to achieve optimalfracture width, height and length. Standard per-forating resulted in unpacked perforations thatwere pathways for produced sand.

Attempts to control sand with conventionalscreenless techniques were not successful so ateam of Saudi Aramco and Schlumbergerexperts reevaluated perforating, hydraulic frac-turing and proppant-flowback strategies.17 Usingthe PowerSTIM well optimization process, thesespecialists compiled a set of comprehensive for-mation-evaluation, reservoir-characterization,fracture-stimulation and well-test data toimprove stimulation and completion design,

44 Oilfield Review

> Proppant-flowback control. Carbon fibersmixed and pumped with proppants and fracturingfluids form a random, net-like structure in theproppant packs of hydraulic fractures. PropNETfiber widths are several times smaller than aver-age proppant diameters. Specially engineeredfiber lengths allow contact with more than 30proppant particles. These factors ensure packconductivity and stability, even if localized flowexceeds critical rates and causes a few proppantparticles to move or break away. Fibersstrengthen and reinforce the pack by interweav-ing among individual proppant grains. This pro-motes particle bridging and distributes stress forincreased pack stability, while still allowing highproduction rates.

ASIA

EUROPE

AFRICA

Riyadh Ghawar

Hawiyah

T h e

G u l f

Re

dS

e a

A r a b i a n

S e a

SAUDI ARABIA

IRANIRAQ

OMAN

UAE

QATAR

YEMEN

0 200 400

0 250 500 750 1000 km

600 miles

> Ghawar field, Saudi Arabia.

Spring 2003 45

execution and evaluation.18 This approachhelped the team analyze, optimize and imple-ment several innovative practices.

Based on the best available data and up-to-date field responses, the joint completions teamdeveloped and calibrated improved petrophysicaland formation mechanical-properties models.The new sand-prediction model differentiatedthe more competent, or stable, layers from thoseprone to sand production. This improvementhelped engineers make decisions about perforat-ing practices and perforation placement.

The Jauf team thoroughly investigated andimproved two key aspects of these well comple-tions. First, they developed fracturing tech-niques using the best combination of orientedperforations, treatment fluids, proppants andflowback-control additives. Second, they imple-mented screenless techniques, including perfo-ration specifications—interval length, hole sizeand placement—proppant type and size, andchemical and fluid systems to optimize gas out-put and minimize sand production.

Screenless methods have been the key tosuccessful gas-well completions in the Jaufreservoir. The objective of producing sand-freegas at economic rates and reasonable drawdownpressures was achieved by multiple means: • perforating only stable intervals • perforating one interval per well • limiting perforated interval length • using intermediate-strength RCP • using fiber flowback-control additives • orienting perforations in the PFP • forcing fracture closure immediately after

treatments• designing special flowback procedures.

The revised completion strategy avoided perfo-rating within 10 to 20 ft [3 to 6 m] of weak zonesas identified on stress profiles. Perforated inter-vals were limited to single lengths of 30 or 40 ft toensure fracture coverage of all perforations, cre-ate an external pack at the wellbore, and preventsand flux from untreated perforations.

The combination of intermediate-strengthRCP and high-temperature PropNET Gold fibersalso was used to stop proppant flowback andhelp control produced sand. Finally, carefullyevaluating and adjusting post-treatment produc-tion helped Saudi Aramco achieve and maintaininitial sand-free rates.

Perforations properly aligned with the PFPminimize unpacked tunnels that can contributeto sand production. Saudi Aramco chose theWireline Oriented Perforating Tool (WOPT) andguns with 180º phasing to perforate in the direc-tion of maximum formation stress and PFP orientation at an 80º or 260º azimuth (above).

Wirelineswivel

Gyroscopecarrier

HSD HighShot Densitygun, 180°phasing

Wireline PerforatingInclinometer Tool

(WPIT) and casing-collar locator (CCL)

Upper weightedspring-positioning

device (WSPD)

Upper indexingadapter

Lower indexingadapter

Lower weightedspring-positioning

device (WSPD)

Charges

Casing

Perforating Run

Relative bearing, 0°

PFP

PFP HSD gun

HSD gun

Casing

Charges

Initial Gyroscope Run

Relative bearing, 0°

270° 90°

180°

0°

150°

120°

60°

30°

210°

240°

300°

330° 30%

20%

10%

20%10%

Preferred fracture plane

Borehole breakout

30%

>Wireline-oriented perforating. The Schlumberger Wireline Oriented Perforating Tool (WOPT) can berun in near-vertical and high-angle wells with inclination angles from 0.3 to about 60° (left). Developedinitially for oriented fracturing, the WOPT is also used for sand prevention and screenless completions.This tool orients standard hollow-steel carrier guns with charges at optimal 0 or 180° phasing in a pre-determined direction. Saudi Aramco, a primary user of oriented perforating, deploys the WOPT systemto facilitate TSO fracturing. The Ghawar field PowerSTIM team used borehole breakout identified onFMI Fullbore Formation MicroImager logs to confirm an east-west maximum stress and PFP orienta-tion in the Jauf formation at an azimuth of about 80° or 260° (right).

14. Armstrong K, Card R, Navarrete R, Nelson E, Nimerick K,Samuelson M, Collins J, Dumont G, Priaro M, Wasylycia Nand Slusher G: “Advanced Fracturing Fluids Improve WellEconomics,” Oilfield Review 7. no. 3 (Autumn 1995):24–51.

15. Bartko KM, Robertson B and Wann D: “ImplementingFracturing Technology to the UKCS CarboniferousFormation,” paper SPE 38609, presented at the SPEAnnual Technical Conference and Exhibition, SanAntonio, Texas, USA, October 5–8, 1997.

16. Solares JR, Bartko KM and Habbtar AH: “Pushing theEnvelope: Successful Hydraulic Fracturing for SandControl Strategy in High Gas Rate ScreenlessCompletions in the Jauf Reservoir, Saudi Arabia,” paper SPE 73724, presented at the SPE International

Symposium and Exhibition on Formation DamageControl, Lafayette, Louisiana, USA, February 20-21, 2002.

17. Al-Qahtani MY, Rahim Z, Biterge M, Al-Adani N,Safdar M and Ramsey L: “Development and Applicationof Improved Reservoir Characterization for OptimizingScreenless Fracturing in the Gas Condensate JaufReservoir, Saudi Arabia,” paper SPE 77601, presented atthe SPE Annual Technical Conference and Exhibition,San Antonio, Texas, USA, September 29–October 2, 2002.

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

Oriented perforating reduces treating pressuresand creates wider fractures, which also reduceturbulent, or nondarcy, flow and drawdown pres-sure during production, further mitigating sandproduction (above).

Fracture stimulations prior to oriented perfo-rating failed to deliver sand-free gas at requiredrates, but Saudi Aramco observed positiveresults with the first application of oriented per-forating and screenless completions. Analyzingprefracture injectivity and minifracture treat-ments with DataFRAC fracture data determina-tion services confirmed significant reductions in

fracture-initiation pressure for wells with ori-ented perforations. Pressure losses duringpumping operations dropped from about2000 psi [13.8 MPa] for conventional perforatingto less than 600 psi [4.1 MPa] in wells with ori-ented perforations.

Improved hydraulic fracturing execution andincreased well productivity demonstrate theeffectiveness of oriented perforating. Fracturestimulation treatments prior to implementationof the revised well-completion strategies thatwere devised by the joint team resulted inextended flow periods to clean up wells aftertreatments. In one case, it took 55 days to

achieve solids-free production. Optimizedscreenless technologies and improved flowbackprocedures reduced this cleanup period to as lit-tle as five days in some cases.

Saudi Aramco routinely limits perforatedintervals, and is one of the largest users of ori-ented perforating services. The company com-pletes most wells in the current Jauf stimulationprogram with the WOPT system. To date, screen-less techniques have achieved sand-free gasrates even at high production rates and aftercycling production on and off for several months.

Formation Consolidation Existing completions and some new wells haveperforations that are not oriented in the pre-ferred fracture plane or at optimal 0° or 180°phasing. These “nonaligned” perforations canbecome a source of sand production, especiallyat higher rates and drawdown pressures.Formation consolidation, historically by injectionof organic resins, addresses this problem by bind-ing individual formation grains together (nextpage).19 In combination with TSO fracturing andPropNET fibers, this technique stabilizes a lim-ited collar-shaped volume around wellbores andperforations when resins are evenly divertedacross perforated intervals.20

Some resins create a high-strength consoli-dated region while only moderately reducing for-mation permeability. Using these systems main-tains some productivity after consolidation evenwithout fracturing. Other systems impair forma-tion permeability significantly or completely sealoff the near-wellbore region. Subsequent TSOtreatments extend propped fractures beyond thealtered zone to connect with the undamaged for-mation and control sand production.

Formation consolidation strengthens weaklyconsolidated formations and minimizes risk ofsand influx from nonaligned, potentiallyuntreated perforations. Flowback-control addi-tives in proppant packs prevent sand productionfrom perforations in communication with thehydraulic fracture. The formation around perfo-rations that do not communicate with the frac-ture is stabilized by the resin and is less likely toproduce sand.

In wells with existing conventional gravelpacks, consolidation stabilizes gravel in the per-forations and in annular packs between screensand casing. This step can enhance or extendwell productivity. During TSO fracturing, consoli-dation techniques also help prevent prematurescreenouts by limiting treatment-fluid lossesinto highly permeable existing gravel packs or

46 Oilfield Review

Pinch points

Perforations

CementBorehole

CasingCharges at 90° phasing

Preferred fractureplane (PFP)

Maximumhorizontalstress (SH)

PFP

Minimum horizontalstress (Sh)

SH

Sh

90°

Multiple initiation pointsand annular fractures

Misalignedperforations

Properly alignedperforations

Single-wingfracture

> Fracturing considerations. Hydraulic fracture initiation can occur at various discrete points on thewellbore radius if perforations are not aligned with the preferred fracture plane (PFP), or maximumhorizontal stress (SH). Developing fractures travel around casing and cement or turn to align with thePFP. This results in complex near-wellbore flow paths, or tortuosity, including competing fractures,pinch-point flow restrictions and fracture wings that curve or have poor alignment with the wellbore(top). Perforations oriented close to the PFP, or path of least resistance, minimize fracture-initiationand treating pressures. In full-scale laboratory tests on formation blocks under triaxial stress, perfora-tions in the PFP resulted in a dominant single-wing fracture with minimal tortuosity and lower injectionpressures (bottom left). In the same test, misaligned perforations resulted in multiple fracture initiationpoints (bottom right).

Spring 2003 47

the near-wellbore region. The success of thesetreatments depends strongly on optimized fluid-system chemistry, engineered and controlledfluid placement and wellbore physics.

Schlumberger offers epoxy-based SANDLOCKsand control systems using resin and furan-based K300 systems. Recommended depth ofpenetration for these systems is 2 to 3 feet [0.6to 0.9 m] into a formation. These systems rely onmultiple stages of injected fluids, which limiteffective placement in heterogeneous intervals.Current resin systems are limited to treatingintervals of about 20 ft.

SANDLOCK treatments begin with a preflushto clean the formation volume near a wellboreand leave sand-grain surfaces oil-wet and readyto bond with the resin. The resin system ismixed into a water-base carrier fluid, usually lin-ear hydroxyethylcellulose (HEC), and pumpedinto the rock matrix. The SANDLOCK system hasan internal catalyst, and a curing agent is mixedwith the resin, so the reaction begins immedi-ately after mixing. Catalyst concentration deter-mines available pumping time. This system hasbeen used successfully for proppant-flowbackremedial operations, but has limited applicationin screenless completions other than gravel-pack remediation because it does not penetrateformations with less than 1-darcy permeability.

The K300 system uses an external catalystthat is pumped after placing resin in the forma-tion to initiate curing. Consequently, treatmentprocedures are more complicated. Like theSANDLOCK system, a preflush is pumped first,followed by K300 resin; no carrier fluid is used.The next step involves pumping a viscous over-flush, usually linear HEC fluid, to sweep excessresin away from the near-wellbore region. In thefinal stage, an external catalyst is pumped.Unlimited resin-placement time is one advan-tage of this approach, but uncertainty abouteffective in-situ downhole mixing of catalyst andresin is a disadvantage.

Formations are fractured during screenlesscompletions, so there is no requirement to usesystems that retain formation permeability. Thisgreatly simplifies in-situ consolidation treat-ments. As a result, Schlumberger employs anovel technique that uses the water-baseOrganoSEAL organic crosslinked gel system,which was developed for water-control applica-tions. This single-stage treatment completelyfills matrix pore spaces and shuts off near-well-bore permeability. TSO hydraulic fracturingrestores well productivity.

The OrganoSEAL-R system can be pumpeddown wellbore tubulars and diverted with solidagents to treat interval lengths of up to 50 ft

[15 m], but coiled tubing is the preferred place-ment method. This consolidation system costssignificantly less, is more environmentallyfriendly and is easier to clean out of the wellborethan resin systems. OrganoSEAL-R fluids can beeasily squeezed into annular gravel packs, butflow less readily into the formation because ofdifferences in gravel and rock-matrix permeabil-ity. This makes fluid placement across an entirezone for gravel-pack remediation feasible.

Resinsolution

Resin solution displaces preflush

Formationsand grain

Oil and formation water before consolidation

Formationwater

Oil

Preflush miscibly displaces oil and formation water

Preflush

Oil

Well ready forproduction

ResinOverflush

Overflush and catalyst immisciblydisplaces resin and activates resin cure

Resin

19. Parlar M, Ali SA, Hoss R, Wagner DJ, King L, Zeiler Cand Thomas R: “New Chemistry and ImprovedPlacement Practices Enhance Resin Consolidation: CaseHistories from the Gulf of Mexico,” paper SPE 39435,presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 18–19, 1998. Ott WK and Woods JD: World Oil Modern SandfaceCompletion Practices Handbook. Houston, Texas, USA:Gulf Publishing Company (2003): 113-114.

20. Nelson EB, Brown JE and Card RJ: “Sand ControlWithout Requiring a Gravel Pack Screen,” U.S. PatentNo. 5,551,514 (September 3, 1996).

> Formation consolidation. Chemical consolidation before fracturing stabilizes completion intervalsthat do not have optimal or oriented perforations (top left). Typically, a resin system is injected into theformation using conventional pumping services or coiled tubing. These treatments consist of threebasic stages: pretreatment acid and surfactant preflush to displace formation water and hydrocar-bons (top middle), resin injection (top right), catalyst injection and viscous overflush with a shut-inperiod that allows the resin to cure (bottom left). This procedure is followed by TSO fracturing tobypass the consolidated region and reconnect with the unaltered rock (bottom right).

Gulf of Mexico: Slimhole Sidetrack In November 2000, J.M. Huber Corporationassumed operational responsibility for the SouthTimbalier Block 21 field in the Gulf of Mexicosouth of Louisiana, USA (above).21 At that time,the company identified an untapped reservoircompartment and drilled a directional sidetrackfrom nearby Well 48 to develop updip reserves.Well logs and sidewall cores confirmed 22 ft of oilfrom measured depth (MD) 11,772 to 11,794 ft[3588 to 3595 m].

The target upper Miocene sandstone was rel-atively clean with average porosity of 28%, per-meability ranging from 100 to 500 mD and a

5800-psi [40-MPa] bottomhole pressure sup-ported by a strong waterdrive. Typically, theseMiocene formations require sand-control mea-sures. Based on a history of sand production inthe field and a previously completed interval ofthe same zone in Well 48, completion engineersplanned to gravel pack 23⁄8-in. screens inside a 5-in. liner.

However, during drilling operations, the 5-in.liner became differentially stuck above theplanned total depth (TD). This forced the opera-tor to cement the string at 11,101 ft [3384 m]MD as intermediate casing and run a 31⁄2-in. liner

to TD at 12,160 ft [3706 m] MD (next page, left).A smaller conventional gravel pack was not prac-tical because it would restrict production. J.M.Huber and Schlumberger solved this dilemmawith screenless technology.

The revised well completion combined opti-mized perforating, formation consolidation andTSO fracturing with a proppant flowback-controladditive with careful control and monitoring ofinitial cleanup and production rates. Analysis ofpast screenless procedures and experiencesworldwide, particularly unsuccessful comple-tions, confirmed that when any of these tech-niques or associated guidelines is misapplied,chances of success decrease significantly.

Well 48, originally drilled in the 1960s, couldnot support a conventional rig intervention fromits small caisson structure. For this reason, theoperator used a jackup rig to support completionoperations, including wireline, coiled tubing andhigh-pressure pumping equipment. After cementwas drilled out of the 31⁄2-in. liner, the screenlesscompletion was performed in four stages: • optimized perforating • coiled tubing acidizing and consolidation • TSO proppant fracturing with PropNET fibers • coiled tubing wellbore cleanout.

NODAL production system analysis deter-mined that a 6-ft perforated interval could pro-duce 400 B/D [63.6 m3/d] with less than 100 psi[689 kPa] of pressure drawdown at the sand-face. Based on SPAN Schlumberger PerforatingAnalysis modeling software, J.M. Huber andSchlumberger representatives selected chargesto create a 0.33-in. [8.4-mm] diameter entrancehole in the casing. This perforating job wasdesigned to achieve the required productionrate and prevent sand influx by helping toensure that the propped fracture would coverthe perforations completely.

Perforation density was limited to 6 shots perfoot (spf) to improve treatment placement andreduce the likelihood untreated perforations. Aphasing of 0° further ensured that perforationswould communicate with the propped fracture.The engineering team, however, still worriedthat proppant flowback might initiate sand pro-duction. This dictated the need for a consolida-tion treatment prior to fracturing. Engineerschose K300 furan resin, which could be placedacross the short perforated interval using coiledtubing, to stabilize a volume of formation aroundthe wellbore.

Resins tend to reduce formation permeabil-ity to some extent, but hydraulic fracturesextend past the consolidated near-wellboreregion. Chemical consolidation prevents sand

48 Oilfield Review

TEXAS

FLORIDA

GEORGIAALABAMAMISSISSIPPI

LOUISIANA

New Orleans

South TimbalierBlock 21

G u l f o f M e x i c o

USA

MEXICO

0

0 200 400 600 km

100 200 300 400 miles

> South Timbalier Block 21 field, Gulf of Mexico, USA.

Spring 2003 49

production early in the life of a well, but by itselfmay not control sand influx in later stages ofreservoir depletion. This soft, or weakly consoli-dated, formation also required a short, widepropped fracture to control sand by reducingflowing pressure drop and preventing sand influxthrough perforations.

For this job, the operator used a low-guar,borate-crosslinked fracturing system that wascompatible with reservoir fluids. A 20/40 mesh,stress-cured, ceramic RCP was selected to avoidcrushing of the proppant at the 8000-psi [55-MPa] formation stress. PropNET fibers wereadded to proppant-laden fluid stages. The TSOfracture treatment, performed from a stimula-tion vessel, placed 9096 lbm [4126 kg] of prop-pant in the formation out of a total 13,204 lbm[5989 kg] pumped. Decreasing pump rate at theend of the job avoided excessive surface treatingpressures. Controlled flowback immediatelyafter pumping ceased initiated rapid forced clo-sure of the hydraulic fracture.

Initially, the well tested at a rate of 535 B/D[85 m3/d] of oil and 4 MMscf/d [114,560 m3/D] ofgas with a tubing pressure of 3700 psi[25.5 MPa]. NODAL analysis confirmed a frac-ture permeability of 200 mD and a slightly nega-tive skin effect. This indicated that the zone wasstimulated and would produce better thanundamaged formation. After more than a month,hydrocarbon rates stabilized at about 500 B/D[79.5 m3/d] of oil and 2.5 MMscf/D [71,591 m3/d]of gas with a 3500-psi [24.1 MPa] flowing tubingpressure (ftp).

One year after pumping the sand consolida-tion treatment, this well was still flowing 220 B/D[35 m3/d] of oil, 850 B/D [135 m3/d] of water and380,000 scf/D [10,882 m3/d] of gas at a 1520-psi[10.5-MPa] ftp. There was no significant sandproduction during the first year of production.

Offshore Italy: Dry-Gas Completions Eni S.p.A. E&P Division applied screenless tech-nology to address sand production in AdriaticSea fields off the eastern coast of Italy (above).22

Many reservoirs in this area comprise interbedded

21. Riddles C, Acock A and Hoover S: “Rigless, ScreenlessCompletions Solve Sand Control Problems in TwoOffshore Fields–Part 1,” Offshore 62, no. 6 (June 2000):48–50, 98.

22. Pitoni E, Devia F, James SG and Heitmann N:“Screenless Completions: Cost-Effective Sand Control inthe Adriatic Sea,” paper SPE 58787, presented at theSPE International Symposium on Formation DamageControl, Lafayette, Louisiana, USA, February 23–24, 2000;also in SPE Drilling & Completions 15, no. 4 (December2000): 293–297. Heitmann N, Pitoni E, Ripa G and England K: “Fiber-Enhanced Visco-Elastic Surfactant Enables Cost-EffectiveScreenless Sand Control,” paper SPE 78323, presented atthe 13th SPE European Petroleum Conference, Aberdeen,Scotland, UK, October 29–31, 2002. Pitoni E, Ripa G and Heitmann N: “Rigless, ScreenlessCompletions Solve Sand Problems in Two OffshoreFields–Part II,” Offshore 62, no. 7 (July 2002): 64–68, 109.

2 7⁄8-in. tubing withgas-lift mandrels

7-in. casing

Polished-bore receptacle(PBR) and 5 1⁄2-in. liner:11,101 ft MD

Packer

Cement

Liner hanger:7652 ft MD

Liner hanger:10,811 ft MD

Perforations: 11,774 to 11,780 ft MDPlug-back depth:12,100 ft MD3 1⁄2-in. liner:12,160 ft MD

Propped fracture

> Redesigned completion. During drilling of theWell 48 lateral sidetrack at a 40° borehole incli-nation angle, shallow pressure-depleted zonescaused the original 5-in. liner to become stuck at11,101 ft [3384 m] MD, so it had to be cemented inplace. This setback required that an additional31⁄2-in. liner be run to TD at 12,160 ft [3706 m] MD.A polished-bore receptacle (PBR) designed toaccept a seal assembly was run at the top of the31⁄2-in. liner. The redesigned completion had apacker with 27⁄8-in. tubing above and below it setin 7-in. casing to allow for through-tubing fractur-ing operations. Tubing-movement calculationsverified equipment stability, and computer frac-ture simulations determined safety limits duringthe TSO fracture treatment.

ASIAEUROPE

AFRICA

ITALY

T y r r h e n i a n S e a

A d r i a t i c S e aNaples

Rome

Giovannafield

0

0 200 300 400100 500 km

100 200 300 miles

> The Giovanna field offshore eastern Italy.

layers of sand, silt and clay. Pay intervals havelow to moderate permeability and historically produce formation solids, which requires sand-control completion methods. Typically, Eni com-bines several sedimentary groups into “pools”that are completed with conventional gravelpacks and produced separately. Some wells havemore than 10 distinct pools.

Most wells are dual completions with twoparallel strings of 23⁄8-in. tubing. A gravel packcannot be installed for the short string of wellswith 7-in. casing, which limits the number ofpools that can be completed in a single wellbore(above left). Accessing other pools requiresexpensive recompletion operations with conven-tional rigs. In 95⁄8-in. or larger casing, a single,selective gravel pack can be installed for theshort string, but full-scale workovers are neededto complete additional intervals.

Without sand control, however, upper zonesbecome choked by sand in a short time, oftenless than two years. Effective and reliablescreenless methods allow completion of multiplelayers through the short string without regard tocasing size and without bypassing or deferringproduction of reserves. This approach reducesdrilling and completion costs significantly andallows more gas zones in a well to be producedefficiently, even with smaller 61⁄8-in. boreholesand 5-in. casing.

Like other developments in this area, theGiovanna field consists of heterogeneous lami-nated and stratified reservoirs with a gas rela-tive permeability that is low—about 12 mD.These “dirty” sandstones have clay contents ashigh as 50%. Produced sand and migrating finescause productivity declines that significantlyreduce field output. An upper zone in GiovannaWell 6 was selected for a screenless completionfield trial. Eni initially completed this well withdual 23⁄8-in. tubing in December 1992, but the

wellbore filled with sand in less than two yearsand had to be shut in (left).

Eni and Schlumberger evaluated each step ofthe screenless-completion process—perforating,formation consolidation, fracturing for sand con-trol and optimal treatment-fluid selection. Opti-mized perforating was not an option because thewell had existing perforations and a slotted-pipeextension across the target interval. Low perme-ability limited matrix injection rates and pre-vented the use of conventional formation-consol-idation resins. The remaining option was toremove sand fill from the wellbore and performa TSO fracture treatment with effective prop-pant-flowback control.

A relatively low fracture-closure stress—3000 psi [20.7 MPa]—simplified proppant selec-tion, but choosing a mesh size was more diffi-cult. Larger proppant sizes maximize fractureconductivity, but smaller sizes prevent formationparticle migration. Wide TSO fractures reducedthe likelihood of fines transport by decreasingdrawdown pressure and flowing gas velocity inthe formation during production. Therefore, aproppant size that could control sand produc-tion, but not fines invasion, was chosen.

After comprehensive fracturing studies andsimulations, Eni chose a ClearFRAC fluid to meetfracturing objectives. ClearFRAC VES fluids con-sistently demonstrate superior proppant suspen-sion and transport characteristics, even at lowviscosities. Minimizing fracturing-fluid viscosityand optimizing fluid leakoff helped achieve ashort and wide TSO fracture in the GiovannaPool 10 formations, which had not been possiblepreviously with conventional polymer-based frac-turing fluids. PropNET fibers were added to keepproppants inside the fracture.

Prior to fracturing, coiled tubing cleanoutoperations removed sand fill inside and aroundthe perforated extension pipe. A sand plug wasplaced, or spotted, with the top at 5754 ft[1754 m], leaving 39 ft [12 m] of open perfora-tions for fracturing. Because of platform spacelimitations, all slurry stages for the fracturetreatment were batch-mixed in tanks with independently controlled paddles and recircu-lating pumps to ensure better fluid mixing and consistency.

This screenless treatment was pumpedthrough the existing completion and performedwithout a conventional rig. Monitoring net pressure ensured generation of a mature TSOfracture with adequate width. Wellsite observa-tions of surface tanks and treatment lines con-firmed that the PropNET fibers helped suspendproppant in the low-viscosity slurry.

A coiled tubing wellbore cleanout was per-formed and the well placed on production. The

50 Oilfield Review

7-in. casing

Packer

Packer

Packer

Dual-tubingpacker

Internal cased-hole gravel pack

Internal cased-hole gravel pack

Openholegravel pack

Cement

> Typical Adriatic Sea wellbore configuration.

Cement

7-in. casing

Dual packer

Packer

2 3⁄8-in. tubing

Proppedfracture

Perforatedextension pipe

Perforations

> Giovanna field: Well 6, Pool 10, screenless completion.

Spring 2003 51

39-ft zone produced gas with no formation sand,fines, proppant or fibers, and at more than twicethe initial gas rate and flowing pressure of theoriginal completion. Giovanna Well 6 producedsand- and fines-free for two and a half months.

PropNET fiber effectiveness depends on fric-tion between proppant particles and individualfibers. Proppant size, roundness and surfacetexture, and fracture closure pressure as well asfiber length contribute to robust, stabilizedfractures. In laboratory tests, PropNET fiberscreate extremely stable packs, even at zero clo-sure stress. This was confirmed in GiovannaWell 6. No proppant was produced from the“stress-free” annular pack behind the perfo-rated extension pipe.

Offshore Italy: Ongoing ImprovementsBased on the successful rehabilitation of production from Pool 10, Eni immediately sched-uled major workovers for this well and two others.

Eni used programmable, continuous blend-ing equipment to perform additional treatmentson two zones of the short string in Giovanna Well20. The zones have not yet been producedbecause field-development plans call for otherintervals to be depleted first. However, the highnet pressures achieved during both of these screenless treatments indicated favorablefracture geometries that should prevent sand production.

In nearby Annalisa field, a secondary zonewas completed through the short string of a wellwith dual tubing using screenless methods.Without screenless technology, this intervalcould not have been completed and produced.The well initially produced at economic gasrates, but sand production occurred before thezone was shut in to open the primary zone. Post-treatment analysis indicated that the TSO frac-ture did not develop enough width becauseinsufficient net pressure was achieved. A short-age of premixed fluid quantities during theAnnalisa field frac pack highlighted the impor-tance of continuous onsite mixing and blendingof treatment fluids, proppants and additives fortreatment consistency and quality control.

Adequate net-pressure buildup to createoptimal fracture geometry is difficult to achievein soft formations, such as these Adriatic Seareservoirs. Eni prefers low-viscosity, brine-basefluids for compatibility with Adriatic Sea forma-tions, but their high fluid leakoff characteristicsoften do not generate the required fracturegeometry. Polymer-base fluids, with low fluidleakoff, create fractures that are long and nar-row, and may result in excessive vertical fractureheight without achieving a TSO.

Using nondamaging ClearFRAC fluids, Eniand Schlumberger tailored fluid characteristicsto match reservoir characteristics and optimizefracture geometry. However, even with extremelylow fluid viscosities, achieving effective prop-

pant suspension capabilities while maintainingsufficient fluid leakoff is possible only by reducingpump rates at an early stage—often halfwaythrough a treatment. This requires prompt wellsite decisions based on real-time monitoringof net fracturing pressure to achieve optimalTSO fracturing.

Some screenless completions in the AdriaticSea were considered successful while others hadmixed results because of operational rather thantechnical limitations. All these attempts pro-vided valuable lessons regarding this emergingtechnology and implementations of novel riglesstechniques in future well completions and reme-dial interventions.

Offshore Italy: Gravel-Pack Remediation Screenless completions provide a cost-effectivemeans of restoring production in gravel-packedcompletions that fail because the screens areeroded by sand or plugged with fines, hydrocar-bon deposits or scale. This method can be imple-mented without using conventional rigs to pullcompletion tubulars, equipment and screens.Initial applications targeted gravel packs up toabout 50 ft in length and utilized coiled tubing.These remedial treatments are a multistage pro-cess, using standard techniques and fluids, suchas the OrganoSEAL system, to consolidate annu-lar gravel packs between existing screens andcasing before perforating and fracturing (below).

Consolidated annulargravel pack

SqueezeCRETE cementseals unwanted sectionsof existing gravel packs

180° remedial perforations

TSO proppedfracture

Consolidated formation

Initial perforations

CementCasing

> Gravel-pack repair. Screenless techniques provide alternatives for rehabilitating existing completions that have eroded (left) or plugged (right) screens.Coiled tubing is run to clean out the wellbore, displace produced fluids and place, or spot, a consolidation chemical across and above sand-exclusionscreens. These steps are followed by a pressure squeeze to force treatment fluids into the gravel-pack annulus (center). The main objective is to shut offgravel-pack permeability and prevent a wellbore fracture screenout caused by annular fluid loss. Chemical consolidation of the annular pack also keepsperforation tunnels open after reperforating and performing a TSO fracturing treatment. "Micro" cement technology, such as SqueezeCRETE fit-for-purposeslurries, can penetrate and seal off unwanted sections of gravel-packed screens.

Fit-for-purpose SqueezeCRETE cement fluidsolutions can shut off unwanted sections ofgravel packs that are longer than 50 ft. Thesespecially engineered cement slurries penetratefarther into proppant packs than other “micro”cements without bridging or dehydrating duringplacement. This technique helps avoid excessloss of treatment fluid and premature screenoutin existing gravel packs.23

Jetting across a treated interval using coiledtubing tools with fluid nozzles on a rotating headremoves consolidation chemicals from inside thescreens. No attempt is made to remove the con-solidation system from gravel behind thescreens. Wells then are recompleted with opti-mal perforations using deep-penetrating chargesto provide sufficient penetration into the forma-tion and large enough entry holes in casing tofacilitate fracturing success. After reperforating,the screen and consolidated gravel pack arestimulated with a TSO fracture treatment thatincludes proppant-flowback control additives.

Because of the Giovanna field screenless suc-cesses, Eni recognizes rigless application ofscreenless methods as a practical alternative torehabilitate wells once believed to require con-ventional rig interventions. Rigless techniques

also allow recompletion of wells with gravel-packed screens that fail or plug. Giovanna Well14 was the first candidate well for screenlessrehabilitation of failed screens without pullingand replacing the completion equipment.

Downhole conditions, reservoir compactionand a long completion interval presented operational challenges. The lower section ofscreen and gravel pack was shut off with aSqueezeCRETE cement slurry to reduce the tar-get interval below 30 ft. In addition, the reperfo-rated interval allowed coiled tubing access tojust the first 12 ft [3.7 m], so the TSO fractureprobably did not cover all of the perforations,which resulted in early fines migration.

Another screenless completion was identi-fied and scheduled for an uncompleted intervalin Giovanna Well 16, but reservoir compactionbuckled the production equipment and madereentry impossible. Several additional screen-less completions are planned in other fieldswhere the dilemma facing completion teams isthat remaining gas reserves in target layers areinsufficient to justify the expense and risk ofconventional rig operations. Dual-well comple-tions were equipped with a sliding side door(SSD) at one or more perforated intervals within

their short or long production strings. Beforescreenless completions were performed underthese conditions, surface tests were used to ver-ify the feasibility of fracturing through an SSD.Full-scale yard tests assessed potential erosionand pressure integrity of the SSD after pumpingsignificant volumes of proppant-laden fluidunder field conditions.

These surface tests were performed in fourstages with pressure tests and visual inspectionsconducted after every stage. After pumping87,000 lbm [39,462 kg] of proppant at concentra-tions up to 12 pounds of proppant added (ppa),the SSD valve was tested to 3000 psi [20.7 MPa].Visual inspection confirmed only minor superfi-cial erosion effects, verifying that large volumesof proppant-laden fluid can be pumped throughan SSD valve without jeopardizing its pressureintegrity and without significant erosion. Subse-quently, SSD devices installed downhole havebeen closed, successfully pressure tested andreopened following screenless treatments in sev-eral Adriatic Sea wells.

52 Oilfield Review

Coiled tubing unit

Pay zone 1

Pay zone 2

Pay zone 3

Sand plug

Packer

Coiled tubing unit

Pay zone 1

Pay zone 2

Pay zone 3

Fracture

Straddle-isolation tool

Fracture

> Coiled tubing-conveyed fracturing. CoilFRAC stimulation through coiled tubing service facilitates formation consolidationand hydraulic fracturing of individual or multiple zones in a single operation. A tension-set coiled tubing packer and sandplugs can be used for zonal isolation. Pumping schedules for each zone include extra proppant to spot a plug across frac-tured intervals before moving up to treat the next zone (left). The CoilFRAC ST straddle tool system seals above and belowtarget intervals to isolate individual zones for selective stimulation. The tool can be moved quickly from one zone to anotherwithout pulling out of the well (right).

23. Boisnault JM, Guillot D, Bourahla A, Tirlia T, Dahl T,Holmes C, Raiturkar AM, Maroy P, Moffett C, Mejía GP,Martinez IR, Revil P and Roemer R: “ConcreteDevelopments in Cementing Technology,” OilfieldReview 11, no. 1 (Spring 1999): 16–29.

24. 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.

Spring 2003 53

Selective Treatments In addition to proppant-flowback control, thesuccess of screenless completions relies heavilyon effective placement of stimulation fluids andcomplete fracture coverage across all open per-forations. With coiled tubing as the conduit forproppant-laden fracturing fluids, multiple payzones can be treated consecutively during a sin-gle mobilization (previous page). The CoilFRACstimulation through tubing service using aCoilFRAC ST straddle tool system selectively iso-lates individual intervals to achieve optimal frac-ture width and conductivity without conventionaldrilling-or workover-rig intervention.24

Screenless completions offer a viable alter-native when conventional sand-control methodsare economically unattractive or cannot beapplied. This approach allows production fromzones that previously could not be completed.Screenless techniques are straightforward andcan be reapplied later in the productive life of awell if the need arises. Increasingly, operatorsrecognize this technology as an enabling well-completion strategy for both well completionsand production rehabilitation.

Sand-Management SolutionsOperational problems associated with sandinflux adversely affect well and reservoir produc-tivity, jeopardize wellbore longevity, limit reme-dial-intervention options and impact fieldprofitability adversely. Ensuring that perforationtunnels and the surrounding formation remainstable is an important element of sand-manage-ment efforts (above).

Selecting screenless candidates, therefore, isan important aspect of well-completion planningand execution that requires careful formationevaluation and characterization using the high-est quality production data as input to sand-pre-diction models, fracture-design programs andreservoir simulators. SandCADE software andother mechanical models establish maximumcritical drawdown pressures and flow rates toavoid proppant flowback during cleanup and pro-duction phases.

Currently, wells that benefit most fromscreenless methods are those with configurationsthat make installation of internal completion

assemblies difficult, undesirable or even impos-sible. However, applications for rigless tech-niques will increasingly involve recompletion ofwells to tap marginal reserves that do not eco-nomically justify conventional rig-based opera-tions. Screenless results to date clearly provethe viability of this emerging technology, whichprovides attractive solutions to avoid otherwisedeferred production and lost reserves.

Screenless techniques are an important ele-ment in advanced sand-management strategies,but they will not replace conventional sand-control methods. In some reservoirs, however,they provide cost-effective alternative strategiesto eliminate or manage sand production over theproductive life of a well or field development.Current research and development efforts aredirected at improving computer models for pre-dicting sand production and providing enhancedrisk assessment. These efforts will ensure theeffectiveness of increasingly sophisticated wellperforating and completion techniques. —MET

Prediction

CashFlow Traditional completion

Time

Completion 3Completion 2

Completion 1

Prevention and control Remediation

Monitoring

Geomechanicalearth models

Sand predictionmodels

Economic and risk-analysis models

Production logging

Sand detection

Intelligentcompletions

Recompletions

Riglessinterventions

Optimal perforating Optimal perforating

TSO fracturestimulation

Optimal perforating

TSO fracturestimulation

Proppant-flowbackcontrol

Formation consolidation

Cement technology

Selective coiledtubing treatments

Optimal perforating

Proper gravel placement

Cased-hole gravel pack

Openhole gravel pack

Frac pack

Expandable screens

Optimal perforating

Artificial-lift design

Downhole desander

Natural completion Stimulated completion Screenless-completion methods Conventional sand-exclusion methodsManage produced sand

Decreasing formation stability

> The sand-management solutions approach.