10 Oilfield Review

Expanding Applications for Viscoelastic Surfactants

Slaheddine KefiCambridge, England

Jesse LeeTimothy L. PopePhil SullivanSugar Land, Texas, USA

Erik NelsonConsultantHouston, Texas

Angel Nuñez Hernandez Petróleos de Venezuela S.A. (PDVSA)Barinas, Venezuela

Tom OlsenDenver, Colorado, USA

Mehmet Parlar Rosharon, Texas

Brian PowersBPBaku, Azerbaijan

Alistair RoyAllan WilsonBPAberdeen, Scotland

Allan Twynam BPSunbury, England

For help in preparation of this article, thanks to Curtis Boney,Ernie Brown, Steve Davies and George Hawkins, Sugar Land,Texas, USA; Jorge Gonzalez and Arthur Milne, Caracas,Venezuela; Satyaki Ray, Calgary, Alberta, Canada; and David Schoderbek, Burlington Resources Canada, Calgary.

ClearFRAC, ClearPAC, CoalFRAC, FMI (Fullbore FormationMicroImager), FracCADE, NODAL, OilSEEKER andPERMPAC are marks of Schlumberger. Alternate Path is a mark of ExxonMobil Corp.; technology licensed exclusively to Schlumberger. FANN is a mark of the Fann Instrument Company.

Recent developments in viscoelastic surfactants have expanded application of these

unique materials in new and challenging environments. From well completions to

stimulations, viscoelastic surfactant systems are improving well productivity and

hydrocarbon recovery.

Minute objects can have a disproportionateimpact on large-scale endeavors. A drop of inkcan darken a full glass of water, while splitting anatom causes a significant release of energy.Micelles—microscopic structures of water boundtogether by surfactant—are obscure to thenaked eye, but only a few volume percent areneeded to improve the efficiency and effective-ness of reservoir stimulation operations.1

Surfactants are used in many oilfield opera-tions, such as drilling and reservoir stimulation.2

Before 1950, stimulation treatments relied onflammable mixtures of napalm and gasoline tocreate viscous fluids capable of initiating andpropagating a hydraulic fracture.3 In the 1950s,engineers believed that introducing water into areservoir during a fracturing treatment causedformation damage, so wells were stimulated withviscous, or gelled, oils.

Researchers later found that water-base fracturing fluids were not as damaging to produc-tion as they first thought. In the 1960s, engineersturned to viscous solutions of guar, or guarderivatives, in brine.4

In the 1970s, the exploration and production(E&P) industry experienced an increase in

fracture stimulation as less permeable reservoirswere exploited. To stimulate deeper and hotterwells in these reservoirs, engineers needed fracturing fluids with higher viscosity and greaterthermal stability. In response, scientists developed a new generation of polymer-base fracturing fluids. Most often, guar polymers werecrosslinked with borate, zirconate or titanateions to generate high levels of viscosity.5

The 1980s saw advancements in laboratoryformation-damage evaluation techniques, alongwith a greater awareness of the fracture permeability damage caused by polymer-basefracturing fluids. To minimize polymer-inducedconductivity impairment, engineers began usingfoamed fracturing fluids. This reduced therequired polymer concentration by as much as50%. Formation damage from polymer residuewas reduced, and wells cleaned up faster andproduced with greater efficiency.

The next step occurred in the 1990s, whenscientists developed polymer-free aqueous frac-turing fluids based on viscoelastic surfactant(VES) technology. Since the first generation ofVES fluid systems, this technology has evolvedconsiderably. New chemical adaptations enhance

Winter 2004/2005 11

performance, and have been used to address awide variety of well environments and to createentirely new applications.

In this article, we review the evolution of VESchemistry in the oil field over the last decade asit progressed from a relatively obscure technol-ogy to mainstream use. Case histories from SouthAmerica, North America, the North Sea and theCaspian Sea demonstrate how these novel mate-rials help engineers optimize oil and gas assetperformance and improve hydrocarbon recovery.

From the BeginningIn 1983, the Dow Chemical Company introduceda family of surfactants later known as VES.6 They

were used as thickeners in consumer products,such as bleach, liquid dishwashing detergent andcosmetics. Their intriguing performance led

1. Micelle structures refer to a colloidal aggregation ofamphipathic molecules that occur at a well-defined critical micelle concentration.

2. Chase B, Chmilowski W, Marcinew R, Mitchell C, Dang Y,Krauss K, Nelson E, Lantz T, Parham C and Plummer J:“Clear Fracturing Fluids for Increased Well Productivity,”Oilfield Review 9, no. 3 (Autumn 1997): 20–33.

3. Chase et al, reference 2.

4. Guar is a hydrophilic polysaccharide derived from seedsof the guar plant. Highly dispersible in water and brinesof various types, it can be crosslinked by borax and othercompounds to yield high gel strength for suspendingsolids, such as sand and other proppants. Guar is com-monly used in fracturing fluids to generate the requiredviscosity. Guar has low thermal stability, is pH sensitive,and is subject to bacterial fermentation.

5. Ely JW: Stimulation Engineering Handbook. Tulsa: PennWell Publishing Company (1994): 79–97.

6. Chase et al, reference 2.

engineers at the Dowell Tulsa Technology Center,now Schlumberger, to explore ways of applyingVES technology in the oil and gas industry.

Surfactants are compounds whose molecularstructures contain both hydrophilic (waterattracting) and hydrophobic (water repelling)groups. Most surfactants consist of a hydrophilichead group and a hydrophobic tail group (aboveleft). When added to an aqueous fluid, surfactantmolecules combine to form structures known asmicelles. The hydrophobic tails of the micellesassociate to form a core that is surrounded bythe hydrophilic heads, isolating the tails fromcontact with water. Typically, micelles are spheri-cal in shape.

In the case of VES surfactants, when certainsalts are present in the aqueous fluid within aparticular concentration range, the micellesassume a rod-like structure similar to polymerstrands (above). These rod-like micelles becomeentangled, viscoelastic behavior develops, andfluid movement is hindered (left). A significantincrease in viscosity occurs as does the develop-ment of pseudosolid elastic behavior.7

12 Oilfield Review

> The molecular level. Viscoelastic surfactants exhibit a well-defined, hydro-philic head structure (right) attached to an articulated tail section with ahydrophobic end (left). When dispersed in specific brine solutions, tailsections associate, ultimately forming a worm-like micellular structure.

Hydrophobic tail group

Hydrophilic head group

> Chemomechanical effects and viscoelasticity.When blended with salt solutions at the correctconcentration, VES materials form rod-shapedmicelles that become entangled under staticconditions (top), thus imparting fluid viscosity andpseudosolid elasticity. When exposed to evensmall amounts of shearing energy, such as thatprovided by pumping the fluids, micelles readilybecome disassociated (bottom). Elasticity andviscosity decrease.

Static

Dynamic

Flow

dire

ctio

n

> Micrograph of micelles. Viewed through an environmental scanningelectron microscope, VES molecules dispersed in an aqueous solution areshown to associate, form rod-like structures and entangle, ultimatelygenerating viscosity.

0.1 micron

Winter 2004/2005 13

When micelles are disassociated by shearenergy, the rheological behavior of VES fluids is similar to water, or nearly Newtonian; yet viscosity and elastic behavior recover when thedisrupting energy is removed (right). The uniquechemomechanical properties that create VES viscosity readily lend themselves to shear thin-ning, static suspension, low static to dynamic transition-energy requirements and high particle-transport efficiency. VES fluids requireless energy to pump than more conventionalpolymer fluids, effectively reducing wellsitepump-horsepower requirements.

The viscosity of VES fluids may decrease withtemperature. However, increasing the surfactantconcentration or adjusting the salt concentrationcan reduce this temperature-related thinning.Unlike conventional polymer systems, VES viscosity does not degrade with time, and is predictable and easily modeled, coupling opera-tional simplicity with an efficient and effectivefluid design (middle right).

Early laboratory experiments showed that theviscosity of VES fluids is easily broken by contactwith hydrocarbons or dilution by formationwater. Produced oil or condensate alters theelectrical environment in the fluid causing themicelle shape to revert from rods to spheres (bottom right). Fluid viscosity falls because thenow-spherical micelles cannot become entan-gled. Alternatively, when VES fluids are dilutedby formation water, the surfactant concentrationeventually falls to a level at which insufficientnumbers of micelles are present to entangle, andviscosity is lost. Simple laboratory tests are oftenperformed to confirm the compatibility of VESfluids with specific produced hydrocarbons.

In the early 1990s, Schlumberger first appliedVES chemistry in PERMPAC viscoelastic surfactant gravel-packing fluid. New to the oil-field, this cationic surfactant was able toviscosify common completion brines—potassiumchloride, ammonium chloride, calcium chlorideor calcium bromide—to suspend and transportgravel.8 The VES concentration varied from 2.5 to6% by volume, depending on the anticipated tem-perature in a well.

Unlike gravel-packing fluids based on polymer viscosifiers, such as guar or hydrox-yethylcellulose (HEC), VES fluids leave little

> Improved viscosity. When compared with more conventional hydraulicfracturing-fluid systems like hydroxyethylcellulose (HEC) (blue), VES systems(red curve) provide higher viscosity at shear rates that are experiencedduring fracturing (left), while providing similar viscosity at the lower shearrates that are typical in tubulars and perforations (right).

10

0.01 0.1 1 10 100 1,000

100

1,000

10,000

100,000Formation and fracture

Flow regime

Tubulars andperforations

Shear rate, s-1

Visc

osity

, cp

Viscosity Profile at 75°F [24°C]

2.5% viscoelastic surfactant

40-lbm/1,000 gal hydroxyethylcellulose

> Viscosity over time. ClearFRAC polymer-free fracturing fluids have sufficientviscosity for fracturing and other applications up to 275°F [135°C]. Whenexposed to elevated temperatures in laboratory tests, ClearFRAC HT fluidshows little loss of viscosity over time. The viscosity spikes shown at 25, 58,92 and 125 minutes are artifacts of the testing process.

0 20 40 60 80 100 120 1400

50

100

150

200

250

300

350

400

450

500

0

50

100

150

200

250

300

Time, min

ClearFRAC HT Baselines

Appa

rent

vis

cosi

ty, c

p at

100

s-1

Tem

pera

ture

, °F

Temperature5% ClearFRAC HT4% ClearFRAC HT

> Breaking viscosity. VES fluids can lose their viscosity in several ways. Oncontact with breakers, formation water or liquid hydrocarbons, micelles losetheir rod-like shape, collapsing into spheres. Once this occurs, micelles canno longer entangle; viscosity is lost and is generally unrecoverable.

Breaker or contact with

liquid hydrocarbon

Worm-like micelles Spherical micelles

+ =

7. Pseudosolid is a term describing materials that develophighly viscous gel structures, that may exhibit elasticbehavior and that require little energy to reduce the gel to liquid.

8. Cationic surfactants are surface-active agents typicallycomposed of fatty amine salts. They have a net positivecharge, and they are stable over a range of pH levels andin various salt solutions.

residue, which significantly reduces gravel-pack damage.9

PERMPAC surfactant was eventually used inhydraulic fracturing applications, forming thebasis for subsequent development of ClearFRACpolymer-free fracturing fluid. However, cost andtemperature limitations—140°F [60°C]—precluded widespread use in fracture treatments.

Schlumberger introduced the original ClearFRAC surfactant system in 1997. LikePERMPAC fluids, the system was built oncationic surfactant chemistry. The ClearFRACsurfactant proved to be stable in low-densitybrines at temperatures up to 200°F [93°C]. Witha high percentage of fracturing operations occur-ring at temperatures below 200°F, the market forVES fluids in fracturing was broad. In addition,the surfactant could be mixed continuously withbrine, and the resulting fluid system could befoamed, or energized, with nitrogen [N2].

The Challenge of Green Chemistry From the beginning, VES fracturing and gravel-packing fluids improved well performance.Building on this early success, these fluids havecontinued to evolve. By the late 1990s, the questfor new oil and gas reserves led operators to drilland complete wells in more challenging andenvironmentally sensitive areas.

The VES fluids introduced in the early 1980s were based on cationic surfactant chem-istry. Although effective from both an operationaland cost perspective, and environmentallyacceptable in most land-based locations, cationicsurfactants are not always dischargeable inmarine environments.

To address discharge concerns, Schlumbergerengineers and scientists began the developmentof noncationic viscoelastic surfactants. By early2000, researchers had discovered new anionicsurfactants capable of meeting both environmen-tal and functional demands.10

The result, ClearFRAC EF polymer-free frac-turing fluid, improved performance in somesituations, while providing a fluid that could bedischarged in environmentally sensitive areas,such as the Lake Maracaibo region of Venezuela.

In South America, many wells have beendrilled and completed in Lake Maracaibo, innorth-central Venezuela. Today, discharges from oil and gas operations are limited to products and materials that meet strict environ-mental standards.

Wells in the Bachaquero field of Lake Maracaibo generally produce from unconsoli-dated, highly permeable, Miocene sandstones. In

many cases, hydraulic fracturing stimulation hasproved effective for improving well performance.

Engineers at the Schlumberger field supportlaboratory in Las Morochas, Venezuela, evaluatedvarious ClearFRAC surfactants, ultimately select-ing ClearFRAC EF for its environmentalacceptability in marine environments, its low ten-dency to form emulsions with locally produced oiland its viscosity profile under predicted downholeconditions (top).

To improve well performance on steam injector Well BA-2233, engineers performed a fracturing operation generating a 0.6-in. [15.2-mm] fracture (above). Using a ClearFRAC EFcarrier fluid, just under 60,000 lbm [27,215 kg] of20/40 fracturing proppant was placed in the formation. Tip screenout (TSO) was observed10 minutes after pumping began, or two minutesafter the proppant entered the perforations.11

14 Oilfield Review

> Ensuring viscosity on Lake Maracaibo. Engineers evaluated the rheologyperformance of ClearFRAC EF fracturing fluid in laboratory tests using aFANN 50 rheometer. Tests assured engineers that the fluid would performsatisfactorily. Fluid viscosity (blue) remained stable as temperature increasedfrom ambient to 150°F [65°C]. Seven minutes into the test, a change in shearrate (orange) caused a shift in viscosity. Once the shear rate was reduced,viscosity returned to normal for the duration of the 40-minute test. Thestability of the viscosity while the fluid heats up simplifies fracturingengineering. Unlike polymer fluids that lose viscosity with temperatureincrease, the proppant-transport efficiency of VES fluids does not vary as the fluid heats during pumping.

0 5 10 15 20 25 30 35 400

100

200

300

400

500

600

700

0

20

40

60

80

100

120

140

160

Time, min

Rheology Profile of ClearFRAC EF Fluid

Shea

r rat

e, rp

mVi

scos

ity, c

p

Tem

pera

ture

, °F

Shear rate, rpmShear stress, lbm/100 ft2

Shea

r stre

ss, l

bm/1

00 ft

2

Viscosity, cpTemperature, °F

> Results of fracturing operations. The image generated by FracCADEfracturing design and evaluation software shows an estimate of fracture heightand width (left). The fracture extends about 80 ft [24 m] from the borehole(right). About 60,000 lbm [27,215 kg] of fracturing proppant was placed in theBA-2233 well in the Lake Maracaibo area. Most regions of the fracturereceived over 14 pounds of proppant, producing an effective fractureconductivity of 19,746 mD/ft [6,019 mD/m].

-1.00 0 1.00 0

10

2010 30 40 50 60 70 80 904,050

4,000

3,950

3,900

3,850

12.2 to 14.2 ppa

>14.2 ppa

10.2 to 12.2 ppa

8.2 to 10.2 ppa

6.2 to 8.2 ppa

4.2 to 6.2 ppa

2.2 to 4.2 ppa

0.0 to 2.2 ppa

0 ppa

< 0 ppa

Fracture Width Proppant Concentration Contour

Width, in.

Dept

h, ft

Length, ft

Winter 2004/2005 15

NODAL production system analysis predicted that oil production after fracturing andprior to steam injection would be around 200 B/D[32 m3/d]. Actual production after stimulationwas 209 B/D [33 m3/d], in line with NODAL analysis predictions.

Returning Thinner FluidsFracturing fluids serve two primary purposes: first,to provide the hydraulic energy that generates and

opens a fracture; and second, to place transportedproppant materials in the open fracture to main-tain a conductive pathway, or conduit, for linearflow into the wellbore. Once these tasks are performed, pressure in the wellbore falls and thefracturing fluid flows to the surface.

In field tests, engineers found that, comparedwith more conventional polymer fluids, signifi-cantly lower viscosity levels were required with

VES fluids to efficiently transport and place fracturing proppant (left). However, in somecases, even minimal viscosity levels could slowfracturing-fluid flowback during well cleanup.

By shortening the time required to clean up awell, commercial production can be achievedsooner. With this in mind, developers beganresearch on breaker chemistry for VES fluidsthat would provide in-situ viscosity reduction in acontrollable and predictable manner.

Viscosity reduction in VES suspensionsdepends on various factors, including the ionicenvironment, the temperature and surfactant-packing parameters.12 Early experiments showedthat, like produced hydrocarbons, chemicalbreakers cause the VES micelles to change shapefrom rods to spheres, collapsing the entangledmicellular structure that generates viscosity.

By late 1999, developers discovered breakersthat could be encapsulated and blended withproppant for delivery in a uniform and effectivemanner across the length of the fracture (belowleft). In a typical fracturing operation, once theproppant has been placed in the fracture,hydraulic pressure is removed and the fracturebegins to close. Capsules containing the ClearFRAC breaker are crushed inside the closing fracture, releasing the breaker. Thebreaker alters surfactant-packing parameters ofthe fracturing fluid: the micelles collapse, andviscosity is reduced, effectively improving fracturing-fluid flowback.

In field applications, the use of VES breakersimproves well cleanup and increases early gasproduction. Unwanted fluid foaming is reducedat surface, gas and liquid separation improves,and fracture conductivity is optimized. Whencomparing production curves from wells fracturedwith older polymer-base systems with wells frac-tured with VES incorporating breaker chemistry,production curves often become similar withtime. However, in the first 60 days or so, quickercleanup of VES fluids using encapsulated

> Outperforming polymers. In both laboratory and field evaluations,ClearFRAC HT fluids outperformed polymer-base fluids (red) in transportefficiency. At low shear rate, ClearFRAC HT fluids provide higher viscositiesthan polymer fluids (blue – left), while at higher shear rate (blue – right),much lower viscosities are observed.

Visc

osity

, cp

at 1

00 s

-1

0.01

0.1

1

10

100

0.01 0.1 1 10Shear rate, s-1

100

35-lbm/1,000 gal polymer fluidClearFRAC HT fluid

> Effectiveness of VES breakers. The viscosity of ClearFRAC fluids (blue) can be reduced by adding breaker compounds. Most often, breakers areencapsulated, coming in contact with the VES fluid as the capsules arecrushed during the postfracture period. On exposure to encapsulatedbreakers, as much as a 10-fold reduction in VES fluid viscosity is seen (gold–left). The performance of increasing breaker concentration at increasingtemperature is shown.

Visc

osity

, cp

at 1

00 s

-1

300

250

200

150

100

50

050 100 150 200

Temperature, °F250 300 350

6% ClearFRAC surfactant in potassium chloride(KCl) solution6% ClearFRAC KCl solution + 7 ppt* breaker6% ClearFRAC KCl solution + 10 ppt breaker6% ClearFRAC KCl solution + 15 ppt breaker

* ppt is parts per thousand

9. Parlar M, Nelson EB, Walton IC, Park E and DeBonis VM:“An Experimental Study on Fluid-Loss Behavior of Fracturing Fluids and Formation Damage in High Permeability Porous Media,” paper SPE 30458, presented at the SPE Annual Technical Conference and Exhibition, Dallas, October 22–25, 1995.

10. Anionic surfactants are surface-active agents having a net negative charge.

11. Tip screenout fracturing involves deliberately causingproppant to bridge at the fracture tip through pad depletion. Further fracture propagation ceases and continued pumping increases the fracture width.

12. The surfactant-packing parameter is affected by solution conditions such as temperature and surfactantconcentration. It may also be influenced by changes inmicellular chain length and dissymmetry that cause anincrease in the surfactant’s spontaneous curvature, ultimately determining whether surfactant’s molecules will form spherical or cylindrical micelles.

breakers produces substantial incrementalgas—wells go online faster enhancing return on investment (top).

Extending Thermal LimitsEngineers, scientists and developers applying

VES fluids achieved several milestones, includingenvironmental acceptance and engineered viscosity control. Now, as drilling environmentsextend into more extreme conditions of tempera-ture, depth and pressure, VES systems are alsoevolving to meet these challenges.

The versatility of viscoelastic surfactantsmakes possible the development of fluid systemsfor specific applications. In Canada, a new VES system was needed to address drilling challenges in the shallow-gas development areasin southern Alberta (below left). Marginal economics, stringent environmental regulationsand cold wellbore temperatures made it necessary for operators to seek new fracturing-fluid technologies.

Schlumberger engineers responded by developing ClearFRAC LT polymer-free fracturingfluid, a VES-base fluid designed to meet severalrequirements including use in low-temperatureenvironments. While performing in cold wellbores at temperatures below 100°F [38°C],the new fluid also proved economical in situa-tions demanding low-cost hydraulic fracturingsolutions. To meet Canadian environmentalrequirements, developers designed the ClearFRAC LT system to be compatible withnonchloride salt solutions, such as ammoniumnitrate and nitrogen foam fracturing methods.ClearFRAC LT fluids can also be formulated withpotassium chloride and ammonium chloride.

As with other ClearFRAC products, the ClearFRAC LT surfactant is mixed continuously,saving considerable time on location. Costs arereduced and more zones can be stimulated eachday. Field tests conducted on multiple wells inCanada showed improved well economics andlogistics, and the ability to stimulate marginalpay zones in low-temperature environments.

Modifications of the ClearFRAC LT VESchemistry have found application beyond low-temperature wellbores, for example inunconventional reservoirs such as coalbedmethane (CBM) deposits and fractured carbon-iferous, or carbon-rich, shales, which can bedifficult to produce. Globally these types of reser-voirs represent as much as 3,500 to 9,500 Tcf [99 to 269 trillion m3] of natural gas.13

Permeability is one of the most critical factors in CBM recovery. Without intervention,fluid and pressure transmission is, for the mostpart, dependent on coal cleats and the associatednatural coalbed fracture system (next page, top).14

Unlike gas in a conventional sandstonematrix, CBM gas is entrained in the coal systemby adsorption onto the internal surfaces of coal.In sandstone systems, reducing pore pressure to500 psi [3,447 kPa] often releases all entrainedgas, while in a CBM deposit, pressures as low as100 psi [689 kPa] are often required.

Whether fractures are natural or induced dur-ing drilling or completion, the combination of low permeability and low drawdown pressures

16 Oilfield Review

> Incremental gas. Data from field tests show that ClearFRAC fluids clean up faster (blue), producingmore gas in the first month of production than polymer-base fluids (red). This incremental gas(shaded box) can offset stimulation cost and improve return on investment.

Field Test of ClearFRAC Fluid with Encapsulated BreakerAv

erag

e pr

oduc

tion,

Mcf

/D

Production curves

Shaded area indicates incremental gas production in first 35 days

Days from first delivery10 20 30 40 50 60 70 80 90 1000

250

0

500

750

1,000

1,250

1,500

1,750

2,000

ClearFRAC rate

Polymer fluid rate

ClearFRAC fluidPolymer fracturing fluid

> Shallow-gas plays in southern Alberta. Low-temperature ClearFRAC LTfluid was first designed to help operators economically and efficientlystimulate wells in areas of southern Alberta (gold), Canada.

C A N A D A

A L B E R T A

Red Deer

Edmonton

Grande Prairie0

0 200 400 km

100 200 miles

Calgary

Brooks

Winter 2004/2005 17

makes CBM reservoirs sensitive to any restrictionsin flow. Conventional horizontal completions havedemonstrated some success in producing tightCBM reserves. However, producibility drops dramatically as natural permeability falls below 10 mD. Damage from drilling or fracturing fluidsfurther reduces producibility.15

When a coal seam is exposed to drilling orfracturing fluids, swelling can result from sorp-tion of water, gelled fluids or water containinglow concentrations of friction-reducing agentssuch as partially hydrolyzed polyacrylamide(PHPA). This often leads to substantial reductionof cleat porosity and permeability (right). Five-to tenfold irreversible reductions have beenreported.16 Further permeability damage canresult from the failure to remove fracturing-fluidviscosifiers or gells from natural microfractures.

The postfracturing removal of these materialsis dependent on initiating a pressure drop andproducing the fluid from the coal. At the lowpressures inherent in CBM reservoirs, sufficientenergy may not be available to efficiently cleanup residual polymer-base fracturing fluids.

When preparing to hydraulically fracture aCBM deposit, engineers must also consider sensi-tive environmental issues. As much as one-thirdof US CBM reserves are located in areas where

13. Fredd CN, Olsen TN, Brenize G, Quintero BW, Bui T,Glenn S and Boney CL: “Polymer-Free Fracturing FluidExhibits Improved Cleanup for Unconventional NaturalGas Well Applications,” paper SPE 91433, presented atthe SPE Eastern Regional Meeting, Charleston, West Virginia, USA, September 15–17, 2004.For more on CBM gas production: Anderson J, Simpson M, Basinski P, Beaton A, Boyer C, Bulat D, Ray S, Reinheimer D, Schlachter G, Colson L, Olsen T,John Z, Khan R, Low N, Ryan B and Schoderbek D: “Producing Natural Gas from Coal,” Oilfield Review 15,no. 3 (Autumn 2003): 8–31.

> New gas from shallow coal. Although challenging to produce, coal seams provide a source of unconventional natural gas in the form of coalbedmethane (CBM). CBM exists as gas adsorbed on the coal matrix or as free gas in coal fractures, or cleats. Cleats may vary in size from microscopic to those large enough to be seen with the naked eye (left). Cleats generally orient perpendicular to natural bedding planes. Good quality wireline FMI Fullbore Formation MicroImager images can define larger coalbed outcrop cleats. In this image, abundant cleats are seen (right). Bright colors on the static images indicate more resistive lithologies, such as coals, while dark colors are either shales, silts, ash or open fractures. Natural shearfractures within coal may also be present and are usually rotated at variable angles with respect to bedding planes. (Photo and FMI image courtesy ofDavid Schoderbek, Burlington Resources Canada, Calgary, and Satyaki Ray, Schlumberger Canada Ltd, Calgary; used with permission.)

COAL

Static Image Dynamic Image

FMI Fullbore Formation MicroImager Log

Dip Tadpoles0° 90°

XXX8

XXX9

Erosional surface on silts

Traces of bedding

CoalSubvertical cleats

Rotated shear fractures Shaly coal

> Coalbed retained permeability. In laboratory return-permeability testing ona simulated coalbed, the nondamaging characteristics of polymer-free VESfluids (blue) are shown in comparison with polymer fluids (green and purple).

Coalbed Retained Permeability

Reta

ined

effe

ctiv

e fra

ctur

e pe

rmea

bilit

y, %

VES fluidat 120°F

VES fluidat 80°F

Polymer-base fluid

Polymer-base fluidwith breaker added

0

20

40

60

80

100

14. A cleat is a breakage plane found in coal deposits thatprovides natural conductivity through the coalbed.

15. Osman EA and Aggour MA: “Determination of DrillingMud Density Change with Pressure and TemperatureMade Simple and Accurate by ANN,” paper SPE 81422,presented at the 13th SPE Middle East Oil Show and Conference, Bahrain, June 9–12, 2003.

16. Puri R, King GE and Palmer ID, “Damage to Coal Permeability During Hydraulic Fracturing,” paper SPE 21813, presented at the SPE Rocky MountainRegional Meeting and Low-Permeability Reservoirs Symposium, Denver, April 15–17, 1991.

stringent environmental regulations control thecomposition of fluids that might come in contactwith potable groundwater.

Engineers at the Schlumberger Sugar LandProduct center (SPC) developed CoalFRAC nondamaging fracturing fluids specifically forCBM fracturing. CoalFRAC fluids are most oftennitrogen foamed and cause minimal sorptivedamage to coal cleats. As with other VES-basefluids, CoalFRAC fluids readily return to surfaceafter fracturing, avoiding potential permeabilitydamage associated with polymer-base fracturing-fluid residue.

Field tests in central Wyoming, USA, demon-strated VES fluid performance in unconventionalreservoirs. Initially, a six-stage fracture treatmentplaced 330,000 lbm [149,680 kg] of 16/30 meshproppant in the coalbed using a combination offoamed and nonfoamed conventional, polymer-base fracturing fluids that were not crosslinked.17

Since results were below expectations,Schlumberger and client engineers designed arefracturing program for the 600-ft [183-m]coalbed interval. Coalbed permeabilities rangedfrom 0.6 to 2 mD. Gas reserves were estimated at350 to 450 scf/ton [11 to 14 m3/t] of coal. Pumping

nine fracturing stages through coiled tubingusing CoalFRAC techniques, Schlumberger engineers placed 260,000 lbm [118,000 kg] of16/30 fracturing proppant using a nitrogen-foamed CoalFRAC fluid.

A combination of new fracturing techniquesand CoalFRAC VES fluid technology produced afivefold increase in initial production. More than100 CoalFRAC treatments have now been per-formed in North America. When compared withthe more common polymer-base fracturing-fluidtreatments, on average, production rates usingCoalFRAC fluids have improved 30 to 60% in bothCBM and carboniferous shale applications.

Operator interest in efficient fracturing fluidscontinued to expand from low-temperature appli-cations to much deeper and higher temperatureenvironments. Through 2002, VES stimulationfluids had proved effective at temperatures rang-ing from 40°F [4.5°C] to an upper limit of around220°F [104°C].

To address the need for VES fluids that could work effectively in high-temperature environments, scientists at SPC developed ClearFRAC HT polymer-free fracturing fluid, azwitterionic-base VES fracturing fluid specifically

for elevated temperature applications.18 TheClearFRAC HT system extends the operatingenvelope of VES surfactants to 275°F [135°C]while maintaining other attributes common toother VES fluids, such as low friction pressureand excellent proppant-carrying capacity. ClearFRAC HT fluids have low emulsion-formingtendencies, allowing them to be used in a broadrange of oil reservoir applications.

As with other VES-base fracturing fluids, theviscosity of ClearFRAC HT fluids is substantiallyreduced by dilution with formation brines, contact and mixing with hydrocarbons, or by theaddition of chemical breakers.

Improving Gravel-Pack PerformanceSand production is a serious problem in manyreservoirs, and operators go to great expense to minimize the effects of uncontrolled sandflow. Gravel packing, in its various forms, is commonly used to control sand flow into the production system.19

Increases in thermal stability, improvedbreaker technology and expanded compatibilitywith a variety of salt solutions have extended theapplications of VES fluids. Since their first intro-duction as a gravel-packing fluid, VES fluids areagain receiving attention from both sand-controland gravel-packing specialists.

In openhole gravel-packing operations, a carrier fluid transports and places specificallysized gravel in the annular space between thereservoir rock and the production assembly,often a slotted liner or wire-wrapped screen (left). The gravel acts as a filter, allowing formation fluid to flow from the formation to theproduction string while filtering out sand grainsand other formation fines. As with fracturingoperations, the conductivity, or ability of fluids to flow through the gravel pack, is key to maximizing well productivity.

Gravel packs must also be designed to provide uniform flow across the productionassembly. Poorly designed or implemented gravelpacks may subject the production assembly toareas of concentrated flow, or hot spots. In thecase of wire-wrapped screens, concentrated flowerodes the wire mesh, resulting in sand break-through and a shortened completion life thatmay lead to costly remedial workover or recompletion operations.

For prolonged gravel-pack life, engineersmust achieve uniform gravel placement and produced-fluid flow across the entire completion.Conductivity through a gravel pack can beimpaired by residual drilling or carrier-fluid

Oilfield Review

> Gravel placement with VES fluids. Placing gravel in extended-reach highly deviated wellbores is always difficult. Using VES fluids for proppant transport along with Alternate Path technology,engineers can minimize the risk of an incomplete openhole gravel pack. Shunt tubes attached to theoutside of the screen (top right) provide a path for the gravel-packing slurry to flow in the event of apremature screenout, or plugging.

CasingHeel Toe

Shunt tube NozzlesSlurry

Washpipe Blankpipe Gravel Screen Open hole Filtercake

Shunttube

Nozzle

WashpipeScreen

18

Winter 2004/2005 19

material left behind after flowback. Unlike manypolymer fluids, VES carrier fluids optimize graveltransport while leaving no damaging residue toimpair production.

During well construction, drillers attempt tominimize formation damage and drilling-relatedcomplications, such as stuck pipe, by reducingthe amount of fluid lost to a formation. Drillingfluids have multiple phases, often described ascontinuous and discontinuous phases. The continuous phase consists of a carrier fluid, mostoften water or oil along with salts and other compounds soluble in the carrier fluids. The discontinuous phase contains insoluble materials,such as weighting agents, drilled solids, polymersand solid-particulate fluid-loss reducers such ascalcium carbonate.

During drilling operations, the borehole isgenerally overbalanced—hydrostatic pressure isgreater than pore pressure. As the drilling fluidpushes against permeable reservoir rock, the formation acts as a filter and the continuousphase is forced into the rock pore spaces.Depending on the permeability and the size ofthe pore throats within the formation beingdrilled, small amounts of the discontinuousphase are deposited in the near-wellbore area,forming a filtercake, both internal and externalto the borehole face. As the fluid in the boreholecirculates, this process continues in a dynamiccycle of erosion and deposition.

Once the borehole is drilled, engineers usemechanical tools and chemical sweeps to pre-pare the borehole for an openhole completion.Regardless of the cleanup method, some quantityof residual filtercake and pore-throat solidsremains. If not removed, these materials migratefrom the reservoir rock into the gravel pack,potentially plugging flow paths, reducing conduc-tivity, impairing production and creating hotspots that shorten the life of the completion (above right).

To remove internal and external filtercakematerial, high drawdown pressures, greater than200 psi [1.38 MPa], may be required to initiateflow when filtercake is trapped between graveland formation. Industry data indicate that, with-out treatment, retained permeability afterflowback may be extremely low, sometimes lessthan 1% of original reservoir permeability.20

In the past, treatments to remove filtercakewere performed after the completion assembly andgravel packs were installed. This approachinvolved multiple trips into the hole to displace thegravel-pack carrier fluid and spot chemicals thatattack filtercake and other residual compounds.21

Today, engineers combine VES gravel-packcarrier fluids such as the ClearPAC fluid systemfor gravel packing, with enzymes and chelatingagent solutions (CAS) to attack the primary filtercake components—starches and calciumcarbonate [CaCO3] bridging agents. Removing ordegrading these compounds significantly reducesflowback-initiation pressure and allows degradedfiltercake material to pass through the gravelpack, minimizing permeability impairment andimproving well performance.

Implementation of a single-step gravel-packing and cleanup operation requires integration of well-construction and completiontechnologies. Through careful selection andengineering of the reservoir drilling-fluid design,

> Filtercake removal. Filtercake (left) can severely damage a gravel pack. If notproperly removed by mechanical and chemical means, the filtercake can flowback into the gravel pack during production, plugging flow paths and reducingpermeability and conductivity (right).

Mud

flow

Oil m

ud

Filtercakedepositedwhiledrilling

Completionfluid

Screens

Nondisplacedoil mud

Screensplugged byaggregatedcake fromborehole wall

Drilling Completion

17. Fredd et al, reference 13.18. A zwitterionic, or dipolar, compound carries both a

positive and negative charge. 19. For more on sand production and its control: Acock A,

ORourke T, Shirmboh D, Alexander J, Andersen G,Kaneko T, Venkitaraman A, López-de-Cárdenas J, Nishi M, Numasawa M, Yoshioka K, Roy A, Wilson A andTwynam A: “Practical Approaches to Sand Management,”Oilfield Review 16, no. 1 (Spring 2004): 10–27.

20. Brady ME, Bradbury AJ, Sehgal G, Brand F, Ali SA, Bennett CL, Gilchrist JM, Troncoso J, Price-Smith C, Foxenberg WE and Parlar M: “Filtercake Cleanup inOpen-Hole Gravel-Packed Completions: A Necessity or a Myth?,” paper SPE 63232, presented at the SPE Annual Technical Conference and Exhibition, Dallas,October 1–4, 2000.

21. For more on gravel packs and related technology: Ali S,Dickerson R, Bennett C, Bixenman P, Parlar M, Price-Smith C, Cooper S, Desroches L, Foxenberg B,Godwin K, McPike T, Pitoni E, Ripa G, Steven B, Tiffin Dand Troncoso J: “High-Productivity Horizontal GravelPacks,” Oilfield Review 13, no. 2 (Summer 2001): 52–73.

laboratory evaluation of cleanup chemistries,and evaluation of potential borehole conditions,VES fluids are helping engineers to uniformlyplace gravel and obtain consistent filtercakeremoval, particularly across long horizontal-borehole sections.

Deepwater Openhole Gravel PackingReaching for deep oil reserves in the Foinavenfield, about 190 km [118 miles] west of the Shetland Islands, in the UK sector of the NorthSea, BP operates two blocks in 400 to 600 m[1,312 to 1,969 ft] of water. Development of thefield began in late 1994. By 2003, BP had drilledand completed the world’s longest deepwateropenhole shunt-tube gravel-pack completion, thefirst step in accessing oil reserves estimated atmore than 250 million bbl [40 million m3].22,23

Initial development of the T25 reservoir in the Foinaven field consisted of a single horizontal-wellbore completion. The P110 wellreaches across 937 m [3,075 ft] of open hole,spans two sand bodies separated by a 162-m[532-ft] shale section, and accesses an estimated42 million bbl [6.7 million m3] of oil.

Various types of openhole completion designswere available to BP engineers when field development began in 1997. However, no develop-ment had been as challenging as the P110 well.With the high cost of operations and the riskinvolved in deepwater operations, considerableresources were dedicated to the planning anddesign of the P110 completion.

Engineers first examined whether more than900 m [2,952 ft] of horizontal borehole could beeffectively gravel packed, and if so, how. Usingnumerical simulations and friction data from anearlier large-scale yard test, engineers determinedthat openhole shunt-tube gravel-packing technol-ogy could ensure effective gravel placement inwellbores exceeding 900 m and potentially as longas 1,524 m [5,000 ft]. However, to stay below friction-pressure limits, flow rates during gravelplacement would need to be low, around 2.5 bbl/min [0.4 m3/min].

Effectively delivering gravel-pack sand at lowflow rates across a long horizontal boreholerequires a properly constructed borehole and acarrier fluid that is shear thinning, to minimizepressure loss while placing gravel across thesandface. Engineers determined that to minimize risk, and improve efficiency and production potential, a single-step gravel-packand cleanup completion was required.

Limited reservoir information and a lack ofcore data presented a variety of challenges, fromgravel and screen selection to developing synergistic, nondamaging drilling, gravel-packingand cleanup fluids.

The first challenge was to drill a high-qualityborehole avoiding excessive washouts and deviation since these could interfere with propersand placement during gravel-packing operations.Before drilling could begin, however, a detailedfluid-design program was initiated to select thecorrect reservoir drilling fluid (RDF).

This fluid-design program included a wellbore-stability study to determine zones ofweakness and the mud-weight, fracture-gradientwindow. Sidewall core samples from offset wellswere used to study shale characteristics andresponse to RDF exposure. Formation-damagepotential was also evaluated along with cakequality and liftoff pressure requirements usingstandard laboratory return-permeameter evalua-tion techniques.

Compatibility with completion and cleanup-fluid chemistries was key to the RDF design.Engineers selected components of the drilling-fluid system based on drilling efficiency, wellborestability and susceptibility to enzyme breakersand chelating agents.

Gravel selection was based on extensive offset-well sidewall core studies and laboratorysimulations. Dry-sieve, laser particle-size analysisand scanning electron microscopy techniqueswere combined to estimate the gravel grain sizein the Foinaven T25 sand. These results werethen used to develop a laboratory-analog artificial core-pack material.

Technicians used the artificial core materialfor slurry injection and prepack testing. Slurry-injection tests simulated formation sandmigration into the gravel pack during oil produc-tion. Prepack tests simulated the effects ofborehole collapse that could cause significantamounts of formation sand to migrate onto thegravel-pack face. Based on these test results, a30/50-mesh synthetic proppant was selected asthe best material to effectively control sand production and optimize production efficiency.

Gravel placement across the two horizontalproduction intervals was the next challenge. AVES-base ClearPAC gravel-pack carrier fluid wasselected for its shear-thinning, cleanup and prop-pant-transport characteristics, and its ability toincorporate and deliver filtercake cleanup chemi-cals uniformly across both gravel-packed sections.

The VES fluid allowed engineers to transportand place gravel across both production zones,

20 Oilfield Review

> Low skin with oil-base mud. The use of oil-base drilling fluids, water-basecompletion fluids and greater borehole inclinations produces lower mechanicalskin factors. Shown are theoretical changes in mechanical skin factors (red)from the vertical to horizontal where at about 60° deviation, the geometriceffect begins to dominate skin factors as indicated by the convergence of themechanical skin lines. When properly designed, an oil-base reservoir-drillingfluid followed by a VES gravel-packing fluid in combination with drilling high-angle wells with respect to bedding planes effectively delivers low mechanicalskin factor completions. In field tests, wells drilled with water-base mudsshow higher mechanical skin factors than did those drilled with oil-base muds.Oil-base drilling fluids may also mitigate low-angle skin damage.

10

89

7

56

4

23

1

-10

-2

-4-3

-50 10 20 30 40

Wellbore inclination, degrees50 60 70 80

Tota

l com

plet

ion

skin

fact

or

Water-base drilling fluidOil-base to water-base VES completions

Winter 2004/2005 21

together spanning 937 m [3,074 ft] of open hole.More than 36,300 kg [80,000 lbm] of gravel were placed in the well, covering 100% of theopenhole volume.

During well tests, the P110 well initial oil production rate was 20,500 B/D [3,258 m3/d],about 8,500 B/D [1,351 m3/d] above expectations.The well is currently producing sand free.

Extensive sidewall core analysis and laboratory tests allowed engineers to successfullysize gravel and completion screens. Results fromthese tests also guided RDF and VES transportand cleanup system design. Integrating welldesign, construction and completion processesproduced positive results—successful drillingwith water-base mud (WBM), 100% gravel-packplacement, effective filtercake cleanup, zero skin values, and production rates that wereabove expectations.

When Oil-Base Mud Is RequiredEven though water-base muds have improvedsubstantially since the mid-1980s, engineers andscientists have struggled to design cost-effectiveWBMs capable of emulating the inhibitive quality, lubricity and thermal stability performance of oil-base fluids.

Problematic openhole gravel-pack comple-tions in Azerbaijan led BP to switch fromwater-base RDF to synthetic oil-base mud(SOBM).24 Prior to 2003, six wells had beendrilled using water-base RDF, and then gravel-packed. In reservoir sections drilled with 81⁄2-in. bits, washouts of up to 18 in. [45.7 cm] were observed. Ledges in the irregular hole made borehole cleaning difficult, and ulti-mately resulted in a poor gravel-pack completion(previous page, top).

Working with service providers, BP engineerscarried out extensive laboratory testing todevelop a system of nondamaging RDFs and completion fluids capable of controlling the borehole during drilling and of providing a lowskin factor during completion.25

The reservoir consists of poor to moderatelysorted, fine to very fine-grained sands with amedian diameter of 85 to 200 microns requiring20/40 gravel-pack sand and 12-gauge screens tocontrol sand and fines migration.

Four reservoir sections were drilled withSOBM, ranging from 200 to 650 m [656 to 2,133 ft]thick and spanning two productive sands separated by a 120-m [394-ft] thick reactive shalesection. Reservoir pressure averaged 32 MPa at3,500-m [4,650 psi at 11,483-ft] true vertical depth (TVD).

Engineers drilled each reservoir section with10.5-lbm/gal [1,258-kg/m3] SOBM. As drilling progressed, technicians controlled filtercakequality by maintaining the drilled solids concentration below 2% and performed tests toensure that the RDF would flow through a 10-gauge completion screen, two sizes smallerthan required.

Once the driller completed the reservoir sec-tion, a wiper trip was made using mechanical-and chemical-cleaning systems to remove solidsand debris from the casing. The open hole belowthe casing was displaced with high-viscositywater-base fluid containing calcium carbonatesized to control losses into the reservoir rock, yetstill allowing passage through a 10-gauge wire-wrap completion screen. The cased-holesection was then displaced to completion brine.

To ensure complete gravel packing acrossmultiple zones, engineers recommended anAlternate Path completion. After the sandfacecompletion assembly was run into the hole, thewater-base calcium carbonate fluid was dis-placed with a sequence of completion fluids,optimized for this application through laboratorytesting. A ClearPAC carrier fluid provided adequate gravel transport, minimal friction pressure and good performance with the Alternate Path gravel-packing design.

At a rate of 6 to 7 bbl/min [0.9 to 1.1 m3/min],80 bbl [12.7 m3] of VES carrier fluid were pumped,followed by a 6-ppa (pounds of proppant added),20/40-mesh gravel-packing slurry, a 40-bbl [6.4-m3] VES postpad stage and an appropriatedisplacement volume of filtered brine.

After testing, two of the four wells were sus-pended for later production. However, initialwell-test results showed an average productionindex (PI) of 45, indicating excellent productionpotential.26 The other two wells were put on production after tests indicated skins of +2.2 and+2.4, 30 to 50% less than those seen with previous openhole gravel-pack completions.

Compared with other wells in the area, engineers calculated that 550 to 600 B/D [87 to95 m3/d] of incremental oil production wasachieved using an oil-base RDF followed by completion techniques using ClearPAC gravel-packing fluids.

Here and elsewhere in the world, ClearPACgravel-pack carrier fluids have contributed to thesuccessful outcome of difficult completions.Although sensitive to hydrocarbon contact, properly designed VES gravel-pack completionsystems can improve well productivity even whenapplied in conjunction with oil-base RDFs.

Less Water—More oilVirtually every oil reservoir is swept at least partially by water, from either natural aquiferpressure or waterflooding. Water movement dis-places oil and often determines the oil recoveryefficiency in a field. Although critical to the oil-production process, water production sometimesbecomes excessive.

Even the best field-management techniqueshave a limited ability to control excessiveamounts of produced water. In mature fields,water production may increase to the point thatit represents a majority of the liquid volumereaching the surface. Reports indicate that glob-ally, at least three barrels of water are generatedwith every barrel of oil produced.27 Liquid-handling systems often become overloaded,impacting efficiency and productivity. Eventually,the cost of dealing with produced water precludes field profitability.28

22. Shunt-tube, or Alternate Path technology, is used toensure a complete gravel pack around screens. If theannular space packs off prematurely, the shunt tubesattached on the outside of screens provide conduits forthe gravel-pack slurry, allowing gravel packing to proceedpast any blockage, or bridges, that may form around thescreens. For more on shunt-tube gravel packing: Acock etal, reference 19.

23. Wilson A, Roy A, Twynam A, Shirmboh DN and Sinclair G: “Design, Installation, and Results from theWorld’s Longest Deep-Water Openhole, Shunt-TubeGravel-Pack West of Shetlands,” paper SPE 86458, presented at the SPE International Symposium and Exhibition on Formation Damage Control, Lafayette,Louisiana, USA, February 18–20, 2004.

24. Parlar M, Twynam AJ, Newberry P, Bennett C, Elliott F,Powers B, Hall K, Svoboda C, Rezende J, Rodet V andEdment B, “Gravel Packing Wells Drilled with Oil-BasedFluids: A Critical Review of Current Practices and Recom-mendations for Future Applications,” paper SPE 89815,presented at the SPE Annual Technical Conference andExhibition, Houston, September 26–29, 2004.

25. The skin factor is a numerical value used to define the difference between the pressure drop predicted byDarcy’s law and actual values. Skin factors typically rangebetween negative 6 for stimulated high conductivity, suchas that obtained by hydraulic fracturing, to 100 or more forextreme damage and poor conductivity.

26. The productivity index (PI) is a mathematical means ofexpressing the capacity of a reservoir to produce fluids.PI is usually expressed as the volume of fluid producedat a given drawdown pressure at the reservoir face.

27. Veil JA, Puder M, Elcock D and Redweik R Jr: “A WhitePaper Describing Produced Water from Production ofCrude Oil, Natural Gas, and Coalbed Methane,“http://www.ead.anl.gov/pub/dsp_detail.cfm?PrintVersion=true&PubID=1715 (accessed April 16, 2004).

28. Arnold R, Burnett DB, Elphick J, Feeley TJ III, Galbrun M,Hightower M, Jiang Z, Khan M, Lavery M, Luffey F andVerbeek P: “Managing Water—From Waste to Resource,”Oilfield Review 16, no. 2 (Summer 2004): 26–41.

In late 1999, engineers and scientists atSchlumberger discovered a new application forVES fluids, acid diversion. During standardacidizing treatments, stimulation fluids follow the path of least resistance, preferentiallystimulating zones of higher permeability. Theseare often zones with higher water saturationswhere the relative permeability to water-basestimulation fluids, such as acids, is also higher.Hydrocarbon zones with lower permeabilities arestimulated to a lesser degree. Consequently,water production increases disproportionatelycompared with oil.

Frequently, the permeability contrastbetween water- and oil-bearing zones makesselective stimulation difficult. Earlier divertingtechniques relied on polymers and solids to plughigh-permeability zones. Unfortunately, both low-and high-permeability zones became plugged,doing more harm than good to production rates.

Research led to the development ofOilSEEKER acid diverter, a VES-base system thatcan be engineered for either sandstone or

carbonate reservoirs. In each case, OilSEEKERfluid selectively reduces injectivity in water-ladenzones, forcing the acid to enter zones with high oilsaturation (below).

During the development of OilSEEKER fluids,laboratory tests demonstrated effective diversionwhen the rheology of the diverting fluid isdirectly affected by the chemistry of formationfluids. In the case of OilSEEKER fluids, the aciddiverter maintains a gelled state while in contactwith water, but viscosity degrades when exposedto liquid hydrocarbon. Laboratory core-floodexperiments have shown that VES-base diversiontechniques can effectively divert acid from a20,000-mD sandpack to a 200-mD core used tosimulate a zone with lower permeability. Afterseveral treatment cycles, about 40% of the acidwas injected into the low-permeability core.29

In the Barinas field, located in southwestVenezuela, Petróleos de Venezuela S.A. (PDVSA)produces oil from low-permeability carbonatereservoirs containing a high percentage of sandand shale. High amounts of produced water, or

water-cut, are common, and the wells haveproved difficult to stimulate without increasingthe amount of produced water.

Completed in 1984, Well SMW9 initially produced 116 BOPD [18 m3/d] with 25% basicsediment and water (BS&W). In 1997, a matrixstimulation treatment was performed, increasingoil production to 250 B/D [40 m3/d], but alsoincreasing water production.

PDVSA and Schlumberger engineers evaluated the well in early 2003. At that time, thewell was producing about 51 B/D [8 m3/d] of oilwith a water/oil ratio (WOR) of about 75% (next page, top). As with many high water-cutwells, engineers believed that a reduction inWOR would substantially increase oil production.

The hydrocarbon-productive reservoir interval is a calcareous matrix with hard andcompacted dolomites, streaks of glauconite andhard limestone. Because of this geology, engineers were concerned that the use of common acids, such as hydrochloric acid [HCl],could damage the remaining productive zones.

22 Oilfield Review

Stimulating oil zones. During acid stimulations, OilSEEKER acid diverter (left – yellow) is pumped ahead of the acid solution (red). On contact with water-bearing zones, the diverting fluid increases in viscosity, forming a plug that effectively blocks access to water zones. In contrast, on contact withhydrocarbon-bearing zones, the OilSEEKER diverter thins, allowing the subsequent acidizing step to preferentially treat oil-bearing zones not blocked bythe diverting fluid (right – green oil zone).

Productionline

Production tankInjection line Open

Shale

Shale

Closed

Productionline

Production tankInjection line Open

Shale

Shale

Closed

Water Oil OilSEEKER acid diverter

OilSEEKER Viscosity

Acid

LM

H

VIS

LM

H

VIS

29. Chang FF, Acock AM, Geoghagan A and Huckabee PT:“Experience in Acid Diversion in High Permeability DeepWater Formations Using Visco-Elastic-Surfactant,” paperSPE 68919, presented at the SPE European FormationDamage Conference, The Hague, May 21–22, 2001.

30. For more on viscoelastic surfactant acid diversion: Al-Anzi E, Al-Mutawa M, Al-Habib N, Al-Mumen A, Nasr-El-Din H, Alvarado O, Brady M, Davies S, Fredd C,Fu D, Lungwitz B, Chang F, Huidobro E, Jemmali M,Samuel M and Sandhu D: “Positive Reactions in Carbonate Reservoir Stimulation,” Oilfield Review 15,no. 4 (Winter 2003/2004): 28–45.

Winter 2004/2005 23

Therefore, careful attention was paid to acid-stimulation design.

Schlumberger engineers designed an HCl-free, organic-acid formulation composed offormic and acetic acids. Bottomhole static temperatures were estimated at 270°F [132°C],so engineers selected the high-temperature version of the OilSEEKER fluid to divert the acidtreatment away from water-bearing zones.

In the field, engineers first pumped a solutionof oil and solvents, followed by viscosified brine,to clean up the wellbore. Next, the OilSEEKER

treatment was pumped into the formation, followed by organic acid. This process wasrepeated to assure adequate stimulation acrossthe 30-ft [9.1-m] production zone. The pressureprofile during pumping gave little indication ofexcessive fluid loss, suggesting that the acid wasmost likely being pumped into the oil-bearingzones of lower permeability.

During the first two months following simula-tion, engineers recorded an 253% increase in oilproduction coincident with a 24% decrease inBS&W production (above).

Whether used to simulate wells in new fieldsor in mature areas, selective acid stimulation canimprove well performance. Today, engineers cantreat only the oil-bearing zones by designing fluidtreatments using VES-base diversion, such as theOilSEEKER system.

A New Generation for VES Since their first use more than 20 years ago, VESsurfactants have evolved significantly, findingnew applications and benefits in the E&P indus-try. Today, engineers use VES fluids for hydraulicfracturing, gravel packing, acid diversion and ahost of other applications.30

New VES fluids are continually being devel-oped. One area of interest is polymer-free liquidcarbon dioxide [CO2] fracturing. The future willinclude ClearFRAC products specificallydesigned to stimulate wells in which hydraulicfracturing with liquid CO2 and the inherently lowdamage characteristics of VES fluids will signifi-cantly improve well productivity.

Engineers expect the intrinsically low frictionpressure of CO2 and VES systems to improvethrough-tubing stimulation by allowing higherpump rates at maximum treating pressure, partic-ularly when compared with older polymer-basefracturing systems.

As oil and gas operations reach greater depthsand increasingly treacherous environments, scientists and engineers are working to expandthe performance limits of VES-base systems. Eventhough these materials have been used for aquarter of a century, they continue to promisethe potential for new and exciting developmentsthat will improve operational efficiency andenhance hydrocarbon recovery. —DW> Effective stimulation with OilSEEKER acid diverter. After stimulation, oil production increased by

253% and basic sediment and water (BS&W) declined by 24%, demonstrating the effectiveness ofOilSEEKER acid diversion.

Beforestimulation 190 51 73

Barrels of fluidper day (BFPD)

Barrels of oilper day (BOPD)

Basic sediment andwater, % (BS&W)

BFPD increase, % BOPD increase, %

330 74 8293 72Design

350 49 84 253180Afterstimulation

> Increasing water production. With time, water production from mature wells often increases. ThePDVSA SMW9 well is no exception. By 2003, water represented 75% of the produced fluid from thiswell (purple).

Fluids Production Chart

1997 1998 1999 2000

Year

2001 2002 2003

Flui

d vo

lum

e, %

20

0

40

60

80

100

% water

Total fluids

Total oil