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CONDUCTIVITY HALLIBURTON A Supplement to Keeping it flowing and going The secret to long-term production ENDURANCE and

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Page 1: Conductivity Endurance, Halliburton

CONDUCTIVITY

HALLIBURTONA Supplement to

Keeping it

flowing

and

going

The secret to long-term

production

ENDURANCE

and

Page 2: Conductivity Endurance, Halliburton

CONDUCTIVITY ENDURANCE

TABLE OF CONTENTS3CONDUCTIVITY

ENDURANCE

Sr. Vice President and Chief Financial Officer

KEVIN F. HIGGINS

Executive Vice President FREDERICK L. POTTER

President and Chief Executive Officer

RICHARD A. EICHLER

4545 Post Oak Place, Ste. 210Houston, Texas 77027Tel: (713) 993-9320Fax: (713) 840-0923

__________________

Editors in ChiefLESLIE HAINES, OIL AND GAS INVESTOR

BILL PIKE, E&P

Director of Custom PublishingMONIQUE A. BARBEE

Contributing EditorJOE WOODS

Profile EditorF.JAY SCHEMPF

__________________

Art DirectorALEXA SANDERS

Graphic DesignerLAURA J. WILLIAMS

Production ManagerJO LYNNE POOL

For additional copies of this publication,contact Marcos Alviar at ext. 150.

__________________

PublishersBOB JARVIS, OIL AND GAS INVESTOR

RUSSELL LAAS, E&P

__________________

A custom publication to

and

New Technologies Improve Long-Term ProductionWhen designing hydraulic fracturing projects, operators are plan-ning for uninterrupted reservoir fluid flow, while wanting to achievea high level of conductivity for the present and long term. New tech-nologies can help achieve conductivity endurance through the fol-lowing parameters:

■ increasing the proppant pack conductivity;

■ reducing effects of production cycling;■ maintaining proppant pack permeability;■ immobilizing fines to prevent intrusion and plugging; and■ reducing proppant flowback.The value of increased production from proper application of

these new technologies can be significant.

Propping-up ProductionHydraulic fracturing treatments of oil and gas wells are designed to create highly conductive proppedfractures that yield sustained production increases and control fines migration. New ConductivityEndurance technologies are improving long-term asset performance onshore and offshore.

Case Histories: Building the Case for Conductivity Endurance

Stick to Tacky. It Pays.The use of proppant surface-modification technology enhances well productivity.

Not All Resin-Coated Proppants Are Created EqualCurable resin-coated proppant was introduced to the industry during the 1980s as a means to preventproppant flowback. For a hydraulic fracturing or frac-pack treatment to be effective, resin-coated prop-pants should consolidate under downhole conditions into a long-lasting, high-strength permeable pack.

Company Profile Index

4

16

22

30

38

Page 3: Conductivity Endurance, Halliburton

Propping-up Production

Bob Barree, Barree and Associates, Lakewood, Colo.Harvey Fitzpatrick, Halliburton Energy Services,HoustonJorge Manrique, Knowledge Reservoir, HoustonMike Mullen, Mullen Energy, HoustonSteve Schubarth, Schubarth Inc., HoustonMike Smith, NSI Technologies, Inc., Tulsa, Okla.Neil Stegent, Halliburton Energy Services, Houston

V irtually every oil and gas well drilledtoday at some point in its life willrequire some type of stimulation.

The goal is to increase the flow of hydrocar-bons to the wellbore. Since hydrocarbons are contained in the pore spaces in the for-mation rock, exposing more of the formationto the wellbore often can increase productionof viable reserves, which normally is done by fracturing the producing formation orplacing a reactive fluid (acid) in contact withthe producing formation. In financial terms,the goals of stimulation are to help improvethe net present value (NPV) of the asset,improve the production rate and helpincrease recoverable reserves. This handbookwill focus on new technologies related tohydraulic fracturing and the importance of maximizing fracture conductivity toenhance production.

The Need for Improved Technology“Energy prices are going to face continuedpressure – reflecting fundamental changes indemand, supply and geopolitics. We are, infact, witnessing a change in the basic energyequation. To understand why, we have tounderstand the dynamics of supply anddemand today. Global energy demand willexpand about 40% over the next two decades,driven largely by population growth and rapidindustrialization in the developing world,” saidDavid J. O’Reilly, chairman and chief executiveofficer of ChevronTexaco. 2

To illustrate this point, one only has to looktoward China, whose population grows byabout 8 million people annually. As Chinese

incomes rise, so does car ownership. Car regis-trations in China are expected to jump from20 million to 50 million between 2002 and2007. Chinese crude oil imports increased by30% in 2003, and the country’s energy needswill more than double by 2020.

In the United States, oil demand is expectedto continue rising annually by nearly 2%.Cleaner burning natural gas is projected toincrease by about 25% during the next 15years. With increased demand, ever-increasingpressures are placed on finding new supplies,which means increased imports. More than60% of the crude oil and 15% of the naturalgas the United States uses today is imported.3

Crude oil—For 2003, U.S. imports of crudeoil and petroleum products averaged 12.25million b/d, an estimated increase of 724,000b/d or 6% from 2002. This represented morethan 61% of domestic petroleum demand.Fifteen years ago, by comparison, importscomprised just more than 40% of U.S. needsand constituted a U.S. $39 billion trade valueprice tag (imports only) compared to the cur-rent U.S. $132.5 billion burden. TheOrganization of Petroleum ExportingCountries (OPEC) imports made up 42% ofall U.S. crude imports in 2003, up 2% from2002 but down almost 8% (in percentageterms) from 1993 levels.

In 2003, estimated U.S. crude oil produc-tion (excluding natural gas liquids) averaged5.74 million b/d, compared to 5.75 million b/din 2002, representing a 1.43 million b/d(almost 25%) decrease since 1992. U.S. crudeproduction has fallen for 12 straight years.4

Natural gas—Annual natural gas importsfor 2003 amounted to 3.9 Tcf, almost doubleU.S. natural gas imports in 1992 (2.1 Tcf).Imports of natural gas have been rising fairlysteadily since 1986 – up almost 424%(25%/year annualized) – while U.S. dry pro-duction is up only 19% (or 1.12% annualized)during the same time period.5

Natural gas is a critical source of energy

and raw material, permeating virtually all sec-tors of the U.S. economy. Today, natural gasprovides nearly one-quarter of U.S. energyrequirements6 and is an environmentally supe-rior fuel, contributing significantly to reducedlevels of air pollutants. It provides about 19%of electric power generation and is a clean fuelfor heating and cooking in more than 60 mil-lion U.S. households. Industries in the UnitedStates get more than 40% of all primaryenergy from natural gas. Figure 1 illustratesthe contribution of natural gas to U.S. energyneeds, and Figure 2 shows gas use by sector.

According to a recent National PetroleumCouncil study, the gas bubble is gone. Today,no additional production capacity exists at thewellhead (Figure 3). The requirements to fillstorage during the traditionally slow periodsare now great enough to require wells to beproduced continuously at high rates. Plus, theaverage decline rates (Figure 4) for newer gaswells are steeper than in the past because oftwo key issues: the reservoir quality has beendeclining, and economics require wells be pro-duced at maximum rates to generate the neces-sary revenue.

During the 1990s, environmental standards

Figure 1. 1997-2001 Average U.S. AnnualEnergy Use, 97 Tcf/year (equivalent). (source: Energy Information Administration)

4 CONDUCTIVITY ENDURANCE

Hydraulic fracturing treatments of oil and gas wells are designed to create highly conductive proppedfractures that yield sustained production increases and control fines migration. New ConductivityEndurance technologies are improving long-term asset performance onshore and offshore.

1. S. Schubarth, A. Byrd, J. Wickham: “U.S. Natural Gas Market: Recent Dynamics and FutureConcerns,” SPE 80949, presented at the SPE Production and Operations Symposium, Oklahoma City,OK, March 23-25, 2003.

2. Remarks made at the U.S. Chamber of Commerce CEO Leadership Series in Washington, DC, June23, 2004.

3. Ibid.4. F. Lawrence: “State of the U.S. Oil & Natural Gas Industry,” America’s Independent, July/August 2004,

p. 22-26.5. Ibid.6. Data from Energy Information Administration, Monthly Energy Review, April 2003.

Page 4: Conductivity Endurance, Halliburton

and economic growth were the forces drivingthe demand for natural gas in North America.Historically in the United States, drilling activ-ity has responded quickly to market signalsand, together with increasing supplies fromCanada, has yielded sufficient production tomeet demand. Figure 5 shows U.S. andCanadian production from 1985 to 2002.It now appears that natural gas productivecapacity from accessible basins in the UnitedStates and Western Canada has reached aplateau. Recent experience shows steeperdecline rates in existing production and alower average production response to higherprices from new wells in these areas. Thistrend is expected to continue. As a result, mar-kets for natural gas have tightened to a degreenot seen in recent experience and prices haveincreased well above historic levels. Thesehigher prices have been accompanied by sig-nificant price volatility (Figure 6).

A need exists for higher production rates,both short- and long-term. Oil and gas opera-tors, in close cooperation with industry servicesuppliers, are providing promising new solu-tions. One such initiative involves a family offracturing products and techniques thatHalliburton has designated as “ConductivityEndurance” technologies.

Hydraulic fracturing in low permeability,hard rock formations and fracpacking in high-permeability, soft rock formations have longbeen recognized as effective means to improveproduction. Higher production rates can bemost easily achieved through the use of moreeffective hydraulic fracturing focused on maxi-mizing the effective fracture length and main-taining conductivity. Recent research hasdemonstrated and field results have provedthat Conductivity Endurance fracturing canenhance the outcome of stimulation treat-ments and achieve sustained productionincreases through a combination of factors:

• proper treatment design;• low-damaging fluid systems;• accurate proppant selection; and• coated propping and packing materials.

Fracturing Concepts, Geometry and Rock Mechanics7

By design, fracturing stimulates production.The extreme advantage of fracturing wells to

increase productivity is now largely accepted,but there still is substantial room for growthworldwide through proper application of the

process and use of new conductivityendurance technologies. It is estimated thathydraulic fracturing may add several hundred

CONDUCTIVITY ENDURANCE 5

Figure 2. U.S. Primary Energy Use by Sector, Year 2002. (source: Energy Information Administration)

Figure 3. U.S. Wet Gas Production (Gas Well Gas & Oil Well Gas).1

Figure 4. U.S. Gas Production Decline. (Source: Energy Information Administration)6

7. W.K. Ott and J.D. Woods: Modern Sandface Completion Practices Handbook, Gulf Publishing Co.,September 2003.

8. J. Gidley, S. Holditch, D. Nierode and R. Veatch: “Recent Advances in Hydraulic Fracturing,” SPEMonograph 12, Richardson, Texas, 1989.

9. F. Monus, F. Broussard, J. Ayoub and W. Norman: “Fracturing Unconsolidated Sand FormationsOffshore Gulf of Mexico,” SPE 24844, presented at the SPE Annual Technical Conference andExhibition, Washington, DC, Oct. 4-7, 1992.

Page 5: Conductivity Endurance, Halliburton

thousand barrels per day from existing wells ina number of countries, and worldwide thegains in added production could be millions ofbarrels per day.

A detailed discussion of rock mechanicsand creation of a hydraulic fracture are beyondthe scope of this text. However, certain generalprinciples are assumed to be understood andbelieved valid for most reservoirs:

• fractures are nearly always vertical

(exceptions may be in very shallow wellsand tectonically active areas);

• fractures are oriented perpendicular tothe direction of minimum principlestress (in most formations, this is thedirection toward the maximum horizon-tal stress);

• fracture initiation pressure is normallyhigher than fracture extension pressure;and

• fracture height and length continue toincrease as long as the fluid pressureinside the fracture is larger than the leastin-situ principal stress or until a barrieris reached, or a tip screen out (TSO) orsand out obtained.

Hydraulic fracturing is most commonlydone in strong or hard rock formations thathave permeabilities less than 1 md or 2 md,where a contrast between the proppant andformation permeabilities of 10,000 or more is desirable. Fracture lengths of 500+ ft (152.4+ m) and propped fracture widths of0.2 in. or less are common. This is enough for good initial production results in low permeability formations.

There are many unknowns and disagree-ments on the best means of fracturing strong,low permeability rocks where fracturing hasbeen applied for several decades. For instance,the Society of Petroleum Engineers (SPE)Monograph Vol. 12, Recent Advances inHydraulic Fracturing, published in 1989,8 states“fracture height is a variable that can be onlygrossly estimated with today’s technology.”Today, fracture design technology hasimproved in design software, and acquiringand managing the data needed for a design.

Even though the sophisticated computerprograms used to design, model and evaluatefracture treatments have helped the process,the programs often are based on certainassumptions and questionable input data thataffect the results of fracture geometry. Lengthand height of a fracture are used to calculate itswidth. A fracture is usually assumed to beelliptical, rectangular or “penny shaped,” andboth wings are equal length, height and width.

In low permeability or hard rock forma-tions (1 md to 2 md), viscous fracturing fluidsgenerate long fractures because of low fluid

leakoff while less viscous fluids, such as water,leak off quickly and create shorter fractures(Figure 7). In micro Darcy reservoirs, however,the opposite may be true. If fluid leakoff isminimal, thin fluids can create much longerfractures with very narrow widths. Viscous flu-ids, on the other hand, create wider fracturesand less length. Reservoir permeability andpressure are two important parameters thatneed to be considered in both these situations.In either case, hydraulic fracturing increaseseffective completion radius by establishing lin-ear flow into propped fractures and dominantbilinear flow to a wellbore (Figure 8).

In high permeability or soft rock forma-tions, TSO fracturing treatments are designedto create short, wide propped fractures thatprovide some reservoir stimulation and miti-gate sand production by reducing near-well-bore pressure drop and flow velocity. In lowstrength (soft/unconsolidated sand) forma-tions, proppant concentration after fractureclosure must exceed 2 lb/ sq ft (10 kg/ sq m) toovercome proppant embedment in fracturewalls (Figure 9).

A logical question might be: “How muchconfidence can be given to computer programsfor designing, modeling and evaluating frac-tures?” This question can be answered basedupon knowledge of rock mechanics, linearelastic fracture mechanics, and laboratory andfield based studies published by SPE. The frac-ture geometry (height, length and width) is

6 CONDUCTIVITY ENDURANCE

Figure 5. U.S. Lower-48 and CanadianNatural Gas Production. (source: EnergyInformation Administration)

Figure 6. U.S. Wellhead Gas Price. (source:Energy Information Administration)

Figure 7. Fracture geometry in low permeabil-ity, hard rock formations.

Figure 8. Bilinear flow established by fractur-ing the formation.

10. M.Y. Soliman and J.L. Hunt: “Effect of Fracturing Fluid and its Cleanup on Well Performance,” SPE14514, presented at the Eastern Regional Meeting, Morgantown, WV, Nov. 6-8, 1985.

11. G. Voneiff, B. Robinson and S. Holditch: “The Effects of Unbroken Fracture Fluid on Gas WellPerformance,” SPE 26664, presented at the SPE Annual Technical Conference and Exhibition, Houston,Oct. 3-6, 1993.

12. S. Schubarth, R. Chabaud: “Moxa Arch Frontier Formation Development Success Through IncreasedFracture Conductivity,” SPE 28610, presented at the SPE Annual Technical Conference and Exhibition,New Orleans, Sept. 26-28, 1994.

13. S. Schubarth, R. Chabaud, G. Penny: “Moxa Arch Frontier Formation Development Success ThroughIncreased Fracture Conductivity – Part 2,” SPE 30717, presented at the SPE Annual TechnicalConference and Exhibition, Dallas, Oct. 23-25, 1995.

Figure 9. Proppant pack and embedment infracture wall of high permeability formations.

Page 6: Conductivity Endurance, Halliburton

uncertain if the rock or soil mechanical prop-erties are uncertain. On the other hand, thefracture geometry can be predicted by softwareif the rock mechanical properties are known.The rock and soil mechanical properties meas-ured or calculated in the laboratory for frac-ture designs are as follows:

• Young’s modulus (for fracture length,width and pressures; also can controlheight growth);

• Poisson’s ratio (for fracture height andformation stress determination);

• fracture toughness (for fracture heightand length, also fundamentally affectswidth);

• minimum principal horizontal stress vs.depth (for fracture height and pressure);

• proppant embedment (for fracturewidth and fracture conductivity);

• leakoff coefficients (for fluid leakoff intoformation); and

• Biot’s poroelastic coefficient (for forma-tion stress determination, height con-tainment and width).

If all or most of the above properties are known, successful fracture treatments are expected.

Designing an optimal fracturing treatmentrequires data. Most of the information is read-ily available or can be obtained at reasonableexpense. For example, previous fracture treat-ments in the same zone can yield valuableinformation for future treatments. Collecting,storing and applying all available data will pro-vide answers for the best possible treatment.The completion engineer must determine spe-cific data related to each of the following:

• reservoir information;• fracture width;• fracture length;• fracture height;• fracture initiation and propagation

points; and• frac fluids and proppants.

Reservoir information—The geology ofthe play has a major effect on fracture design.Faults, unconformities, natural fractures and other geological features will impact thetreatment. In designing the optimum fractreatment, the completion engineer needs togather the following information related to thetarget reservoir.

Permeability, porosity and bottomholepressure—Perhaps the most important infor-mation needed is the reservoir permeability.A high permeability well might be designedwith a TSO treatment to give greater fracwidth, whereas a low permeability well wouldneed a longer frac length for increased reser-voir exposure. Permeability can be obtainedfrom pressure build-up (PBU) tests, nodalanalysis matches (production decline analysis)and core measurements. Reservoir porositycan be obtained from log measurementsand/or core sample analysis. Current and orig-inal reservoir pressure can be obtained fromdirect measurement after perforating or meas-ured from PBU analysis.

Temperature, saturation and geology—Bottomhole temperature and informationabout the production fluids (oil, gas andwater) and their saturations can be obtainedfrom log and/or core data. The geology of theplay will yield the drainage area, pressure tran-

sitions and information about other potentialtectonic parameters.

Reservoir fluid properties—The reservoir-wetting phase (oil or water wet) can be deter-mined from core analysis or inferred from pro-duction in the same reservoir. The gas gravityand percentage of impurities such as carbondioxide, nitrogen and hydrogen sulfide can beobtained from a reservoir sample sent to a fluidlab for analysis. Oil gravity, viscosity and solu-tion-gas content can be determined from labmeasurement of formation fluid samples. Theproduction yield can be measured or estimatedfrom other known reservoirs in the area. Thisinformation is essential to ensure the properuse of compatible frac fluid systems.

Rock properties—A lithology log, usually agamma ray or SP, is critical to identifying theformation layering, such as sand, silt, or shale,among others. Young’s modulus and Poisson’sRatio of the rock can be determined from lab-oratory measurements of core samples.Modulus also can be obtained from a cali-brated dipole sonic log. Sieve analysis of coresamples from the producing interval will yielddata about possible fines movement, especiallyin soft formations. Rock “hardness” (or“applied toughness”) controls pressurerequired for fracture propagation. This is acomplex variable that must be measured froma pretreatment field test or minifrac.

Laboratory testing and history matching of previous treatments provide insight intostress profiles and the performance of treat-ment fluids, but in-situ formation propertiesvary significantly. After developing preliminarystimulation designs, engineers perform a

CONDUCTIVITY ENDURANCE 7

14. S.K. Schubarth, R.R. Yeager and D.W. Murphy: “Advanced Fracturing and Reservoir DescriptionTechnique Improves Economics in Utah, Green River Formation Oil Project,” SPE 39777, presentedat the SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas, March 23-26, 1998.

15. S. Neghaban, L.K. Britt, T.H. Phenicie and K.G. Nolte, K.G: “The Effect of Yield Stress on FractureFluid Cleanup: Inclusion of Gravity Effects,” SPE 49038 presented at the SPE Annual TechnicalConference and Exhibition, New Orleans, Sept. 27-30, 1998.

16. R. Dusterhoft, P. Nguyen and M. Conway: “Maximizing Effective Proppant Permeability under High-Stress, High Gas-Rate Conditions,” SPE 90398, presented at the SPE Annual Technical Conference andExhibition, Houston, Sept. 26–29, 2004.

17. S. Schubarth, R. Yeager and D. Murphy: “Advanced Fracturing and Reservoir Description TechniqueImproves Economics in Utah, Green River Formation Oil Project,” SPE 39777, presented at the SPEPermian Basin Oil and Gas Recovery Conference, Midland, Texas, March 23-26, 1998.

Figure 10. Diagnostic fracture inject test analysis shows normal leakoff (left) indicating a normal frac design is appropriate. The plot on the rightshows pressure dependent leakoff indicating the fracture treatment should be redesigned to control leakoff.

Page 7: Conductivity Endurance, Halliburton

pretreatment evaluation, orminifrac, to quantify five criticalparameters: fracture-propagationpressure; fracture-closure pressure;fracture geometry; fluid efficiency;and leakoff mechanism.9

This procedure consists of twotests – stress and calibration – per-formed prior to the main treatmentto determine specific reservoir prop-erties and establish the performancecharacteristics of actual treatmentfluids in the pay zone. A stress, orclosure, test determines minimum in-situ rockstress, which is a critical reference pressure fortreatment analysis and proppant selection.

The type of test performed depends on therock type or hardness and the data needed. Astep-rate injection test is used to determine theminimum injection rate necessary to extend afracture and is usually conducted with theactual frac fluid. Step-rate tests are only ofpractical value in high permeability reservoirswhere injection below frac rate is physicallypossible. A flow-back test only provides an esti-mate of closure pressure.

For low permeability reservoirs, a flow backtest is a convenient method to estimate closurepressure; however, these tests provide no infor-mation about leakoff or efficiency. Flow backtests are usually done when leakoff is too slowto observe closure in a reasonable amount oftime. A diagnostic fracture injection test(DFIT) is conducted with low viscosity, non-damaging fluids to determine closure pressure,leakoff mechanism, some inference of fracturegeometry and reservoir permeability as well aspore pressure (Figure 10).

A calibration test involves injecting actualfracturing fluid without proppant at the designtreatment rate to determine formation-specificfluid efficiency and fluid-loss coefficients.Fracture-height growth can be estimated by tag-ging proppants or fluid with radioactive tracersand running a post-treatment gamma ray log. Apressure decline analysis confirms rock proper-ties and provides data on fluid loss and efficiency.

Surface data from pretreatment tests com-bined with bottomhole injection pressures arehistory-matched using a computer simulatorto calibrate the fracturing model and finalizetreatment design. Calibrated data from com-puter analysis also are used to assess

stimulation effectiveness during post-treatment evaluations.

During the initial design of a fracturingtreatment, completion engineers determine the required fracture geometry based on reservoir conditions, rock properties and barriers to fracture height growth. Fracturelength and, more importantly for high-permeability formations, fracture widthenhance well productivity.

Fracture initiation and propagation—Fracture initiation and propagation in soft andhard rock are affected by these properties:

• in-situ stresses;• stratification;• rock strength and properties, such as elas-

tic modulus, Poisson’s ratio, toughnessand ductility;

• fluid, pressure and permeability profile inthe fracture; and

• pore pressures.The permeability profile and rock strength

of most weak, high permeability formationsvary more than in high strength, low perme-ability formations. For instance, the permeabil-ities of weak sandstone commonly vary fromnear zero in shale and clay strata to higher thanone Darcy; whereas, the permeabilities ofstrong sandstone commonly range from nearzero to only 5 md or 10 md. Similarly, weaksandstone formations that are candidates forfracpack treatments often have strata or pock-ets of strong sandstone, shales or carbonates.Strengths may range from nearly zero to manythousands of pounds per square inch uncon-fined compressive strength.

Fracture orientation in weak formations isthe same as in stronger formations. The staticstress fields that force them to always be perpen-dicular to the minimum principal stress dictate

the direction of all fractures, whichmeans that the fracture is usually inthe same direction as, and parallel to,the maximum horizontal stress.

Focusing on Fracture ConductivityThe importance of fracture conduc-tivity and its effects on well produc-tivity are widely understood in thepetroleum industry.10,11,12,13

Laboratory testing procedures arewell documented, and sophisticated

modeling software and databases are availableto help engineers optimize fracture treatmentdesigns in terms of fracture geometry, andproppant concentration and type. In spite ofthe availability of advanced design tools andreams of conductivity test data, post-treatmentperformance in many wells seems to suggestthe effective fracture length may be shorterthan expected. The shorter fracture lengthsmay be the result of fluid cleanup issues or lossof fracture conductivity because of fluidresidue such as filter cake. Effective fracturelength can be affected by broken fluid proper-ties and the conductivity in the fracture.14, 15, 16

Increased fracture conductivity—The impactof increased fracture conductivity in lower per-meability reservoirs may be argued; however,improved fracture cleanup and longer effectivefractures should be a direct result of theincreased fracture conductivity. In the simplestform, the effective fracture length can be esti-mated using the following equation:

Cr = wKf/ (πX

eff K)

Where: Cr = Conductivity ratio (dimensionless)wK

f= Fracture conductivity (md ft)

K = Reservoir permeability (md)X

eff= Effective fracture length (ft)

Solving the above equation for the effectivelength and setting the value of the conductivityratio to 10 can approximate the effectivelength. This process defines the infinite con-ductivity fracture length, which provides a rea-sonable estimate of effective fracture lengthwhen fracture cleanup is taken into account. Inthis case, the effective fracture length is definedas the length of the created fracture that actu-ally cleans up and contributes to production(Figure 11).

8 CONDUCTIVITY ENDURANCE

18. S. Neghaban, L. Britt, T. Phenicie and K. Nolte: “The Effect of Yield Stress on Fracture Fluid Cleanup:Inclusion of Gravity Effects,” SPE 49038, presented at the SPE Annual Technical Conference andExhibition, New Orleans, Sept. 27-30, 1998.

19. J. Sherman and S. Holditch: “Effect of Injected Fracture Fluids and Operating Procedures onUltimate Gas Recovery,” SPE 21496, presented at the Gas Technology Symposium, Houston, Jan. 23-25, 1991.

Figure 11. Effective fracture length.

Page 8: Conductivity Endurance, Halliburton

Based upon the previous information, onewould expect to see improved early flush pro-duction as a direct result of higher fracture con-ductivity, and improved long-term productivityand a slower production-decline curve resultingfrom improved reservoir access caused byincreased effective fracture length. This expecta-tion differs from conventional fracture designtheory that suggests the drainage radius is con-stant and increasing effective fracture lengthwould result in higher production rates andmore rapid pressure declines. In other words,the effective drainage radius, for example, in alow-permeability gas reservoir may not be lim-ited by physical boundaries, but is actually afunction of the effective fracture length.Increasing the effective fracture length actuallyimproves reservoir exposure, resulting in ahigher effective-drainage radius. This mecha-nism achieves the combination of higher pro-duction rates and flatter production profilesthat are often seen when longer effective frac-tures are obtained.

Many operators believe that given sufficienttime, fracture cleanup will occur and greatereffective fracture lengths will be obtained.17,18 Inpractice, results have been more rapid produc-tion declines than predicted, with consequentlower ultimate recoveries. Many concepts havebeen put forth to address some of these issues,including the effects of non-Darcy flow in gaswells, multi-phase flow conditions and yieldstrength of broken fracturing fluids.19

Recent testing performed through a largeindustry consortium20 was begun to evaluatefracture conductivity performancemore rigorously under high gas flow-rate conditions. This testing has helpedprovide valuable insight into non-Darcy flow effects, but also has shownsome additional potential sources forfracture conductivity loss under high-stress and high-gas flow-rate condi-tions. Specifically, the mechanical fail-ure of the high-strength core materialused in the conductivity testing equip-ment and the subsequent penetrationof formation material into the prop-pant pack caused significant damage tothe proppant pack. This damagebecame even more pronounced underhigh flow-rate conditions.

Results of the rigorous conductivity testingindicate there is significant benefit gainedthrough the use of surface-modificationagents (SMA) (Halliburton’s proprietarySandWedge® agents) and liquid resin systems(LRS) (Halliburton’s proprietary Expedite®service) added to the surface of the proppant(a process involving on-the-fly, direct coatingof proppant just before it is blended with thecarrier fluid). Previous work suggested thesetechniques could sharply reduce the potentialdamage associated with formation materialentering the proppant pack.21,22 In the mostcurrent study, a test series was conducted toevaluate the effects of using liquid coatings onproppant under extreme conductivity testingconditions. Field results were analyzed to helpsupport the data obtained from coating of

SMA or LRS on proppant.Data from this study strongly suggest mul-

tiple factors impact the conductivity perform-ance of the proppant pack:23

• for uncoated proppant, a negativeimpact on fracture conductivity appearsto be related to the high point loading ofthe proppant at the interface. The mag-nitude of this loading appears to behighly dependent upon the mechanicalproperties of the formation material.This aspect is currently being evaluatedmuch more closely;

• applying the SandWedge (SMA) coatingor the Expedite (LRS) material to proppant results in a proppant pack of higher porosity, providing increasedconductivity and pack permeability

over a wide range of stresses (Figure12) until the proppant strength isexceeded and the proppant begins tocrush. This high-porosity pack mayresult in a slight weakening of theproppant pack as opposed to a moretightly packed system;• SMA and LRS materials on theproppant minimize the loss of conduc-tivity associated with the formationmechanical properties by stabilizingthe formation surface at the interface;• under high stresses, the primarydamage mechanism to uncoated prop-pant appears to be intrusion of forma-tion material into the proppant pack.This invasion occurs after the forma-

CONDUCTIVITY ENDURANCE 9

Figure 12. Conductivity vs. closure stress for 20/40 bauxite, 20/40 bauxite plus 2% SMA, and20/40 bauxite plus LRC at 250°F and 2,000psi, 4,000psi, 6,000psi, 10,000psi and 12,000psi.

Figure 13. Untreated proppant pack (left) shows significant intru-sion of formation material resulting in clogged pore throats andreduced flow area. Proppant pack (right) treated with SandWedgeenhancer shows virtually no intrusion of formation material andopen pore throats.

20. “Report on the Investigation of the Effects of Fracturing Fluids upon the Conductivity of Proppants,Proppant Flowback, and Leakoff,” final report, 2003 Stim-Lab, Inc., Completions Technology Consortia,Proppant Consortium. Presented to members of the Stim-Lab Consortia at Mesa, Ariz., Feb. 26-27, 2004.

21. M. Blauch, J. Weaver, M. Parker, B. Todd and M. Glover: “New Insights into Proppant-Pack Damagedue to Infiltration of Formation Fines,” SPE 56833, presented at the SPE Annual Technical Conference

and Exhibition, Houston, Oct. 3-6, 1999.22. S. Schubarth, L. Bazan, J. Bechel, A. Wagner, J. Manrique: “Increasing Well Productivity in the Wilcox

Lobo Trend,” SPE 75677, presented at the SPE Gas Technology Symposium, Calgary, Alberta, Canada,April 30-May 2, 2002.

Page 9: Conductivity Endurance, Halliburton

tion has undergone a significant degreeof failure at the interface (Figure 13);and

• under high-stress conditions, the pri-mary damage mechanism for the SMAand LRS coated proppants appears to beproppant crushing in the center of thepack. The stabilized formation interfaceapparently reduces the formation intru-sion so stresses are transmitted moredirectly to the individual proppantgrains and contact points (see page 22,“Stick to Tacky. It Pays”).

Conductivity and the Fluids Factor 24,25,26,27,28

The relationship between fracture conductiv-ity damage and rheological propertiesrequired to accomplish fracture stimulationseems to be inversely related. Many incremen-tal technology advances aimed at providing“cleaner” carrier or fracturing fluids have beenimplemented, but with each improvement, asacrifice in fluid rheology and fluid loss con-trol also has occurred to a point where tradi-tional fluids are so weak that fracturing treat-ments often end prematurely.

Innovative application of chemistry haspermitted the development of a new fracturingfluid system as robust as the high concentra-tion guar fluids of the early 1980s but withfracture conductivity properties expected ofthe polymer-free fluids.

Inherent problems of traditional polymer-based and surfactant-based fluid systems—

Because of their low cost and highly control-lable fluid rheology, water-based polymers,guar and derivatized guar have been the main-stay fracturing fluids for many years.Unfortunately, these materials can damagefracture conductivity leading to poorer-than-expected production after fracture stimulation.Steps taken to help reduce conductivity dam-age caused by these fluids include:

• application of special purification chemical processes;

• improving polymer breakers;• formulating fluids with less polymer;

and • improved fluid recovery during well

flowback after treatment.Each of these steps has incrementally

improved conductivity; however, one-half ormore of the native conductivity can be lost tofracturing fluid damage because of using guar-based polymers.

Another approach to reducing conductivitydamage is the recent application of surfactant-based, polymer-free viscoelastic fracturing flu-ids. This technology has demonstrated thevalue of non-conductivity damaging fluids bygenerating high well productivity with smallfracture stimulation treatments. The downsideis that these non-damaging fluids have limitedapplication because of high fluid loss and con-sequent inability to generate extended fracturesat a reasonable cost. What this implies is thatan optimum fluid system must be able totransport proppant, extend fracture length andcontain no more polymer than absolutely nec-

essary to perform these functions. Then, thefluid must break cleanly and flow back fromthe fracture. New polymer technology isenabling such fluids.

Until recently, throughout the industry,most fracturing fluid systems are designed andpriced with the primary focus on polymerconcentration (lb/Mgal). This standard wasestablished years ago because the polymer con-centration was the primary means of modify-ing fluid performance and the resulting valueto the operator.

Now, with advanced chemical knowledgeand new technologies, polymer concentrationis not always the primary component thatdrives fluid performance and value.Consequently, Halliburton is taking the lead inintroducing a performance-based approach tofracturing fluid systems: the “vis” system. Thisapproach enables the optimization of fluidperformance rather than being limited by thequantities of various fluid components.

Vis-based fluid systems—Under this newsystem, fluid performance and price are bench-marked on the base gel viscosity, which corre-sponds to required downhole performancerather than the polymer concentration.

Historically, a measured quantity of liquidgel concentrate was blended into the base fluidand the base fluid viscosity checked to deter-mine whether the correct fluid blend was beingprepared. The vis-based fluids are prepared inthe same way. Under this new approach, how-ever, fluid performance based on reservoir con-ditions, regardless of polymer loading, is nowthe reference point. The result: no more poly-mer than is needed is introduced into the frac-ture resulting in improved cleanup andenhanced conductivity.

Halliburton’s extended complement ofvis-based, performance-focused fracturingfluids (Table 1) represents a step-changeimprovement in fracturing fluid technology.These fluid systems offer the most desirablequalities of both polymer-based and surfac-tant-based systems.

All fluid systems are integrated intoadvanced stimulation software to enable tai-lored treatment designs. Temperature predic-tion and analysis models are programmed intoproprietary 3-D model or pseudo 3-D model

10 CONDUCTIVITY ENDURANCE

Figure 14. American Petroleum Institute conductivity tests demonstrated the effectiveness of SandWedge®

agent in controlling fines intrusion into the proppant pack. Test conditions included 20/40 US-mesh prop-pant, 180ºF, and 4000-psi closure stress. The test sample (a and c) did not have SandWedge agentapplied to the proppant. The effluent from the test is loaded with fines that intruded into the proppantpack. Note in the sample treated with SandWedge agent (b and d) that the interfacial areas are clearlydefined and the effluent is clear. Essentially no formation material intruded into the pack.

a.

b.

c. d.

23. R. Dusterhoft, P. Nguyen and M. Conway: “Maximizing Effective Proppant Permeability under High-Stress, High Gas-Rate Conditions,” SPE 90398, presented at the SPE Annual Technical Conference andExhibition, Houston, Sept. 26–29, 2004.

24. G. Penny: “An Evaluation of the Effects of Environmental Conditions and Fracturing Fluids Uponthe Long-Term Conductivity of Proppants,” SPE 16900, presented at the SPE Annual TechnicalConference and Exhibition, Dallas, Sept. 27-30, 1987.

25. M. Parker and B. McDaniel: “Fracturing Treatment Design Improved by ConductivityMeasurements Under In-Situ Conditions,” SPE 16901, presented at the SPE Annual TechnicalConference and Exhibition, Dallas, Sept. 27-30, 1987.

26. J. McGowen and S. Vitthal: “Fracturing-Fluid Leakoff under Dynamic Conditions Part 1:Development of a Realistic Laboratory Testing Procedure,” SPE 36492, presented at the SPE AnnualTechnical Conference and Exhibition, Denver, Oct. 6-9, 1996.

Page 10: Conductivity Endurance, Halliburton

software. This service helps achieve an opti-mum viscosity profile so proppant can beplaced properly to maximize the initial produc-tion rate and sustain long-term production.

New Conductivity EnduranceProducts/ServicesThe quality of available reservoirs is decreasingand the nature in which wells are producedtoday is more aggressive than in years past.

This results in increased damage to fractureconductivity, which reduces flow rates. Earlierfindings now confirmed by an independentresearch facility, coupled with recently com-pleted studies of long-term production resultshave demonstrated that along with reservoirdepletion, two additional factors accelerateproduction decline following propped stimula-tion treatments – invasion of crushed forma-tion grains into the proppant pack and loss offracture width because of proppant embed-ment and flowback.

The findings and studies also conclude thatdesigning treatments and choosing proppingmaterial based on enhanced reservoir under-standing along with applying the appropriatecoating to the propping agents used in thestimulation treatments can mitigate these neg-ative effects. To this end, Halliburton has intro-duced proprietary Conductivity EnduranceTechnologies based on a family of new prop-pant enhancers and complementary fracturingfluid products.

While no one can affect reservoir quality,these new technologies address getting moreconductivity from the proppant placed, allow-ing for increased flow – at first production andthroughout the well’s productive lifetime.Additionally, during periods of restricted orlimited proppant availability, Halliburton’s newproppant coating systems, SandWedge®

enhancer and Expedite™ agent (Table 2), canachieve the conductivity needed but use up to30% less proppant. These agents are changingthe manner in which the industry approachesfracture stimulation in high perm (soft rock)and low perm (hard rock) reservoirs.

The SandWedge® conductivity enhancementsystem attacks two significant problems thatresult in fracture conductivity loss: formationfine intrusion into the proppant pack and prop-pant pack damage resulting from productionstress cycling. The unique characteristics of theSandWedge® agent reduce or eliminate intrusionof formation material into the proppant packand stabilize the proppant pack, which increasesits resistance to stress cycling damage that canoccur when wells are shut-in for service.

The system works by chemically modifyingthe surface of the proppant grains to enhancefracture conductivity resulting from treatmentsusing water-based fluids. The coating processallows the system to be used on any available

proppant, and it is compatible with allHalliburton water-based fracturing fluids. Also,since this coating is performed in real time atthe well site, only the material pumped intothe well is coated.

In addition, the SandWedge® OS enhanceris specially designed to allow overboard dis-charge in the Gulf of Mexico. It conforms to all overboard oil and grease limits set by theU.S. Minerals Management Service and can be used in coalbed methane wells and otherenvironmentally sensitive land areas.

In reservoirs of 60˚F to 550˚F (16˚C to288˚C) where controlling proppant flowback isa primary concern, Expedite service canimprove proppant flowback control, enhanceconductivity and reduce time to production,thereby helping to improve the NPV of frac-turing treatments. Expedite service providesthe highest compressive strength available,which is critical to effectively controlling prop-pant flowback and allowing operators to opti-mally produce their wells.

Widely used (precoated) resin-coated prop-pants often cannot provide the necessary com-pressive strength because high closure stress isrequired to provide good grain-to-grain con-tact prior to resin curing. This requirement canlead to proppant flowback, since in many for-mations the fracture may not close sufficientlyduring the first 24 hours after treatments.However, even with no closure stress, proppantcoated using Expedite service can provide highstrength, consolidated proppant packs. Thesepacks can reduce proppant flowback under themost severe conditions and sustain exception-ally high production rates.

Higher production rates can be most easilyachieved through the use of more effectivehydraulic fracturing focused on maximizingthe effective fracture length and maintainingconductivity. Conductivity Endurance fractur-ing can enhance the outcome of stimulationtreatments and achieve sustained productionincreases through a combination of:

• proper treatment design;• low-damaging fluid systems;• accurate proppant selection; and• coated propping and packing materials.

As in the past, advances in hydraulic fracturing technology will continue to play a major role in increasing production of vitalhydrocarbon reserves. ■

CONDUCTIVITY ENDURANCE 11

Table 1. Performance-based frac fluid systems.

Table 2. Conductivity Endurance agents forproppant coating.

Performance-Based Fracturing

Fluid Systems

Bottomhole StaticTemperatureRating (˚F)

SilverStimSM LT 80 – 180

SilverStimSM 175 – 300

SeaQuestSM 300

SiroccoSM 400

Delta Frac® 140-R 140

Delta Frac® 200-R 200

Delta R Foam Frac™ 140

Hybor™ 100 – 320

Water Frac™ G-R 70 – 200

ConductivityEndurance Proppant

Coating Systems

PrimaryApplication

SandWedge® NT Conductivity

enhancement in BHTs80˚F to 350˚F

SandWedge® OS

Same as SandWedgeNT except OS meetsoverboard discharge

requirements forGOM. Also applica-

ble for environmentallysensitive land applica-

tions such as CBM.

SandWedge® XS

Same as NT but provides a small

amount of proppantflowback control.

Arctic SandWedge® Applicable to -20˚Fsurface temperature

Expedite™

Proppant flowback control and conductivity

enhancement – 60˚Fto 550˚F. 400˚F to

550˚F range is mainlyfor geothermal wells.

27. G. Voneiff, B. Robinson and S. Holditch: “The Effects of Unbroken Fracture Fluid on Gas WellPerformance,” SPE 26664, presented at the SPE Annual Technical Conference and Exhibition, Houston,Oct. 3-6, 1993.

28. C. Shuchart, et al.: “Novel Oxidizing Breaker for High-Temperature Fracturing,” SPE 37228, presentedat the SPE International Symposium on Oilfield Chemistry, Houston, Feb. 18-21, 1997.

Page 11: Conductivity Endurance, Halliburton

The stimulation industry is reconsidering the true nature of fracture conductivity technology – and how itcan improve and maintain that technology.

Implied vs. Applied Fracture Conductivity

W ith the invention and implemen-tation of the modern computer,hydraulic fracturing designs have

taken a quantum leap forward over the handdesigns and field knowledge used for fractur-ing treatments in the past.

Today, all service companies and manyoperators are equipped with hydraulic fracturemodeling and reservoir simulation softwarethat allows engineers to customize all aspectsof the treatment from fracturing fluids to flow-back and production rates. In this same age ofmodernization, unfortunately fewer improve-ments in fracture conductivity technology havetaken place, leaving the industry with littleenhanced understanding.

In 2003, about 6.1 billion lb of proppant –ceramic, resin-coated and raw sand – wereinjected into formations worldwide. The prop-pant is the only thing that should be left in theformation after the treatment and is the mostimportant feature in achieving and maintain-ing a profitable completion. With this in mind,the stimulation industry is rethinking whatfracture conductivity really is and what it cando to improve and maintain it.

Flow capacityWhen designing fracturing treatments, engi-neers select a proppant type based upon sev-eral key criteria such as closure stress, fractureconductivity requirements, whether theyrequire flowback control and cost. These num-bers typically are available within the fractur-ing software programs or on proppant suppli-ers’ Web sites. It is apparent to most engineersthat as closure stress goes up, stronger materi-als are required; and as formation permeabilityincreases, greater conductivity is required. Thisoften is not as readily apparent as the need forflowback control, or it often is not realizeduntil too late.

Closure stress (applied by the formation) isa fairly simple calculation based upon severalwell-known equations and is one valuablepoint in determining the criteria to be placedon the proppant for the chosen treatment. Asclosure pressures increase, the ability of theproppant to maintain fracture conductivity isreduced. This number (fracture conductivity)

is important to the operator because itdescribes the flow capacity that will be left inthe formation after the treatment to improveproduction rates.

In a nutshell, fracture conductivity is theproduct of proppant permeability and frac-ture width. It is the ability of the fracture toconduct fluid to the wellbore that increasesproduction rates as well as profitability.Fracture conductivity of most proppants ismeasured in third-party laboratories andreported by proppant manufacturers ingraphical and tabular form. An engineer whodesigns a fracturing treatment must realizethat even though the numbers are generatedby side-by-side standard laboratory testingprocedures, the “implied” fracture conductiv-ity numbers reported are not what is really“applied” to the formation.

Implied vs. applied fracture conductivityIn all wells, reservoir characteristics andparameters vary significantly throughout theproduction cycle. For example, closure stresson the proppant is at a minimum at thebeginning of production and increases to a

maximum when reservoir pressure isdepleted. Multi-phased fluid flow usually doesnot begin to occur in most wells until signifi-cant drawdown pressure is applied or reser-voir depletion begins to occur. Over the well’sproduction cycle, repeatedly opening andshutting-in the well subjects the proppant toan incredible amount of cyclic stress.These pressures can cause pack rearrange-ment, near-wellbore fracture width loss andcan also increase embedment and fines generation (Figures 1 and 2). For these reasons, engineers must understand and analyze additional factors that affect the overall applied fracture conductivity prior to selecting the necessary proppant.

As reservoir changes begin to occur, oneitem that should be maximized is fracture conductivity. The basic premise for improvingthe ability to drain the reservoir efficiently is to provide a conduit for the hydrocarbons toreach the wellbore. Any change in the capacityof this conduit can impede or reduce theseresults. Therefore, when selecting the correctproppant, engineers should take care to understand how issues like quality assurance,storage and handling, slurry pump time, fines

Figure 1. Failed proppant grains after cyclic stress testing.

12 COMPANY PROFILE

BORDEN CHEMICAL INC.

Page 12: Conductivity Endurance, Halliburton

migration and flowback control of the prop-pant can impact applied fracture conductivity.

Quality assurance—To generate sufficientquantities of proppant to meet today’s globaldemand, proppant suppliers are required tomass-produce large volumes in short periodsof time. The production runs require compli-cated procedures that, though standard anddocumented, still raise opportunities for error.It then becomes necessary to create a qualityassurance process to ensure the proppantdesigned for the customer is the one deliveredto the wellsite. It is important to know howeach manufacturer accomplishes and tracksquality assurance/quality control to ensure aquality product.

Storage and handling—Most operators andservice companies neglect or take this forgranted when using proppants. Improper stor-age or handling of proppants can generate“dust” within the proppant load. This dust isthen transported into the fracture along withthe proppant and reduces the ever-importantfracture conductivity. Resin-coated proppants,especially curable (bondable) products, can besignificantly affected by temperature and han-dling. Some of the curable resin-coated prod-ucts can lose bond strength by partially curingin the bulk bags or storage containers. This loss of strength results from prolonged expo-sure to excessive temperature while beingstored and/or shipped in bags. Excessive use of pneumatic transfer also can degrade any proppant because of the transfer of fines generated during the process.

Slurry pump times—Along with the effectsof storage and handling, a portion of thebonding capability of the curable resin coatingon proppants can be lost while being injectedinto higher temperature formations. As pumptimes are extended and formation tempera-tures increase, part of or sometimes the entirecurable portion of the resin can be reacted.This reduces bond strength or the conversionof a curable product into a precured one.The loss of bond strength often can be the difference between fracture conductivity and proppant flowback.

Proppant flowback control—The ability ofthe proppant pack to maintain fracture con-ductivity throughout the well’s productive life-cycle is directly related to the ability of theproppant to “stay” in place during production.Proppant flowback can dramatically affect theoverall efficiency of the propped fracture todrain the reservoir. In some instances, it can

cause a choke point, reducing efficiency.Proppant flowback also can damage tubularsand surface equipment, resulting in costlydowntime and replacement.

Applied fracture conductivityDuring the past 20 years, the OilfieldTechnology Group of Borden Chemical Inc.has led the fracturing proppant industry withtechnology that not only can be easily appliedto the well, but also stands up to pre- and post-treatment testing. The company is committedto providing the customer with products thatmeet or exceed required specifications. In itseffort to maximize product performance,Borden has established a number of internalspecifications that exceed those the industryhas put in place. To illustrate this commitment,the company has introduced two new develop-ments to the industry that not only willincrease stimulation rate of interest, but alsowill confirm what Borden says and what itprovides are the same things.

XRT Stimulation Technology is a newplatform of products, applications and sup-porting research focused on significantlyimproving applied fracture conductivity.WebQC is Borden’s online, real-time prop-pant management and quality control assur-ance Web site. From it, Borden provides oper-ators and service company personnel withinformation on individual orders specific to

that customer; or, customers can review theoverall performance of their orders to docu-ment trends. This Web site also will allow cus-tomers to see when their order was shipped,who is transporting it and the quality controltest results. By placing this information on theWeb site, Borden is ensuring the productshipped is within specifications and meetsquality control assurances.

By launching these two developments,Borden is delivering fracture conductivity thatcan be applied to the stimulation industry. ▲

13

Figure 2. XRT proppant grains after identical cyclic stress testing.

FOCUSED ON PRODUCTION WITHQUALITY YOU CAN TRUST

Oilfield Technology GroupBorden Chemical Inc.

15115 Park Row Drive, Suite 160Houston, TX 77084Tel: (713) 646-2800Fax: (713) 646-2898

Web site: www.bordenchem-oilfield.com

Page 13: Conductivity Endurance, Halliburton

Saint-Gobain Proppants concentrates on strength and innovation to deliver higher conductivity and valueto the hydraulic fracturing industry.

Innovative Particle Size Distribution and Higher Strength Yield Higher Fracture Conductivity

S TRENGTH. Endurance comes fromstrength. Athletes know that to achieveendurance they need strong muscles.

To run a marathon, an athlete needs strongmuscles that won’t break down over the lengthof the race. Strength is the key. Even thesmartest of the Three Little Pigs knew thatbricks are better for building a house thanstraw or sticks. So whether you need protec-tion from the Big Bad Wolf or need a proppantthat will hold up under pressure, choose amaterial that is strong.

Strength is at the heart of every Saint-GobainProppants product. For 28 years, Saint-GobainProppants (formerly Norton Proppants) hasbeen making quality ceramic proppants for theoil and gas industry. Versaprop® andUltraprop™, the company’s primary products,represent our commitment to quality, use of the

strongest ceramic materials and innovativeapproach to sieve distribution design. Theseproducts provide the highest value available tothe industry in ceramic proppants.

Versaprop, introduced in the fall of 2002,has combined intermediate density ceramicproppant material and an innovative sieve dis-tribution to become the value leader in theceramic proppant market. The combination ofstrength and sieve distribution gives Versaprop25% more conductivity than comparablypriced ceramics, which means more conductiv-ity delivered to the fracture per unit cost andtherefore increased value. The result: Versapropis the fastest growing proppant product in theindustry.

Ultraprop features the same innovative sievedistribution design as Versaprop and the high-est strength ceramic material, sintered bauxite.

This combination makes Ultraprop the valueleader in high-strength ceramic proppants.

Name change reflects worldwide scopeFort Smith, Ark.-based Norton Proppants wasthe first manufacturer of ceramic proppants.However, its experience with highly processed,naturally occurring base materials dates backmore than a century, to the F.B. Norton PotteryShop in Worcester, Mass., which grew fromhumble beginnings to become a diversified,multinational industrial abrasives manufacturer.

Norton Proppants was established in 1973,when sintered bauxite pellets became a keycomponent of hydraulic fracturing technology.The company grew as the oil and gas industryrecognized the value of higher-strengthceramic materials in fracturing applications. Aspart of its continuing evolution, the companyrecently took on the name of its corporate par-ent, Saint-Gobain, a world leader in ceramics,glass and plastics, whose High-PerformanceMaterials (HPM) business unit acquiredNorton in 1989.

The name change, which took effect Oct. 1,2004, reflects more than just the parent com-pany’s resources and specialization in ceramicmaterials development. It also embodies theincreased focus by Saint-Gobain Proppants onadditional world markets at a time when for-mation stimulation and re-stimulation areenhancing the flow of much-needed oil andgas production around the world.

To better serve the worldwide market,Saint-Gobain Proppants is in the process ofexpanding production capacity at its FortSmith plant by 30%.

In addition, Saint-Gobain HPM recentlypurchased the proppants business of theChinese firm Chengdu-Hengda Refractory andProppant Co. Ltd. This business, with head-quarters in Guanghan, Sichuan Province incentral China, services hydraulic fracturingoperations involved in the development of theprovince’s widespread natural gas reserves,

Ceramic proppants manufactured by Saint-Gobain Proppants (formerly Norton Proppants) havebeen a leading industry product of choice for more than 28 years.

14 COMPANY PROFILE

SAINT-GOBAIN PROPPANTS

Page 14: Conductivity Endurance, Halliburton

which provide more than half of China’s cur-rent domestic supply. This new arm of Saint-Gobain Proppants also will supply ceramicproppant to the growing Russian andSoutheast Asian markets.

The Guanghan manufacturing site will ben-efit from increased capital investment by Saint-Gobain Proppants, which will provide the exist-ing plant with leading-edge technology to meetthe company objective of increasing proppantproduction capacity three-fold by 2005.

Higher strength means conductivity enduranceJack Larry, director of worldwide sales andmarketing for Saint-Gobain Proppants, statedthat the median particle diameter (MPD) isthe primary determining factor in the level ofconductivity a proppant will provide.However, the completions engineer should be aware of how a proppant’s MPD changesas stress increases. Typically, we only look atthe proppant sieve distribution under surfaceconditions – before any stress is placed on the proppant.

While Saint-Gobain Proppants was devel-oping Versaprop, the company worked tounderstand why a proppant with a wider sievedistribution could have higher conductivitythan proppants with a tighter distribution. Toinvestigate this proppant physical behavior, aseries of crush tests were performed by anindependent laboratory to determine how thesieve distribution changed with stress. A sum-mary of this work is found in SPE Paper No.90562, presented at the Society of PetroleumEngineers Annual Technical Conference andExhibition in Houston in the fall of 2004. Thework indicates that a proppant with a tightersieve distribution under surface conditions canactually have a wider distribution once stress isintroduced if a weaker material is used. Also,the ability of a proppant product to retain itsMPD as stress increases correlates to its abilityto retain more of its conductivity with increas-ing stress.

Versaprop and Ultraprop are able to retaintheir unstressed MPD much better than light-weight ceramic counterparts. “This is why theycan deliver superior conductivity and value,”Larry said. Conductivity comes from size, con-ductivity endurance comes from strength andvalue comes from combining the two at com-petitive prices.

“Stress cycling can be a significant problemfor proppant packs,” Larry stated. “Each time

stress is relieved through increasing bottom-hole pressure and then increased againthrough a return to production, it can causeadditional crushing and a resulting loss in con-ductivity.” Long-term conductivity tests havedifficulty mimicking this behavior. However, itcan easily be duplicated using crush tests. Theresults from these cyclic crush tests continue tosupport the need for strength in the proppantmaterial, showing that proppants that arealready crushing have this extenuated, whilethose demonstrating strength are not affectedto the same degree.

While Versaprop and Ultraprop are thebackbone of the Saint-Gobain Proppantsproduct line, the company continues to manu-facture the same quality Interprop® andSintered Bauxite products it always has.Interprop can be purchased in 12/18, 16/30,20/40 and 30/50 American Petroleum Institute(API) mesh sizes. Sintered Bauxite is currentlyoffered in 16/30, 20/40 and 30/50 API meshsizes. All the company’s products are manufac-tured for storage in bulk form at its eightNorth American distribution points and aninth in the United Kingdom. They are avail-able via 24-hour truck dispatch to designatedland locations or offshore loading terminals.

Saint-Gobain: The big pictureSaint-Gobain Proppants is part of Saint-Gobain, one of the world’s 100 largest indus-

trial companies and a leader in the develop-ment and manufacture of ceramics and otherengineered materials. Saint-Gobain operatesin 46 countries around the world andemploys more than 171,000 individuals. Thecompany’s HPM business unit producesceramics, abrasives, crystals, grains and pow-ders along with reinforcement products fornumerous industry sectors, including energy,automotive, aerospace, medical and optical,electronic, and semiconductor. Saint-GobainHPM is a world leader in ceramics for ther-mal and mechanical applications and devotessignificant resources to ongoing research anddevelopment into new materials and newapplications of existing materials. ▲

15

Saint-Gobain Proppants is placing an increased focus on additional world markets at a timewhen formation stimulation and re-stimulation are enhancing the flow of much needed oil andgas production around the world.

Formerly Norton Proppants5300 Gerber Rd.

Fort Smith, AR 72904Tel: (479) 782-2001

Toll Free: (800) 643-2149Fax: (479-782-9984

Web site: www.proppants.saint-gobain.com

Page 15: Conductivity Endurance, Halliburton

Since Conductivity Endurance technolo-gies were first introduced, Halliburtonhas placed several thousand stimulation

treatments in reservoirs to enhance fractureconductivity and increase production poten-tials. Initial data and field tests on performancecharacteristics of the SandWedge® conductivityenhancer and Expedite® service were encourag-ing. Now, with time and production recordsadding substantial information to the analysis,it is clear these new technologies help preventintrusion of formation material and controlproppant flowback for improved long-termproduction. The realized benefits from theproper application of Conductivity Endurancetechnologies have been demonstrated in caseafter case. Here are just a few examples.

Case History 1: Gulf of MexicoHigh Perm Formation WellsProduction rates from four wells were com-pared (Figure 1). The wells were offsets andhad essentially identical completions except

that the proppant in one of the wells wastreated with SandWedge® OS enhancer.

Results: Compared to the average produc-tion from the other three wells, the SandWedgetreated well produced more initially, main-tained higher production, and produced 50%more cumulative.

Case History 2: New MexicoCoalbed Methane WellsSandWedge® conductivity enhancer used withDelta Frac service helped a major operatoradd coalbed methane production worth anestimated U.S. $10 million/year from 10coalbed wells in the San Juan Basin. Unlikeother area operators who traditionally haddrilled another blind sidetrack wellbore thathad to be cased and cemented, the SandWedgeenhancer with Delta Frac® service treatmentscalled for hanging an uncemented liner insidethe existing 7-in. casing and then perforatingat four shots per foot. The wells that had beencompleted open hole were cavitated. The

treatments were pumped at a rate of 65bbl/min using a 20-lb/1,000-gal Delta Fracservice fluid to place 5000 lb of 20/40 sand/ftof net coal. All proppant was coated with theSandWedge enhancer.

Results: Average production from theunder-performing wells increased 2.4-fold tomore than 14.8 MMcf/d. Treatment costs wererecovered in 3 months.

Case History 3: Gulf of Mexico Shelf WellsProduction rates from four Gulf of Mexico shelfwells were compared (Figure 2). The wells wereoffsets completed in almost the same way, withthe exception that two of the wells benefitedfrom Conductivity Endurance technology(SandWedge service).

Results: Notice the production from theSandWedge-treated wells showed little declineduring the 12-month period and providedabout three times the cumulative production ofthe wells completed conventionally.

Figure 1. Production comparison of four Gulf of Mexico high permeabil-ity wells.

Figure 2. Comparison demonstrating SandWedge production impact ontwo Gulf of Mexico wells.

16 CONDUCTIVITY ENDURANCE

CASE HISTORIES

Building the Case for Conductivity Endurance

Page 16: Conductivity Endurance, Halliburton

Case History 4: New MexicoCoalbed Methane ProductionIncreases Almost Four-FoldEven though they had already been fracture,stimulated with slick water and put on artificial lift, three Fruitland Coal wells innorthern New Mexico’s San Juan Basin were not producing up to their potential(averaging about 200 Mcf/d each).Halliburton worked closely with the operator to restimulate the wells using Delta Frac service and coating all the prop-pant with the SandWedge agent to enhancefracture conductivity and control finesmigration. Since all three wells under consideration were virtually identical indepth, hole size and formation conditions,it was decided to use SandWedge on two of

the wells to confirm the system’s perform-ance. Between 95,000 gal and 100,000 gal of Delta Frac® fluid was used to pump morethan 300,000 lb of proppant into each wellthrough 51⁄2-in. casing.

Results: All three treatments successfullyincreased gas production. In the well usingDelta Frac fluid by itself, the anticipated pro-duction increase was achieved. However, thetwo wells in which the SandWedge agent wasused showed an almost four-fold productionincrease. The wells are still flowing severalmonths after the job without artificial lift.The production increase and lift cost savingscreated an additional economic value of morethan U.S. $60,000 a month.

Case History 5: South Texas Gas WellsA South Texas operator needed to stimulate aseries of wells and achieve production morequickly than with the normal proceduresusing RCP. Typical well conditions includedbottomhole temperature greater than 325˚F(162.6˚C) with closure stresses up to about12,000psi. Typical treatments were pumped at 35 bbl/min to place 300,000 lb of bauxite at 2 lb/gal to 8 lb/gal.

Results: Using the Expedite® service, tem-perature and pressure of these wells enabledcleanup to begin after only 2 hours with littleor no proppant flowback. Production rateincreased 30%. Time to achieve 40 MMscf/dproduction was reduced from the usual 200hours with RCP to 65 hours for a 68%improvement. Cumulative proppant flowedback was reduced by 60% compared to flow-back with RCP material.

Case History 6: Eight SouthTexas Gas WellsIn the Monte Cristo field, production fromeight similar wells was compared – four treatedusing Expedite service and four treated con-ventionally (Figure 3).

Results: After 10 months, the four wellstreated using the Expedite service provided 21⁄2 times the production of the conventionallytreated wells.

Case History 7: San Juan Basin CBM WellsThree coalbed methane wells in the San JuanBasin (Four Corners area) were refracturedusing SandWedge® enhancer (see table). Thewells were studied in terms of the effect ofSandWedge agent on advancing dewateringand overall production.

Results: All three wells responded significantly and provided fast payouts ofthe refracs.

Case History 8: Michigan RefracIn Michigan, Halliburton applied its SandWedgeservice in fracturing one of two wells with thesame production and very similar characteristicson the log. Three additional wells were fracturedwith regular sand. One well experienced a pro-duction decrease from 275 Mcf to 220 Mcf.Another well screened out. Then on the thirdwell, the comparison well, initial productionincreased from 40 Mcf to about 150 Mcf withwater production also increasing. However,when the water production dropped off, pro-duction of gas also dropped to 80 Mcf.

Results: When the comparison well wasfractured using SandWedge, productionincreased five times from 40 Mcf/d to 200Mcf/d. Water production also increased, butwhen it later dropped off, gas production heldat 200 Mcf/d. The well has since gone as high as300 Mcf/d. The economic value to the operatoris about U.S. $290,000 for the first year (at thencurrent gas prices). ■

CONDUCTIVITY ENDURANCE

CASE HISTORIES17

Figure 3. Production comparison for eight South Texas gas wells.

San Juan Basin wells refractured using SandWedge.

Case CBM Refrac 1 CBM Refrac 2 CBM Refrac 3

Gas produced 9months after initial stimulation (Mcf)

463,747 88,406 72,452

Delta gas 9 monthsafter refrac (Mcf) 179,071 408,818 268,294

Time to pay out of stimulation treatment 3 weeks 3 weeks 1.33 months

Page 17: Conductivity Endurance, Halliburton

Texas company helps develop, manufacture and blend several Expedite proppant flowback control products.

Filling the Bill for Custom-made Fracture Treatment Chemicals

Q uality manufacturing and preciseblending of component chemicalsare crucial to developing new com-

pounds that, when used in advanced treatmentfluids, help coax more production from oil andgas well completions.

This is as true for the small quantities offluids to be analyzed at the laboratory benchlevel as it is for the somewhat larger recipestested at the pilot stage, but even more impor-tant when it comes to producing the muchgreater batch volumes necessary for commer-cial applications in the field.

Magnablend Inc., with 25 years of experi-ence in custom chemical manufacturing,blending and packaging, merits high standingin the oil and gas industry as a “go to”partner for providing chemical products prepared and blended to exacting customerspecifications. These and other capabilitieshave earned Magnablend “preferred supplier”status with a number of major companiesaround the world.

The company has long been an alliancepartner with Halliburton Energy Services(HES) as a key manufacturer of specialty liquidand powder compounds incorporated intomany of its downhole applications. They play acritical role in the success of the HES line ofConductivity Endurance services, including itsExpedite proppant flowback control system.

Grass roots participation pays offAlong with several other specialty chemicalssuppliers, HES called upon Magnablend toconsult very early in the grass-roots develop-ment of the dry and liquid chemical productsused for the service applications that came tobe grouped together as ConductivityEndurance technology.

Scott Pendery, vice president and chiefoperating officer, said Magnablend’s demon-strated ability to acquire raw materials quicklyfrom domestic and international sources, alongwith the capability of bringing its extensiveblending facilities to bare rapidly and depend-ably, added tremendous value during the tech-nology’s formative stages.

“In the fall of2001, Magnablendmade small pilotbatches ofConductivityEndurance chemicalsfor testing purposes,”Pendery said. “InJanuary 2002, HESstarted ordering full-scale productionquantities to supply anumber of fracturingjobs that includedthe Expedite® serv-ice. They relied onMagnablend to man-age chemical compo-nents sourcing to ensure that enough were on hand to meet the volumes required for Expedite applications, which were growing rapidly.”

Magnablend manufactures and blendscomponent chemicals used for the medium- tohigh-temperature and low-temperature ver-sions of the Expedite chemical products.

Since demand forecasts for any new prod-uct is difficult at best, Pendery said,Magnablend stayed in constant communica-tion with the field to calculate and fill a high-end inventory of Expedite component chemi-cals at its 40,000 sq-ft liquid blending facility inWaxahachie, Texas, about 25 miles (40 km)south of Dallas.

“By April of 2002, HES booked severalfracturing jobs requiring Expedite coating ofmillions of pounds of proppants,” he said.“They needed all the product we could supplyand asked us to do our best to anticipate thenear-term demand. So, we geared up to dojust that.”

In addition to ordering and warehousinglarge supplies of expensive raw chemical feedstock, Magnablend also dedicated themanpower and equipment necessary forrapid-fire turnaround that, during 2002,required 24-hour-a-day/7-day-a-week (24/7) accessibility.

“It was a challenging time, and the idea of falling behind was totally unacceptable,”Pendery said. “But while fulfilling theExpedite chemical product orders on timeand at a competitive price, we also focusedintently on high standards for safety, healthand environmental concerns, which we main-tain at all of our facilities.”

Modified ‘tote tanks’ benefit customersTo better handle distribution of the blendedExpedite chemicals during “on-the-fly” mixingat well sites, Magnablend ordered 36 gal of thefirst 330-gal tote tanks in the well treatmentindustry to be equipped with 3-in. interiordiameter (ID) ball-type discharge valves.“Standard” tote tanks are equipped with 2-in.ID butterfly valves.

Additionally, Pendery said, the tanks were engineered with top-mounted valves for pressurizing to further assist dischargingof the tanks’ liquid contents into well sitemixing equipment.

Later, with input from one of its key sup-pliers, Magnablend assisted HES in makingchanges in chemical formulations to furtherthin component products, transforming theblend from a suspension of chemicals into atrue solution, Pendery said. This not only

A bulk tank truck loads chemicals from 5,000-gal mixers at Magnablend'sliquid facility.

18 COMPANY PROFILE

MAGNABLEND INC.

Page 18: Conductivity Endurance, Halliburton

helped lower Expedite coating viscosity, hesaid, but also extended its shelf life, which had economic and job-specific benefits forthe customer.

“As the Expedite product continues tomature, both Magnablend and HES areengaged in a joint process of continuousimprovement,” Pendery said. “We cooperatewith HES to make sure that every product iter-ation simplifies application in the field.”

As an example of one such solution,Pendery said that after a well treatment wasfinished, the inside surfaces of well site mixingand pumping equipment was filmed with theadherent compound produced by mixingMagnablend-supplied products with otherchemicals to form the Expedite proppant coat-ing. Depending upon time elapsed for movingthe equipment back to HES facilities, this filmgradually stiffened, posing a potentially lengthycleanup time.

However, he said, Magnablend chemicalspecialists worked with their counterparts atthe HES laboratory in Duncan, Okla., todevelop a cleaning compound that can beused on location that diffuses such stickiness,leaving the equipment clean and ready for thenext job.

Plants meet wide-ranging specsFounded in 1979 and headquartered inWaxahachie, Texas, Magnablend has earnedhigh recognition in the industry for consis-tently maintaining a competitive edge by dintof its thorough attention to detail in customerservice, and through the quality workmanshipand honesty of its management and employees.

The company operates two chemical prod-

uct-blending facilities, one each for liquids andpowders, with the ability to quickly shift to a24/7-production schedule. The 40,000 sq-ftliquid blending facility is comprised of 21,000sq ft dedicated to manufacturing and packag-ing, with the remainder committed to ware-housing. An additional 12,000 sq ft of ware-house space is being added, with completionscheduled for spring 2005.

With more than 30 liquid-mixing vesselsranging in size from 250 gal to 15,000 gal, theplant can accommodate nearly any sized proj-ect. Mixing vessels are fabricated out of stain-less or carbon steel, fiberglass and high-densitypolyethylene, allowing coverage of an array ofchemical reactions. Built-in heating or coolingcapability allows routine handling of exother-mic and endothermic reactions. Specialized

equipment exists forextremely viscousblends as well as sus-pensions or disper-sions. After a productis manufactured andapproved byMagnablend’s qualitycontrol laboratory, itcan be packaged andlabeled as specified bythe customer.

Located nearby isthe 162,000 sq ft pow-der blending facility,comprised of 50,000 sqft for manufacturingand packaging, and

112,000 sq ft of warehouse space. Productionequipment includes seven double-action rib-bon blenders ranging in size from a 40-cf pilotbatch unit to a large 480-cf model, as well asseveral large storage/blending silos.

“The small unit allows us to make batchesin the 500-lb to 1,000-lb range, while the largeblenders handle batches up to 20,000-lb,”Pendery said. “By incorporating our 60,000-lbcapacity blending silos, we can produce fulltransport truckloads all under one lot number,a feature which some companies findextremely valuable.”

Such flexibility, he added, benefits cus-tomers, since Magnablend can assist with trialbatches during testing and then move directlyinto mass production. Powder products can bepackaged in containers ranging from 1-lb bagsto 50,000-lb bulk transport trucks.

In addition to its oilfield customers,Magnablend serves companies in the agricultural, water-treatment, rubber andindustrial cleaning compound industries,among others. ▲

19

Magnablend’s 162,000 sq-ft powdered chemical facility contains sevendouble-action ribbon blenders for small pilot-level quantities to large,commercial-sized batches.

Magnablend’s modern powder plant features ribbon blenders and a large storage area, allow-ing efficient loading of sacked and bulk-batch powdered chemicals.

Magnablend Inc.326 N. Grand Ave.

Waxahachie, TX 75165Tel: (972) 938-2028Fax: (972) 938-8203

Web site: www.magnablend.com

Page 19: Conductivity Endurance, Halliburton

20

New well conductivity enhancement services benefit from cross-fertilization among widespread labs andproduction sites.

Merging Worldwide Resources to Solve R&D Partners’ Needs

W hen Halliburton Energy Services(HES) decided to conduct addi-tional research into improved

polymers for cleaner well stimulation fluids,they went to long-time research and develop-ment (R&D) partner the Rhodia Group forassistance in creating new polymeric com-pounds and improving existing ones.

Rhodia, headquartered in Aubervilliers,France, is a far-reaching specialty chemicalscompany with strong technology positions inapplications chemistry, specialty materialsand services, and fine chemicals. It has anumber of subsidiaries in Europe, the FarEast and the Americas. Combined, the Rhodiacompanies have more than 23,000 worldwideemployees, a large percentage of whom arechemists, as well as chemical engineers, andother engineering specialists and businessdevelopment professionals.

Rhodia Inc., the U.S. subsidiary, is amongcompanies that assist HES with R&D into andmanufacturing of chemical building blocksfor their special formation treatment fluids.Much of this work is conducted under formalR&D partnerships.

Rhodia Inc., headquartered in Cranbury,NJ, operates an Oilfield Services group basedin Houston that has generated more than 30years of experience in supplying a range ofproducts used in drilling, cementing, stimula-tion and production. That group supports oil-field service customers and partners with aproduct offering made up of surfactants, natu-ral hydrocolloids and synthetic polymers usedin the oilfield setting as emulsifiers, dispersingand wetting agents, viscosifiers and gellants,corrosion and scale inhibitors, biocides, andfoaming and antifoaming agents. For the HESConductivity EnduranceS services, the group

conducts R&D to develop products from guargum, xanthan gum, and other natural and syn-thetic polymers.

Rhodia’s oilfield service operations are notlimited to the U.S. market. Under the parentcompany’s successful global business model, allof its resources, including five R&D centersworldwide – Aubervilliers and Lyon, France;Paulinia, Brazil; Shanghai, People’s Republic ofChina; and Cranbury – can be brought to bearto help formulate oilfield service or otherindustry-specific chemical products, whereverthey are needed. The company also operates113 production sites around the world, withseveral based in the United States workingclosely with service company customers andpartners to manufacture formation-level prod-ucts for use anywhere on the globe.

‘Fast-break’ conductivityKansas Hernandez, regional business directorfor the Americas, said that for oilfield chemi-cals, Rhodia’s suite of viscosifier and gellantproducts made from guar-based polymers aswell as from synthetic polymers, is helping customers and partners enhance fracture conductivity in oil and gas wells.

“In the case of HES’s ConductivityEndurance services, our chemists work directlywith theirs to develop various treatment fluidtechnologies, including fracturing fluid prod-ucts whose viscosity is best broken with a sepa-rate additive, or those that break when theycome into contact with formation fluids,”Hernandez said.

The newly developed micro-polymers, hesaid, help enhance fracture conductivity inthree ways: they help carry an optimum prop-pant load into the fracture, and when “de-linked” on contact with formation-producedfluids, offer extremely high cleanout efficiency.This is particularly important in combinationwith the HES proppant surface modificationagents, which help significantly raise overallfracture conductivity. The third benefit fromthe micro-polymer system and the way it islinked and subsequently de-linked is the possi-bility it can be re-used.

A company-wide ability to ‘cross-breed’ capabilities allows Rhodia to bring its worldwideresearch and development capabilities to bare to help solve customer/partner challenges.

COMPANY PROFILE

RHODIA

Page 20: Conductivity Endurance, Halliburton

21

Most of the feed stocks for Rhodia’s guar-based polymers receive initial processing inIndia, where guar beans are grown, harvestedand “split” to separate the endosperm fromwhich the natural polymer base materials arederived (though, if market forces dictate,Rhodia can obtain splits from guar beansgrown and harvested domestically, with thesplitting process undertaken at a U.S. produc-tion site). In India, this initial step is handledunder a long-term (50 years) partnershipbetween Rhodia and Indian companyHindustan Gum and Chemicals. The guar is then shipped directly to a Rhodia ware-house and production sites as splits or,after additional processing in India, as standard guar powder.

Hernandez said that among other marketR&D activities, the company’s Cranbury labo-ratory handles oilfield applications, includingfracturing fluid formulations, and subjectsthem to standard American Petroleum Institutetesting before submitting them for testing andapproval at the customers’ own laboratories.Orders for fracturing fluid component chemi-cals and other products are fulfilled largely atRhodia’s production facility at Vernon, Texas,near Wichita Falls, Texas. There, at a state-of-the-art plant on a 40-acre site, splits from Indiaor domestic sources are processed into standardguar products or derivatized guar such as HPG,CMHPG, cationic or other specialty derivi-tiezed guar products.

Other well treatment chemical productsare formulated and tested at various Rhodialabs around the world under similar R&Dpartnership arrangements, Hernandez said.Many are manufactured at the Vernon plant,with some coming from other U.S. and over-seas production sites.

The art of cross-fertilizationDavid Kremmer, oilfield service account man-ager, said Rhodia Inc.’s research and productinnovation strategies are important aspects ofits well treatment chemicals business. Servicecompany customer/partners expect more fromsuppliers than just the products, he said, andthey depend upon suppliers to deliver com-plete solutions that address their unique, prod-uct-specific requirements.

Kremmer said Rhodia uses internal “cross-fertilization” capabilities to draw upon a vastreservoir of technical and field expertise inorganic and inorganic chemistry to identifycustomers’ needs. After R&D completion,

the company’s project engineers, who arechemists or chemical specialists, help deter-mine which chemical products work best tofill those needs.

“Our global research centers are available tohelp deliver the user benefits our customersand partners expect,” said Kremmer, whoadded that any of the production sites alsocould be brought in to participate with indi-vidual project teams. “By stimulating interac-tion among the talented people employed bythese company assets through this uniquecross-functional business process, we candevelop comprehensive, end-to-end solutions.”

While internal capabilities are an integralpart of the company’s culture, Rhodia strivesto identify skills and technology sources out-side the company, as well, said Bruno Langlois,market innovation director for the parentcompany’s industrial and oilfield specialtiesgroup based in France.

This has resulted in numerous R&D part-nerships with customers, he said. It alsoincludes basic and applied research partner-ships established with a number of major uni-versity and scientific research laboratoriesaround the world. In the United States, theseinclude Harvard University, MassachusettsInstitute of Technology (MIT) and theUniversity of California at Santa Barbara.Overseas research partners include the FrenchNational Scientific Research Center, Belgium’sUniversity of Louvain and Brazil’s nationaluniversity.

Overall, such cross-productiveness results in benefits where they count the most, Langlois said.

“By listening more closely to our

customers and R&D partners, Rhodia is com-mitted to designing the right end-productswhile minimizing the time required to manu-facture them. That shortens the time it takesfor the customer to move those products intothe marketplace.”

A worldwide market baseIn addition to oilfield specialties markets, theRhodia Group also serves and partners withmajor players in the petrochemical and refin-ing, automotive, electronics, fibers, pharma-ceuticals, agrochemicals, consumer care, tire,paints and coatings markets, among others.

More than half the company’s productdevelopment projects are undertaken in part-nerships with customers.

In 2003, the company, whose shares aretraded on major world stock exchanges,posted consolidated net sales of U.S. $6.8 bil-lion (5.5 billion Euros). In the same year, thecompany allocated almost 4% of net sales toR&D activity, with 6% of that investedthrough external partnerships. ▲

Rhodia’s 40-acre Vernon, Texas, production plant manufactures guar-based polymers for use inwell treatment fluids worldwide.

Worldwide40 Rue de la Coq

93306 Aubervilliers Cedex FranceNorth America

259 Prospect Plains RoadCranbury, NJ 08152

Oilfield Tel: (979) 239-2890Fax: (979) 233-8748

Web site: www.rhodia-hpcii.com

Page 21: Conductivity Endurance, Halliburton

The use of proppant surface-modification technology enhances well productivity.

Stick to Tacky. It Pays.

A surface modification agent (SMA)was introduced into the global stim-ulation market in 1997. The agent

was designed to enhance and sustain fractureconductivity by making the proppant surfacetacky. Several conductivity-enhancing mecha-nisms were suggested. Two important mecha-nisms resulting from increased surface tacki-ness are: increased proppant pack porosityresulting in increased pack permeability; andincreased proppant pack stability that preventsencroachment of formation fines into the packand migration of fines within the proppantpack. The myth that excess conductivity can beplaced in a fracture or frac pack to allow finesproduction has been disproved. Stim-Lab test-ing has verified that locking fines in place willmaintain greater proppant conductivity thanallowing them to be produced. In terms ofextended conductivity maintenance, the finescontrol aspect has proved the most valuableproperty developed from the product.

At the well site, the proppant is coated withSMA (a thermally stable, polymeric material)during the well treatment. It becomes tacky,resulting in long-term changes in the propertiesof the proppant pack. Because of its tackiness,SMA-coated proppant resistssettling, resulting in increasedpack porosity and permeabil-ity. It also resists movementcaused by fluid flow. In addi-tion, the SMA does notharden and the flexible, tackycoating makes the proppantresistant to stress changesresulting from variable pro-duction conditions.1

Since first introduced,thousands of stimulationtreatments have been placedin reservoirs with the surfacemodification agent(Halliburton’s proprietarySandWedge®) to generateconductivity enhancement.

Most early detractors considered benefits fromconductivity enhancement to improve the ini-tial potential of the well and little else. What isnow believed is that more hydraulically frac-tured reservoirs produce fines than previouslythought. Soft rock reservoirs (Young’s Modulusless than 1 million) and coalbed methanereservoirs are notorious for producing fines.Conversely, few would expect reservoir rockwith properties similar to the Vicksburg Sandof South Texas or the Tirrawarra of the CooperBasin in Australia are capable of producingfines. However, several cases have evolvedwhere some benefit from using an SMA isobserved in these reservoirs.2

Conductivity maintenance, then, is thelong-term benefit of using an SMA material toabate fracture or proppant conductivity decline.The maintenance process is more than simplyestablishing a higher conductivity starting level,as in cases that use very low residue3 or other-wise non-damaging frac fluids.4 The processalso is more than establishing fracture conduc-tivity by including proppant flowback control5

or proppant pack stability.6 Conductivity main-tenance is the process of addressing theseissues, in addition to providing long-term fines

control7 and proppant pack flexibility. Lack offines control can have the most devastatingeffect on proppant pack conductivity.

Damage within the Proppant Pack8

The invasion of fines into a proppant pack canaffect pack permeability, resulting in underper-formance and premature decline in well pro-ductivity, such as effectively “choking” the pro-ductive capacity of the well. Formations pro-duced from wells completed with hydraulicfracturing, frac-packing and gravel packing aresusceptible to pack invasion of fines and subse-quent permeability or conductivity losses.With each of these completion techniques, tar-get productivity depends on proppant-packpermeability and conductivity. Again, conven-tional thinking leads one to believe thatincreasing the proppant size or concentrationwill provide adequate conductivity and allowthe fines to be produced. This, however, is notthe case. Some fines may be produced, butthose left behind will bridge and ultimatelyreduce the conductivity of the proppant packin both soft and hard rock stimulations.

Fines invasion has been limited historicallyto classic size exclusion processes (criteria

reported by Saucier) in whichthe proppant-pack size distri-bution is sized to the medianparticle size of the formation.This approach is limitedbecause one proppant size isselected for formations thatare almost always heteroge-neous. The tendency, there-fore, is to undersize the prop-pant pack to exclude thesmallest median formation-framework grain size likely tobe encountered. As a result,production may be conduc-tivity limited assuming nofurther fines encroachmentand damage to the pack. Evenin adequately designed packs

Figure 1. Results of using Saucier model to determine permeability damage result-ing from fines invasion. Larger SMA-coated proppant prevented fines invasion.

22 CONDUCTIVITY ENDURANCE

1. S. Ali, S.Vitthal and J. Weaver: "Improvements in High-Rate Water Packing with Surface-ModificationAgent," SPE 58755, presented at the SPE International Symposium on Formation Damage held in Lafayette,La., Feb. 23-24, 2000.

2. L. Lehman, B. Shelley, T. Crumrine, M. Gusdorf and J. Tiffin: "Conductivity Maintenance: Long-TermResults from the Use of Conductivity Enhancement Material," SPE 82241, presented at the SPE EuropeanFormation Damage Conference, The Hague, The Netherlands, May 13-14, 2003.

3. J. Dawson, H. Le and C. Cramer: "Successful Application of a Novel Fracturing Fluid in the WasatchFormation in Eastern Colorado," SPE 49042, presented at the Annual SPE Technical Conference andExhibition, New Orleans, Sept. 27-30, 1998.

4. M. Samuel et al.: "Polymer-Free Fracturing Fluid for Hydraulic Fracturing," SPE 38622, presented at theAnnual SPE Technology Conference and Exhibition, San Antonio, Oct. 7, 1997.

Page 22: Conductivity Endurance, Halliburton

in which formation framework grains areexcluded, many formations have a “fine” tail, orcontain significant formation “matrix” or authi-genic minerals within the pore network that canbecome mobile and infiltrate into the proppantpack. This condition, which usually is diagnosedafter completion, requires post completiontreatments such as acidizing for remediation.

However, alternative solutions and a funda-mentally different approach using proppantsurface-modification technology to preventproppant-pack damage has emerged throughstudy of the mechanisms of fines invasion, par-ticle plugging and interface stabilization. SMAis now a proven technology that has changedprevious solution paradigms (Figure 1).

It is important to note that proppant con-ductivity is a smaller-scale component of frac-ture conductivity. Standard industry conduc-tivity testing usually is performed in thesmaller-scale context of proppant conductivity.This scale-dependent concept is illustrated inFigure 2.

Proppant and fracture conductivity can beimpaired or damaged from the several overlap-ping mechanisms. In each phase, the physics ofparticle retention and the net effect on perme-ability are different. The most significant find-ing in analysis of particle-deposition mecha-nisms and resulting permeability reductioninvolves deposition kinetics and the location ofparticle retention. The flow regime and themechanism determining permeability damagedepend on these variables. An important con-

clusion from extensive analysis is that inter-pack conductivity or permeability reductiondepends on the specific particle-depositionmechanism (Figure 3).

Surface deposition of particles—In thisphase, particles deposit on the grain/poresurface. The kinetics of this process dependon physical and chemical factors such aspore-scale hydrodynamics, electrostaticcharge differences between particles andpore surfaces, pore-surface texture and par-ticle composition. Whether surface deposi-tion is restricted to monolayer or multilayerdeposition depends on the tendency for par-ticles to aggregate.9 It has been theoreticallyand experimentally demonstrated that thisphase alone results in minimal damage.Colloidal and clay-sized particles normallywould fit into this deposition mechanism inthe absence of larger macro particles.

Pore-throat bridging and accumula-tion—Pore-throat bridging occurs when aparticle flowing through a pore throat formsa bridge. The particle may attach to two parti-cles already deposited onto a pore-throat sur-face (three-particle bridging) or to a previouslydeposited particle and pore-throat surface(two-particle bridging). Pore-throat bridgingalso can occur when particles are larger thanthe pore-throat size (single-particle bridging).Once formed, the pore bridge forms the struc-ture for subsequent upstream accumulation ofparticles, thereby dramatically decreasing thefluid-flow rate through these pores. The most

dramatic rate of permeability decrease isobserved during this phase (Figure 4).

Internal cake formation—Once the forma-tion of bridged pore throats reaches a criticalvalue, the pores no longer are connected oversome critical damage depth. In this phase, allthe incoming particles accumulate not only inthe immediate pore throat, but also within allpore bodies that still are available to flow, form-ing an internal filter cake.10,11 Weaver et al. intro-duces this impairment mechanism through

CONDUCTIVITY ENDURANCE 23

Figure 2. Fracture model for frac-packing indicating proppant-conductivity vs. fracture conductivity. Figure 3. Interpack damage mechanisms.

Figure 4. Extensive testing has verified the abilityof SandWedge® agent to stabilize the proppantpack/formation interface to reduce intrusion of for-mation material into the proppant pack. The micro-graph images above were taken following identi-cal test procedures. The image on the left is aproppant pack without SandWedge agent. Noticethe formation material intrudes deeply into thepack, almost completely plugging pore throats.The image on the right is an identical proppantpack in which SandWedge agent has beenapplied. Notice the formation material/proppantpack interface is distinct and shows virtually nointrusion. Also, pore throats are clear. SandWedgeagent remains active almost indefinitely for long-term pack stability and conductivity to helpachieve improved production.

5. R. Card et al.: "A Novel Technology for Controlling Proppant Backproduction," SPE 31007, printed in SPEProduction & Facilities, November 1995.

6. A. Richards et al.: "Need Stress Relief? A New Approach to Reducing Stress Cycling Induced Proppant PackFailure," SPE 49247, presented at the Annual SPE Technical Conference and Exhibition, New Orleans, Sept. 27-30, 1998.

7. M. Blauch et al.: "New Insights into Proppant-Pack Damage due to Infiltration of Formation Fines," SPE56833, presented at the Annual SPE Technology Conference and Exhibition, Houston, Oct. 3-6, 1999.

8. Ibid.9. G. Chauvetear, et al: "Physics and Modeling of Permeability Damage Induced by Particle Deposition," SPE 39463,

presented at the SPE International Symposium on Formation Damage Control, Lafayette, La., Feb. 18-19, 1998.10. Gatlin and Nemir: "Some Effects of Size Distribution on Particle Bridging in Lost Circulation and Filtration

Tests," Journal of Petroleum Technology, June 1961, p. 575-578.11. A. Abrams: "Mud Design to Minimize Rock Impairment Due to Particle Invasion," Journal of Petroleum

Technology, May 1977, p. 586-592.12. J. Weaver, M. Blauch, M. Parker and B. Todd: "Investigation of Proppant-Pack Formation Interface and

Relationship to Particulate Invasion," SPE 54771, presented at the European Formation Damage Conference,The Hague, The Netherlands, May 31-June 1, 1999.

13. Ibid.

Page 23: Conductivity Endurance, Halliburton

micro visualization techniques.12 The depth ofthe internal damage and the permeability ofthis region control the system permeability orconductivity. The onset of internal cake forma-tion is characterized by rapid reduction ofdownstream particle concentration. Theamount of permeability damage depends onthe concentration and distribution of smallerparticles, including colloidal and clay size, inthe flowstream. Expansion of this work has ledto additional insights about particle-size distri-butions, shape and bridging mechanisms.

External cake formation—At the pointwhere internal cake formation is achieved, par-ticles accumulate upstream and may form filtercakes at the interface. In a fracture/gravel-packapplication, this mechanism is not a primaryphenomenon, since the internal filter-cakegrowth would dominate and continue alongthe length of the propped fracture.

Infiltration-sedimentation—In geologicmedia and sand filtration systems such as apropped fracture, mass flow of particle slurriesinto a porous medium results in particle accu-mulation in hydrodynamic low-flow regions.This accumulation can occur in the absence ofinternal filter-cake formation. This process canbe largely gravity-driven, whereby thedynamic-flow vector force is less than the sedi-mentation force, resulting in the interporeaccumulation of infiltrated particles. Thisprocess was first described in the context offracture/gravel packing.13

Source of Fines, Transport and Conductivity ImpairmentUnconsolidated or poorly consolidated (“soft

rock”) formations, and those completed withfracture/gravel packing methods are most sus-ceptible, although not exclusively, to destabiliza-tion of the formation/fines interface andencroachment of fines into the proppant pack.Even in “hard rock” formations, the proppantpack can be susceptible to fines migration fromproppant crushing because of formation andproduction cycling stress. Fines also are createdduring the fracturing process, and can migratethrough the proppant pack and greatly reduceproppant conductivity. Formation types usuallyconsidered most susceptible to interface desta-bilization include unconsolidated clastics suchas laminated sand/shale sequences, turbiditesand volcaniclastics such as tuffs or bentoniticshales. Among the many well-known examplesand analogs, the most notable are offshore for-mations producing from the Gulf of Mexico.Nonclastic formations susceptible to this phe-nomenon include carbonate chalks, organiccoal and shale.14 Following is a brief summaryof the various sources of fines destabilizationand encroachment.

Unattached or weakly bonded fines—Someformations contain unattached or weaklybonded fines. The slightest change in fluidsalinity or interfacial tension can cause thesefines to migrate with the producing fluid.These fines typically are small enough to movethrough a proppant pack without causingsevere plugging, if not too many fines are mov-ing at once.

Formation stress and fluid velocitychanges—Stress changes resulting from varia-tions in production rates and pressures oftencan cause formations to yield. In addition, the

onset of water production and the resultingchanges in the capillary pressure/relative per-meability can weaken the formation matrix.Consequently, the formation integrity at theproppant pack interface can fail, resulting infines migration and/or invasion into the prop-pant pack (Figure 5).

Proppant crushing—Fines are generatedwhen proppant is crushed during the trans-porting, mixing and pumping operationsrequired for well completion. Weak proppantor that which is not uniformly distributed, alsocan be crushed by excessive fracture closurestresses and production cycling. Fines resultingfrom proppant crushing vary widely in sizedistribution, but all can damage pack perme-ability (Figure 6).15

Historical Control MethodsHistorical methods employed to prevent ortreat damage caused by formation finesinclude chemical and mechanical techniques.

Chemical treatment—These methods aredesigned to produce a chemical reaction withthe formation sand for the purpose of inhibit-ing its mobility. They normally include the useof chemical flocculation, or the use of organiccationic polymers, inorganic polymers and oil-wetting surfactants.16,17 Although chemicaltreatments sometimes are referred to as "per-manent," they are subject to deterioration withtime and also result in reduced formation per-meability.18 They focus on flocculation oragglomeration of clay fines for formationtreatment, or involve changing the surface-wetting properties to reduce the tendency ofaqueous fluids to migrate. Limited study or

24 CONDUCTIVITY ENDURANCE

14. M. Blauch et al.: "New Insights into Proppant-Pack Damage due to Infiltration of Formation Fines," SPE56833, presented at the Annual SPE Technology Conference and Exhibition, Houston, Oct. 3-6, 1999.

15. S. Ali, S.Vitthal and J. Weaver: "Improvements in High-Rate Water Packing with Surface-ModificationAgent," SPE 58755, presented at the SPE International Symposium on Formation Damage held in Lafayette,La., Feb. 23-24, 2000.

16. H. McLaughlin and J. Weaver: "Oil Well Treating Method and Composition," US Patent 4,366,071 (Dec.28,1982).

17. H. McLaughlin, E. Elphingstone and B. Hall: "Aqueous Polymers for Treating Clays in Oil and Gas," SPE 6008,presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Oct. 3-6, 1976.

18. W.K. Ott and J.D. Woods: Modern Sandface Completion Practices Handbook, Gulf Publishing Co.,September 2003.

Figure 5. Fines migration and intrusion canresult from stress changes within the forma-tion/proppant pack, which can cause severeconductivity impairment.

Figure 6. The effect of production cycling on proppant is shown above. Base proppant (left),proppant after 10 cycles at 8,000psi (center), and proppant after 20 cycles at 8,000psi (right).Notice the obvious crushed fines and damaged proppant (circled in right photo).

Page 24: Conductivity Endurance, Halliburton

application has been performed with these sys-tems in the context of fracture/gravel-packcompletions. All of these existing technologiesrely on treatment and contact with the parti-cles, which may become mobile.

Another solution involves applying tempo-rary clay stabilizers. These stabilizers minimizethe tendency to disperse or deflocculate natu-rally occurring fines within the formationmatrix. Such chemical systems may includemono and divalent salts or low-molecular-weight quaternary amines. This solution isconsidered temporary, since the subsequentchanges in water salinity can cause chemicaldispersion or swelling of the susceptible clays.19

Mechanical exclusion methods—Theseinclude the use of mechanical "screens" or sand-exclusion devices. However, the screen has noeffect on fracture conductivity. The frac-packingtechnique, for example, provides stimulationand sand control. In poorly consolidated forma-tions completed by frac packing, sand and finesexclusion and sufficient conductivity depend oncareful proppant sizing. Smaller proppant sizescan provide sand and fines control without pro-viding adequate conductivity.

Controlling Fines with SMA TechnologyIn fracturing or frac-pack operations, proppantcoated with SMA becomes tacky, resulting inlong-term changes in the properties of theproppant pack. Because of its tackiness, SMA-coated proppant resists proppant grain move-ment caused by fluid flow. The coated prop-pant also resists packing and settling, resultingin increased pack porosity and permeability. Inaddition, because the flexible, tacky coatingSMA provides does not harden, it resists stresschanges resulting from variable productionconditions. Extensive laboratory data andthousands of field applications have led to thefollowing conclusions: 20,21,22

• conductivity maintenance can extendinto an economic benefit by increasingultimate recovery and reducing monthlyoperating expenses;

• SMA-treated proppant resists particulateinvasion and maintains permeabilityover a range of flow rates;

• surface treatment of proppant to renderthe surfaces “tacky” has the followingeffects: the treatment adsorbs finesentering a proppant pack; and it reducesor eliminates fines entry into a proppantpack by stabilizing the proppant/forma-tion interface;

• pore bridging and accumulation, inter-nal cake formation and infiltration sedi-mentation are dominant mechanismsthat cause the greatest damage to prop-pant packs;

• particle adsorption onto proppant sur-faces produces minimal damage to per-meability because of the location anddistribution of the entrapped fines; and

• the proppant’s resistance to particulateinvasion results in a new sizing criteriafor frac-pack treatments, which enableslarger proppant sizes to be used formaximum well productivity.

SMA-treated proppant has been found toprevent proppant-pack damage caused by infil-tration of formation fines into a proppant pack:

• proppants coated with SMA thatremains tacky while in the formationexhibit a great degree of control over theconductivity endurance of the proppant

pack. This control has a longer effectthan previously thought because ofSMA’s capability to control other con-ductivity damaging factors;

• the economic benefit from using anSMA can outweigh the cost where finescontribute to diminishing conductivity;

• in cases where fines are the major factorcontributing to conductivity loss, refrac-ing zones with SMA-laden proppant isvalue-proven; and

• SMA coating is resistant to water andhydrocarbon-based well fluids.

In summary, SandWedge (SMA) enhancercan be applied to proppant as a liquid additive.It dramatically increases the surface friction ofindividual proppant grains. Because SandWedgematerial coats the proppant before it becomescoated with frac fluid gel, more gel remains inthe intergranular volume, helping improve the stereo-chemical capability of breakers used during cleanup. SandWedge material also helps improve proppant conductivity by enabling proppant grains to achieve better vertical distribution and alignmentwithin the fracture. This, in turn, increasesproppant porosity, which equates to increasedproppant pack permeability. ■

CONDUCTIVITY ENDURANCE 25

19. M. Blauch et al.: "New Insights into Proppant-Pack Damage due to Infiltration of Formation Fines," SPE56833, presented at the Annual SPE Technology Conference and Exhibition, Houston, Oct. 3-6, 1999.

20. Ibid.21. S. Ali, S.Vitthal and J. Weaver: "Improvements in High-Rate Water Packing with Surface-Modification

Agent," SPE 58755, presented at the SPE International Symposium on Formation Damage held in Lafayette,La., Feb. 23-24, 2000.

22. L. Lehman, B. Shelley, T. Crumrine, M. Gusdorf and J. Tiffin: "Conductivity Maintenance: Long-TermResults from the Use of Conductivity Enhancement Material," SPE 82241, presented at the SPE EuropeanFormation Damage Conference, The Hague, The Netherlands, May 13-14, 2003.

Figure 7. Uncoated bauxite is shown above.Note that formation sand in the upper right-hand corner has invaded the proppant pack,plugging pore spaces.

Figure 8. Bauxite coated with SandWedge® isshown above. Pore spaces remain open, withonly a few grains (white spots visible on prop-pant) evident in the proppant pack. Note the for-mation sand is "stuck" to the proppant and willnot migrate through the proppant pack.

Figure 9. Uncoated economical lightweightproppant. Note crushing from pressure. Finescreated by crushed proppant are free tomigrate to pore spaces.

Figure 10. Economical lightweight proppantis shown pack coated with SandWedge agent.Pressures also crush Proppant; however, SMAholds fines in place.

Page 25: Conductivity Endurance, Halliburton

Forging cooperative relationships with service providers creates teamwork to supply much-needed formation-level chemicals.

Research and Development Partnerships Help Drive Oilfield Success

N alco is a company name long recognized as a world leader inwater treatment and industrial

process products and services. The companyhas a 75-year history as a specialty chemicalsmanufacturer, technology innovator, researchand development (R&D) partner, and processenhancement company with more than 10,000 employees. The company serves customers globally in numerous industries,among which range from aerospace and aviation to cosmetics, and from mining andminerals to pharmaceuticals.

One of Nalco’s most important markets isthe petroleum industry, where its products andservices extend across all phases of hydrocar-bons development – from oil and gas extrac-tion, production and transportation to refiningand petrochemicals processing.

The company’s contributions to the extrac-tion segment, including exploration and pro-duction, benefit producers and service-providers who help them drill and completewells with the common goal of yielding opti-mum production at the lowest possible field development cost. Nowhere is this more evident than in those contributions made by Nalco’s Adomite Group, which is heavilyinvolved in formulating and blending chemi-cals with which to exclude co-production of brines and other costly water-based fluids,as well as undesirable sedimentary materials,from the well stream.

Based at the company’s Energy ServicesDivision headquarters in Sugar Land, Texas,near Houston, the Adomite Well ServiceChemicals group supports oilfield service-providers by supplying special formulations toaid oil and natural gas well drilling at the for-mation level, where produced water and for-mation residues often create major barriers toefficient production. Adomite’s researchchemists and field engineers are helping createnew products for drilling, cementing, comple-tion, fracturing and acidizing, among otherdownhole treatment services.

The company is working closely with oil-well service companies to provide special

chemicals and addi-tives for inhibitingcorrosion of oilfieldtubulars and pump-ing equipment down-hole and at the sur-face. It also providesthe means necessaryto significantly reducethe effects of frictioncreated by the flow offluids under extremedownhole tempera-tures and pressures.

Partnering on well treatmentsolutionsOne of Adomite’s keychemical develop-ment activities hasbeen its long-termR&D partnershipwith HalliburtonEnergy Services(HES) in developingspecialty chemicalsfor a number of welltreatment applica-tions. Among these isAdomite’s close coop-eration in designing alarge-scale manufac-turing process at theNalco SugarLandplant to produce anumber of water conformance chemicals usedby HES in its Conductivity Endurance series offormation fracturing services.

Ronald B. Lessard, technical director for theAdomite group, said HES took the formulaefor the proprietary water shut-off chemicals –developed originally at its Duncan, Okla., R&Dlaboratories – to Nalco Energy Services.Drawing on the confidentiality and trust estab-lished by the existing R&D partnership, HESasked Adomite to design and scale-up aprocess to manufacture the chemicals in

batches of as much as 40,000 gal. The Duncangroup teamed with Adomite’s chemists andtechnical consultants to produce pilot-levelquantities at the Nalco complex in SugarLand.They then designed and developed the neces-sary process train in time to supply HES withquantities sufficient to meet field requirements.

“It was a challenge for us to fulfill a fast-track product delivery schedule such as thatone, because the chemistry is difficult,” Lessardsaid. “It was no short order. But we were suc-cessful, and the mutual confidence already

Nalco’s chemicals are shipped in their environmentally safe, patentedPorta-Feed® containers, which are ideal for offshore handling.

26 COMPANY PROFILE

NALCO ENERGY SERVICES DIVISION

Page 26: Conductivity Endurance, Halliburton

established between the two research groupsdid much to make it possible.”

Wide-ranging focus on customers’ needsWhile R&D efforts made by Nalco EnergyServices divisions, including Adomite, arefocused on technical innovations created bytheir own Ph.D.-level research chemists to helpsolve customers’ current challenges as well asprevent potential new ones, they often call onsuch inter-company teamwork to help providesupport for the customer’s own innovations,Lessard said.

“In this case, the actual chemistry was created by HES, but we also routinely supplyHES, as well as other service companies,with products developed jointly by our respective research groups,” he said. “And,having forged this tight connection at the R&D level, our research chemists at timesdevelop new material that we take exclusivelyto the companies with the knowledge that it has a potential role in specific types ofservice applications.”

In fact, he added, it is only with the HESR&D team’s approval that any Nalco EnergyServices sales effort can be directed either tothe Halliburton Co. corporate or HES fieldpurchasing organization. This holds true forother service company customers, as well.

Meanwhile, as Nalco Energy Services divi-sions work to provide original and customer-formulated chemical products, its field salesengineers devote most of their time workingwith customers at their actual field serviceinstallations to help ensure Nalco products arebeing applied in the most result-effective, yetcost-efficient way.

“Most of our technical sales people arechemists by training, so they look at ways inwhich the assets can be managed to produce amaximum effect,” Lessard said. “But they alsomonitor product use with an eye on gettingbetter results from more efficient applicationof the product.”

Getting better results also sometimes callsfor development of subsequent product gener-ations, he said.

“Once our research chemists have walkedthrough a new chemical formulation with the customer and have returned to the plantto set up manufacturing processes and to follow through to actual production, theyoften consider new chemistry that mightimprove on the original formulation,” he

said. “For instance, we are now working on a completely different chemistry withwhich we hope to extend the working tem-perature levels for a number of products now in field use. Since this work is being conducted under an R&D partnership, thepotential benefits created by a new iterationwould go directly to the partner. But in theend, both sides gain.”

Divisions circle the globeThe Energy Services Division of Nalco Co.is a global leader in providing on-site prob-lem solving innovations through its extensivenetwork of technical field specialists in morethan 120 countries. The division’s upstreambusinesses concentrate on solutions to criticalexploration and production issues, includingcorrosion control, oil/water separation, scalecontrol, water treatment, paraffin/asphaltenecontrol, gas/production handling, oil spillchemicals and flow assurance problems associated with gas hydrate formation.

The parent company’s worldwide staff ofresearch and manufacturing professionalswork at key centers around the world,

including one at its Naperville corporateheadquarters. Overseas research/manufactur-ing hubs include the Latin AmericaOperations Center in Sao Paulo, Brazil;European Operations Center at Leiden,The Netherlands; and Pacific Rim OperationsCenter in Singapore. Combined, these centers constitute 49 plants with a total of9,400 professional and skilled employees.Managerial, administrative and other staffconstitute the remainder of the company’stotal employment. ▲

27

Nalco collaborates with customers at the research and development stage to deliver groundbreak-ing innovations.

Nalco Co.P.O. Box 87

Sugar Land, TX 77487Tel: (281) 263-7000Fax: (281) 263-7900

Web site: www.nalco.com

Page 27: Conductivity Endurance, Halliburton

With a staff of field-proven petroleum engineers, a manufacturer works with customers to select the idealproppant for each stimulation treatment.

Designing Fractures for Realistic Downhole Demands

C ompanies at the heart of hydraulicfracturing services share a commonobjective: to deliver nothing less than

optimum fracture conductivity to each well sothe customer benefits most where it counts –at the sales line meter.

Irving, Texas-based CARBO Ceramics, theworld’s largest manufacturer of environmen-tally friendly ceramic proppant, complementsthe work of well-treatment service providerssuch as Halliburton Energy Services – as wellas operating company customers – in severalways. Not only does the company supply thevolumes of ceramic proppant necessary forfracturing operations anywhere in the world,but it also makes technical expertise availableat no cost to help service companies and oper-ators choose the most cost-effective proppantfor every fracturing job.

“We meet the worldwide demand for ourfully-tested, superior quality products fromthree manufacturing plants in the U.S. and afourth in China,” said Terry Palisch, senior staffpetroleum engineer in Irving. “We produce 735million lb per year of tightly-sieved ceramicproppant, which provides superior conductiv-ity to all competing proppants in the market.In all North American locations, this materialis delivered to the wellsite in CARBO-dedi-cated trucks. Internationally, service companiessupply our products from CARBO distributioncenters located in South America, Europe,Middle East, Russia, Southeast Asia andAustralia. Our distribution and storage net-work is unequalled in the industry.”

But manufacturing capacity, product qual-ity assurance and efficient delivery are onlypart of the story. CARBO also boasts a team ofpetroleum engineers who have extensive fieldexperience in hydraulic fracturing. These fracengineers are available to work closely withcustomers before a job to select the correctproppant for the specific formation involvedand then assist with analyzing the actual resultsafter the job is completed. Not only does suchdetailed post-job analysis help assure the cus-tomer a high degree of well productivity, butfield results are fed into CARBO’s fracturingtechnology database, which the engineers use

to demonstrate the most effective proppantapplications through case histories, field stud-ies, technical presentations and in future jobconsultations.

‘Real’ downhole effects often overlooked “Our deep interest in conductivity technologystems from more than 25 years of manufactur-ing and supplying ceramic proppants,” Palischsaid. “We have found that the industry oftenrelies on models that do not realistically pre-

dict fracture conductivity under actual reser-voir conditions. As a result, the industry toooften employs frac sand in situations whereceramic proppant would yield far more prof-itable results.”

CARBO representatives have found mosttraditional conductivity models do not reflectthe many complex issues and downhole condi-tions to which the proppant is exposed, includ-ing non-Darcy and multiphase flow effects;density and width implications; long-termproppant degradation; gel damage; fines

28 COMPANY PROFILE

CARBO CERAMICS INC.

Figure 1.

Figure 2.

Page 28: Conductivity Endurance, Halliburton

migration; and cyclic stresses. “These effectscan decrease the conductivity of the proppantpack by over 95% (Figure 1),” Palisch said.

The engineering staff realized only a fewmodels account for any appreciable number ofthese effects, he said, and if they are taken intoconsideration, even fewer have actual field dataon which to justify correlations.

CARBO Ceramics embarked on a field trialcampaign with several operators 5 years ago inwhich they identified fields they could – underas controlled conditions as possible – make ahead-to-head comparison between the com-pany’s ceramic proppants and lower effectiveconductivity sand, resin-coated sand orbroadly-sieved ceramics.

“We also looked at other fields in whichour products were being used and, eventhough they were not controlled trials, wecould study production results to assess theimpact of using top-quality ceramics. Fromthat, we ‘reality checked’ the model predictions.

“Remember, many fracture models willerroneously predict only trivial pressure losseswithin the fracture. Consequently, these mod-els forecast minimal benefit to increasing con-ductivity by using premium proppants,”Palisch said.

The company also completed a thoroughliterature review and identified more than 100cases from around the world – encompassingthe spectrum of reservoir conditions – thatdemonstrate a direct correlation betweenheightened conductivity and increased produc-tion. Short summaries and full references formost of these cases are documented onwww.carboceramics.com and in Society ofPetroleum Engineers (SPE) Paper No. 77675.

The most recently published CARBO fieldtrial was conducted in the Middle Lance inter-vals in the Pinedale Anticline of Wyoming(SPE Paper No. 90620). The improved produc-tion exhibited when comparing stages thatreceived CARBOECONOPROP® vs. those thatreceived a resin-coated sand (RCS) was “eye-popping” (Figure 2). “Traditional wisdom sug-gested that the middle Lance stages were ofpoor reservoir quality, and all operators in thefield considered sand or RCS to provide ade-quate conductivity in this 12-microDarcy(0.012 md) formation. However, when thesesame middle Lance intervals were treated withCARBOECONOPROP, they provided amongthe highest productivity of any stages in thefield,” Palisch said.

Representatives at CARBO have recently

initiated similar trials in the Pinedale area andanticipate being able to further substantiatethese results as well as compare productivity oftheir tightly-sieved ceramics with less uniformceramics provided by other manufacturers.

‘Required conductivity’ a better goalThe company’s sales and engineering staffbelieves the old industry paradigm of usingstress as the major criterion for selecting prop-pant is outdated. The focus might better beplaced on “required conductivity.” Merelyselecting a proppant based on well depth oreven reported crush statistics rarely matches theproppant conductivity requirements to the welldeliverability. Optimal proppant selection canmore accurately be made with full economicanalyses based upon the reservoir conditionsand the operator’s specific economic criteria.The bottom line is that under realistic condi-tions, fractures propped with premium ceramicproppant exhibit far better conductivity thanconventional sands and RCS (Figure 3).

Sales and petroleum engineers are not theonly staff involved in making sure the company’sproducts deliver superior fracture conductivityto the customer. The company maintains state-of-the-art laboratories at all four manufacturingfacilities. Research specialists there are dedicatedto assuring the quality of all products producedand distributed from the facilities.

“In 2004 alone, CARBO will have per-formed more than 45,000 crush tests, 30,000

sieve analyses and 30,000 bulk density measure-ments,” Palisch said. “We will have performedover 600 short-term and 75 long-term conduc-tivity and beta tests, with these numberstripling upon completion of our new long-term conductivity lab at our plant in China.”

Additionally, the company’s dedicated teamof research and development scientists and spe-cialists are working diligently to evaluate newproducts and are engaged in a constant searchfor ways to make existing products better.

“We currently inventory seven tightly-sieved alternatives (40/70, 30/60, 30/50,20/40, 16/30, 16/20 and 12/18) in four distinctproduct lines. In specialty applications,CARBO provides proppant in sizes rangingfrom 70/140 to 6/10,” Palisch said. “These allhelp CARBO reach its goal to deliver the mostvalue to your wellsite.” ▲

CARBOECONOPROP and CARBOLITE areregistered trademarks of Carbo Ceramics Inc.

29

CARBO Ceramics Inc.6565 MacArthur Blvd., Ste. 1050

Irving, TX 75039Tel: (972) 401-0090Fax: (972) 401-0705

Web site: www.carboceramics.com

Figure 3.

Page 29: Conductivity Endurance, Halliburton

Curable resin-coated proppant was introduced to the industry during the 1980s as a means to preventproppant flowback. For a hydraulic fracturing or frac-pack treatment to be effective, resin-coated prop-pants should consolidate under downhole conditions into a long-lasting, high-strength permeable pack.

Not All Resin-Coated Proppants Are Created Equal1

T oday, two general coating processesare used (Figure 1). The first is to precoat proppant with a resin (RCP)

in a manufacturing plant and then partiallycure it so the proppant can be convenientlystored and transported to the job site with-out consolidating. The second methodinvolves “on-the-fly” coating of the proppantwith an activated liquid resin system – LRS –(Halliburton’s proprietary Expedite® service)at the job site as it is used during a fracturetreatment. This system was first introducedto the global stimulation market in late1990s. As more wells are drilled into deeperreservoirs, severe conditions – including hightemperatures, high production flow rates,and high-closure stresses in propped frac-tures – impose more constraints on the useof curable resin systems.

Nguyen et al.2 report on an extensivestudy related to a new liquid resin coatingsystem that is particularly, but not exclu-sively, useful in controlling proppant flow-back in high-temperature, high-flow ratewells. Additives included in the LRS elimi-nate fracturing fluid interference and permitconsolidation properties to be achievedwithout any formation closure stress.Results of this work demonstrate the diffi-culty in designing fracturing treatments so the curing of resin does not occur toofast relative to fracture treatment time and the time for formation closure toachieve consolidation, but fast enough to prevent flowback upon fluid recoveryoperations. The useful window for resin-coated proppants has been expanded by the incorporation of simple chemical addi-tives into the resin that react with fracturingfluids, rendering them non-interfering tothe consolidation process. Additivesincluded in the LRS emiminate fracturingfluid interference and permit consolidation

properties to be achieved without any for-mation closure stress.

The study provides new answers as towhy RCP consolidations sometimes fail inthe field. Operators can use the informationpresented to help them select the appropri-ate curable resin systems for their applica-tions where consolidations are expected towithstand production conditions of hightemperatures, high flow rates and high- orlow-stress loading.

An earlier study has shown that a compres-sive strength of about 150psi is adequate tocontrol proppant flowback in producing wellswith moderate temperatures and productionrates.3 However, for a consolidated proppantpack to be successful long term, one can inferthat higher consolidation strength is required,coupled with flexibility to handle repeatedstress changes that occur during normal pro-

duction operations at the reservoir tempera-ture. One of the targets of the Nguyen studywas to provide a hydraulic fracture comple-tion that can, in addition to being able to con-trol proppant flowback at high temperatures,allow extremely aggressive flowback rates toremove the fracturing fluid in minimal time,so the production of hydrocarbons can beginas soon as the resin coating on the proppant is“cured” or set. There have been many tech-niques developed during the years to try toaddress these issues.

Failure mechanisms—The limitations andfailure mechanisms of RCPs have been exten-sively studied and well documented. Vreeburget al. have identified two types of proppantflowback that occur when RCPs are used; oneis during the well-cleanup phase, and theother is after a long period of proppant-freeproduction.4

Figure 1. Comparison of cure rates of RCP and high-temperature Expedite LRS system. Note thatat 225ºF (107ºC) and 275ºF (135ºC), the Expedite system had a much slower cure rate.

30 CONDUCTIVITY ENDURANCE

1. P. Nguyen, J. Weaver, M. Parker, M. McCabe, M. Hoogteijling and M. van der Horst, “A NovelApproach for Enhancing Proppant Consolidation: Laboratory Testing and Field Applications,” SPE77748, presented at the SPE Annual Technical Conference, San Antonio, Sept. 29 – Oct. 2, 2002.

2. P. Nguyen, J. Weaver, M. Parker, M. McCabe, M. Hoogteijling and M. van der Horst, “A NovelApproach for Enhancing Proppant Consolidation: Laboratory Testing and Field Applications,” SPE77748, presented at the SPE Annual Technical Conference, San Antonio, Sept. 29 – Oct. 2, 2002.

Page 30: Conductivity Endurance, Halliburton

The early production-type scenario isthought to be caused by insufficient bondingstrength of the RCP. The factors affecting thestrength of the RCP pack include resin con-centration, resin type, curing temperature,resin/fracturing fluid interaction (undershear and temperature) and erosion of theresin from the proppant grains.

The late flowback of proppant mecha-nism was believed to be caused by damage to the consolidated RCP resulting from the stress cycling that the proppant under-goes each time the well is shut in and putback on production.

During a fracturing treatment at nor-mally used proppant concentrations, theproppant grains are, in general, not in con-tact (dispersed) while going downhole. Inaddition, the fluid and proppant tempera-ture is increasing during this time. Once theproppant is placed in the fracture, it isbelieved that there is some proppant grain-to-grain contact that is required in order toform a consolidated pack. The loss of con-solidation strength with curing under lowclosure stress has been identified as a poten-tial failure mechanism.4 Some RCPs havebeen specially formulated to consolidate onlyunder high closure stress. Although this fea-ture facilitates tubing cleanout after a prema-ture screenout, it can lead to reducedstrength development of the RCP pack withdelayed or uneven closure of the formation.

The confining stress acting on the prop-pant pack during the curing process is prob-ably not uniform because of variations ofthe formation in-situ stress and the forma-tion rock-mechanical properties. In addition,some formations may not completely closeafter treatments. Some hydraulic fractures donot completely close during the first 24hours after hydraulic-fracture stimulationtreatments, especially in the case of low per-meability formations. In fact, it has beenreported that many reservoir rocks do notsufficiently close to prevent proppant flow-back and settling during the first 90 daysafter the fracturing operations.5

RCPs may not be effective when wells with multiple or large perforated intervals are treated. Multiple fractures or parts of sin-

gle fractures in high-stress zones can screenout during the proppant stages. Dependingon the stage of the fracturing treatment, ifRCPs are not run throughout, portions of thepropped fractures may not contain any RCPand may contain only uncoated proppant thatcan be produced back. Uncoated proppant

also can be produced from a well that hasbeen perforated during a relatively shortinterval if the treatment was not properlydesigned, and the high proppant concentra-tion RCP stages have been transported awayfrom the near-wellbore area because of buoy-ancy forces.6

CONDUCTIVITY ENDURANCE 31

Figure 2. Expedite LRS coating remained on the proppant grains and provided consistent con-solidation strengths despite extended stirring (simulated pumping) time.

Figure 3. In a comparison of widely used RCPs and Expedite® service at various closurestresses, note that Expedite service provides about three times the conductivity of RCPs at4,000psi and 40% better conductivity at 10,000psi. Testing conditions: 2lb/sq ft, 300°F(149ºC), water as flow medium, at least 48-hours per stress load. (*Note: RCP conductivity datais from supplier-published technical information.)

3. L. Norman, et al.: “Applications of Curable Resin-Coated Proppants,” Production Engineering,November 1992, p. 343-349.

4. R. Vreeburg, et al.: “Production Backproduction during Hydraulic Fracturing - a New FailureMechanism for Resin-Coated Proppants,” Journal of Petroleum Technology, October 1994, p. 884-889.

5. R. Blauer and D. Holcomb: “The Detection, Simulation, and Reservoir Performance Impact of

Slowly Closing Fractures,” SPE 37404, presented at the SPE Production Operations Symposium,Oklahoma City, Okla., March 9-11, 1997.

6. M. Cleary and A. Fonseca: “Proppant Convection and Encapsulation in Hydraulic Fracturing:Practical Implications of Computer and Laboratory Simulations,” SPE 24825, presented at the SPEAnnual Technical Conference and Exhibition, Washington, DC, Oct. 4-7, 1992.

Page 31: Conductivity Endurance, Halliburton

Even when RCPs are placed as designed,failures can occur. Several factors that canaffect RCP consolidation strengths and ulti-mate performances are:3,4,6, 7

• loss of consolidation strength has beenidentified with increased fluid pH;

• crosslinked carrier fluid incompatibility;

• increased shearing;• low and very high closure stress; and• increased stress cycling.

These factors are now well recognized inthe industry and usually are considered injob design and candidate selection. A factornot usually considered is the effect of the

cure kinetics of the proppant’s resin coat onits ultimate consolidation.

Cure kinetics and closure stresses—An ear-lier study by Nguyen et al.8 has concluded thatmost, if not all, of the currently availableRCPs lose their ability to form consolidationswith adequate strengths after being exposedto extended pump times in water-based frac-turing fluids and high temperatures. The curekinetics of RCPs were found to have animpact on the resulting consolidationstrength after curing. For an RCP to achievemaximum consolidation strength, the RCPscure rate should be slow enough that there isminimal curing (or hardening) while theproppant is being pumped and until the for-mation has started closing.

By contrast, the systems that use a liquidresin applied to the proppant as it is beingplaced in the fracture have shown slowercure rates. These systems have demonstratedthe ability to achieve consolidation strengthsthat are much higher than RCPs (Figures 2and 3). The high strengths are achieved evenwhen there are long periods of time beforefracture closure occurs and in some caseseven without closure stress applied to theproppant grains.

The later during the curing cycle the RCPis brought into grain-to-grain contact, thelower the ultimate consolidation strengththat will be developed. Because the resincure rate increases with temperature, thehigher the temperature to which the prop-pant is exposed before grain-to-grain contactoccurs, the lower the ultimate consolidationstrength. In addition, fracturing fluid com-ponents can have a significant impact on theresin-curing rate (any test performed needsto be conducted in the actual fluid systemplanned for the fracture treatment). Thecombination of these effects of time beforegrain-to-grain contact, along with fluideffects and temperature, has a dramaticeffect on the ultimate consolidation strengthof the proppant pack.

It can be expected that the resin systemswith slower cure rates and those that requireminimal closure stress for consolidationwould show less loss in consolidation strengthin fracturing treatments with long pumptimes and slow formation closure rates.

32 CONDUCTIVITY ENDURANCE

7. S. Almond, G. Penny and M. Conway: “Factors Affecting Proppant Flowback with Resin-CoatedProppants,” SPE 30096, presented at the European Formation Damage Conference, The Netherlands,May 15-16, 1995.

8. P. Nguyen, et al.: “New Guidelines for Applying Curable Resin-Coated Proppants,” SPE 39582,

presented at the International Symposium on Formation Damage Control, Lafayette, La., Feb.18-19, 1998.

9. B. Todd, et al.: “Resin Compositions and Methods of Consolidating Particulate Solids in Wellswith or without Closure Pressure,” US Patent 6,311,773; issued Nov. 6, 2001.

Figure 4. With Expedite® service, capillary action causes flow of the liquid resin, concentratingit between proppant grains and resulting in greater concentration of resin at contact points forincreased durability. Above are photomicrographs of a widely used RCP (left) and proppantcoated using Expedite service (right). Both samples were handled identically and tested to failure.Resin grain-to-grain contact footprints (right) correlate closely to compressive strength. Note thelack of contact footprints on the RCP (left).

Figure 5. Expedite® service can help prevent loss of fracture width due to proppant flowback.StimLab conducted tests at 250ºF (121ºC) and 6,000psi closure. Note that gas flow rate increasedto about 130 MMscf/d with essentially no fracture width decrease due to proppant production.

Page 32: Conductivity Endurance, Halliburton

Why LRS-coated proppant outperformsRCPs—Halliburton’s proprietary ExpediteLRS-treated system shows superior perform-ance because:

• capillary action causes flow of the liq-uid resin, concentrating it betweenproppant grains and resulting ingreater concentration of resin at con-tact points (Figures 4 and 5);

• extrusion between proppant grainsincreases porosity and fracture con-ductivity; and

• LRS-treated proppant is tacky, whichpromotes grain-to-grain contact. Incontrast, the RCPs, even when heated,are not as tacky and have little grain-to-grain contact without closurestress. LRS-treated proppant has aslower cure rate and is not removedfrom the proppant surface during stir-ring (simulated pumping) because theresin system has been specially formu-lated to preferentially coat proppantsin gel. RCPs, on the other hand, havefaster cure rates, and the resin fromsome of these proppants has beenshown to be leached off into the frac-turing fluids.

RCPs are partially cured to provide forstorage and handling, and the portion of theresin that is cured does not contribute to theultimate consolidation strength. Only a smallfraction of the resin in RCP is curable, whileall the resin in LRS is curable. Conversely,LRS efficiently contributes to the final con-solidation strength even with less resin:

• LRS is formulated with additives thatpromote the removal of gelled fractur-ing fluid film that can sometimesimpede grain-to-grain contact andconsolidation9; and

• LRS eliminates the problems of dam-age to coated proppants inherent inhandling and storage.

Case History: Indonesia—A fractureoptimization process was initiated in a low-

temperature, low-pressure reservoir with anobjective to increase production and controlproppant flowback. Three design criteriawere pinpointed:

• perforation scheme;• hydraulic fracturing design with tip

screenout (TSO); and• proppant flowback control (if

required).After the optimum perforation scheme

was completed, the hydraulic fracturingdesign was implemented to achieve TSOfracturing. A good TSO fracture treatmentwas expected to significantly reduce proppantflowback. A live annulus was available so thenet pressure increase could be observed accu-rately in real time. It showed a steady netpressure increase, as reducing the pad from14.5% to 4% quickly modified the design.This verified a good TSO was achieved.Nevertheless, proppant flowed back evenwith optimum perforation design and TSOfracturing. The LRS (Expedite service) waschosen to control proppant flowback.

Twenty-three wells were fractured in thiscampaign (Figure 6). Of the 11 wells inwhich the LRS was not applied, proppantflowback occurred in eight wells, necessitat-ing workovers. Starting at the twelfth well,the fracturing treatments included the LRSadditive as it was deemed to be the bestsuited system for low bottomhole tempera-tures and low closure stress. Results: When

LRS was used, there was no decrease in pro-duction because the resin and frequency ofworkovers due to proppant flowback (sandfill) was reduced by 75%.

Conclusions—The Nguyen study and sub-sequent field applications demonstrate that:

• LRS permits aggressive well cleanupprocedures to be used after fracturestimulation. This system significantlyimproves well production time to market;

• LRS minimizes chemical interferenceswith fracturing fluid and permits coat-ing of proppant just prior to blendingwith the fracturing fluid;

• the slow curing rate of the LRS allowsmaximum consolidation strength tobe obtained, but sufficient earlystrength to allow flowback to startwith a short shut-in time;

• additives included in the liquid resin facilitate the removal ofcrosslinked fracturing fluid from the proppant grains;

• resin coating of the entire proppantstage eliminates the possibility foruncoated proppant being producedback; and

• LRS consolidates proppant grains tothe formation face. This produces alarger “footprint,” which reduces finescreation and migration within theproppant pack during time. ■

CONDUCTIVITY ENDURANCE 33

Temperature ratings for various Expedite liquid-resin systems.

Figure 6. Comparison between fracturing treatments not using LRS (Expedite service) and treat-ments using LRS.

Liquid ResinSystem

Bottomhole StaticTemperatureRating (˚F)

Expedite 225 60 – 225

Expedite 350 200 – 350

Expedite 550 300 -550

Page 33: Conductivity Endurance, Halliburton

34

Houston company raises the bar for guar-based products and works toward adding powder only for “on-the-fly” frac fluid preparation.

Keeping an Eye on the Future for Polymers in Well Treatment Fluids

A mong recent innovations that have extended the state-of-the-art in hydraulic fracturing has been

reducing the concentrations of guar-derivedpolymers in well treatment fluids to helpimprove hydrocarbon conductivity frominduced fractures.

At first it might appear to be a self-inflicted setback to its own future, butHouston-based Economy Polymers andChemicals (Economy), a key supplier to thepetroleum industry of naturally derived,high-molecular-weight polymers, is strivingto reduce the concentration of their ownproducts in such well treatment fluids. Thecompany believes that combined with moreefficient cross-linking technology, the use ofhigher quality, improved polymers will helpreduce formation damage, and operators willhave higher overall hydrocarbon productionfrom their wells.

To lower polymer loading to as little as25% of what it was in 1995, the company isinvolved in research in Houston and Jodhpur,India. They introduced the first fast-hydrat-ing, high-viscosity products and are lookingat more ways to continue improving the guarpolymer. The company is looking into theorigins of the gum by involving itself in sev-eral projects dealing with agronomy, which isthe application of soil and plant sciences toland management and crop production.Economy is in a tightly focused search todevelop even faster hydrating guar-basedpolymers than the ones they first introducedto the industry a few years ago. Their conceptis simple: faster-hydrating, higher viscositypolymers reduce fracture fluid loading; there-fore, they deliver more efficient chemical sta-bility and viscosity, which suspends the frac-ture proppant better while it is sheared andheated in surface mixing and pumpingequipment, well tubulars, perforations andthe fractures themselves. But perhaps evenmore important, once introduced into thefractured zone, faster-hydrating polymers willhelp reduce flowback of so-called “additional

residues” when thepolymers themselvesdegrade and areremoved with the fracfluid prior to placingthe well on produc-tion. Better fractureconductivity meansbetter formation flow.

The well operatorbenefits in severalways from the switchto more efficient,faster-hydrating,higher viscosity poly-mers. Less polymerlessens the cost pergallon of treatmentfluid, fracture conduc-tivity is improved, andless blockage to for-mation flow meanshigher ultimate hydro-carbon recovery.

Economy’s natural guar and guar-derivedpolymers – producedas an odorless powder,in processing plants inHouston and Jodhpur,or slurried with sol-vents at processingplants in Calgary,Canada; Fresno, Calif.;Rock Springs, Wyo.;and Houston – are used by oilfield servicecompanies in a number of well treatmentapplications. They are, for example, an integralcomponent of several of the special treatmentfluids used by Halliburton Energy Services(HES) in its new Conductivity Endurancegroup of well completion services.

Among Economy Polymer products used by HES and other service companies are Ecopol 2000, composed of unmodifiedguars; and Ecopol 18 and Ecopol 400,both double derivatives of guar. All are

fast hydrating, easily dispersible and willrespond to conventional crosslinking prod-ucts under basic as well as acidic conditions.The company also manufactures a number ofother polymers for inclusion in well treat-ment fluids.

The quest for better polymersFounded as a chemical supply company in 1951, Economy entered the polymer business in 1982. Since then, it has come to the petroleum industry marketplace

From a small plant springs guar for frac fluid polymers.

COMPANY PROFILE

ECONOMY POLYMERS AND CHEMICALS

Page 34: Conductivity Endurance, Halliburton

35

with a number of revolutionary products,including faster-hydrating polymers for welltreatment fluids, introduced in 2002, whichexhibit higher viscosities and lower polymer-loading characteristics.

Generally, the polymers are producedfrom the guar plant, or cluster bean(Cyamopsis tetragonolobus), an annual plantnative to India and adapted to its semi-aridnorthern and northeastern regions. Theplant’s beans have been dried and used aslivestock feed for thousands of years. Indianfarmers grow the beans and then separateand hand-process them for shipment to thecompany’s Jodhpur plant. Once there, eachbean’s endosperm, or nutritive tissue sur-rounding the seed embryo, is isolated tomanufacture the guar gum base for polymer-ization, the remainder – comprised of solidprotein – is sold as livestock feed. The gum,once processed, is soluble in water, becominggelatinous after time. It hardens when dried,allowing it to be powdered and laced withvarious additives to manufacture specific oil-field polymers for shipping in bulk form orin sacks.

Walter White, Economy’s vice president,said that while the company’s guar-derivedproducts also are used in the personal care and food industries, among others,it has become a staple for oil service applications that require a slurry additive for oil- and water-based well treatment fluids. The company’s research chemists continue to work on reducing the amount of polymer required per thousand gallons of slurry, White said.

“Five years ago, the standard guar product had slow hydration rates, with tests results using a Fann*-35 viscometerranging from 22 cps to 24 cps in 3 minutesand 34 cps to 36 cps in 60 minutes,”White said. “Today, we provide guar-based polymers with 3-minute viscosities of 36 cps to 37 cps and 60-minute viscosities of 46 cps to 48 cps.”

But Economy is searching for even better results. And that, he said, is where the agronomy comes in.

The company is growing hybridized guarplants in India that yield much cleaner seeds,he said, which is resulting in a purer guargum. As a result, the company already is pro-ducing a powdered polymer that, instead ofbeing slurried with various oils and shippedto the well site, can be mixed on the fly with

water, proppant and other necessary chemi-cals – proppant surface-modification coat-ings, cross-linkers and fluid-loss agents – andthen pumped directly into the formation asthe well treatment fluid.

“Once a commercial-grade product isdeveloped and tested in the field, we believeeliminating oil-based slurries altogether –particularly those using diesel oil – will pro-vide significant health and environmentalbenefits, as well as trigger major cost struc-ture changes,” White said. The technology forthis is available today.

A commitment to qualityAs part of its commitment to bring new polymer technology to its markets,Economy controls the entire process of producing raw guar materials and intermediates, including the seed to split operations and processing train in India, as well as the processing-distribution plant in Houston. Both state-of-the-art plants are ISO 9001 2000 certified.

With such raw materials production control in hand, Economy’s first obligation is to provide highest quality products and services to a global customerbase at competitive prices. To accomplishthis, the company is committed to its quality management system and quality policy, which demands continuous

improvement while providing a safe environment for all full-time employees,associates, subcontractors and othersinvolved in their operations.

Meanwhile, as the company works to innovate new technology, it communicates with customers to create new and better formulations,bring new products to the marketplace and provide technical help to customerswhenever necessary.

In addition to the processing plants, thecompany owns seven blending and distribut-ing facilities in North America, with moreplanned in a number of overseas petroleumindustry provinces. ▲

* Mark of Fann Instrument Co.

Hydration profiles 40ppt gels, 2% KCI mix 1 min at 2,800 rpm, Houston tap at 75˚F.

Economy Polymers and ChemicalsP.O. Box 40245

Houston, TX 77245-0245Tel: (800) 231-2066Fax: (713) 723-1845

Web site: www.economypolymers.com

Page 35: Conductivity Endurance, Halliburton

Multiple coats of uniquely formulated curable resin protect sand and ceramic propping materials fromflowback and embedment, and greatly enhance conductivity and crush resistance.

An Intelligent Alternative in CombatingProppant Back-production

A s a negative result of hydraulic frac-turing, even minor instances ofproppant flowback compromise the

conductivity and permeability of the prop-pant pack. The flowback, which occurs duringinitial cleanup or after the well is put backinto full production, ultimately robs proppantfrom the fractures, eventually restraining pro-duction flow. But it also can lead to costly,protracted well service operations.

The ability to keep proppant flowback toan absolute minimum serves to stabilize frac-tures, even under cyclical stresses, therebyhelping conduct hydrocarbons into the well-bore at or near the rate designated in the fracplan. With proppant flowback at a minimum,the customer justifies the expense of the frac-turing treatment – i.e., he or she gets what ispaid for – and benefits from results of higherlong-term fracture conductivity, such asgreater hydrocarbon recovery during the pro-ductive life of the well.

To prevent proppant flowback and othernegative effects, operators often choose thefull range of curable, resin-coated sand andceramic proppants manufactured by Santrol,a subsidiary of Fairmount Industries. Santrol,based in Fresno, Texas, near Houston, pio-neered coating proppants with multiple lay-ers of high-quality phenolic and other spe-cialty resins for greater flowback resistance

and higher permeability throughout therange of closure stresses encountered inhydraulic fracturing. The company firstbegan offering resin-coated gravel pack sandsmore than 25 years ago, and has since been atthe forefront of proppant coating technology.

Curable proppants prevent flowback,reduce embedment and crushed fines, andincrease long-term conductivity. Santrol uses patented multi-layer coating techniquesto apply the resins to specially treated basesand or ceramic substrates. Differentialcrosslink density of each resin layer allowsthe product to attain added strength as wellas the ability to attain grain-to-grain bond-ing, or “curability” in the formation. Free-flow additives, anti-dusting and anti-staticagents enhance handling, water-wetting andflow characteristics.

G2 proppant coating: layers of technologyAmong Santrol’s most recent advancementsin proppant technology is the company’s G2 – second-generation – coating technol-ogy, which company representatives say is anadvancement over existing encapsulated cur-able products, since it furthers the science ofhigh-performance resins as well as the meanswith which to apply successive thin films ofsuch novel resins as encapsulation layers over

curable resin coats (Figure 1). The proppantgrain or bead is first coated with a fully curedlow-molecular-weight PF resin, followed bycoating with a curable, low-molecular-weight“core” layer of resin, after which a fully curedthin-film encapsulation layer of epoxy resinis applied. Finally, the proppant is filmedover with a special coating containing free-flow additives and antistatic agents.

Jon Harper with Houston sales said that allof Santrol’s G2 proppant types provide excel-lent flowback resistance, embedment reductionand increased crush resistance, among otherbenefits. He added that they are curable andexhibit high compatibility with all fracturingfluids, including low-polymer and viscoelasticsystems, and are stable in temperatures up to600°F (315.2˚C).

Developed by Santrol’s research chemistsat the company’s Fresno plant, which, Harpersaid, happens to be dedicated to manufactur-ing ceramic-based coated products, the G2technology has been incorporated into sev-eral new Santrol product lines:

• OptiProp G2—Santrol’s premierencapsulated multi-coat curable prop-pant. Most often using AmericanPetroleum Institute high-spheroid sil-ica sands, but also available on a vari-ety of ceramic media (16/20 and20/40), OptiProp provides superiorperformance for high closure-stressapplications and exhibits high compat-ibility with fluid and breaker systems.The resin coating design allows forconsolidation only under closure pressure in the formation, thereby virtually eliminating the possibility of bonding in the wellbore and allow-ing it to remain in the wellbore forextended periods without consolidat-ing. It is designed for wells with bottomhole temperatures above 140˚F(60˚C) and closures in the 6,000-psi to 10,000-psi range.

• MagnaProp G2—Santrol’s economyceramic proppant is designed for supe-rior performance in moderate closureFigure 1. The above graphic shows the multi-layer coating process for the G2 product line.

36 COMPANY PROFILE

SANTROL

Page 36: Conductivity Endurance, Halliburton

stress applications and con-solidates only after grain-to-grain contact underpressure has occurred.Because only formationclosure pressure allows it toconsolidate, MagnaProp isideal for fracturing multi-zone, deviated and hori-zontal wells with bottom-hole temperatures above140°F in the 6,000-psi to12,000-psi range.

• DynaProp G2—This is thecompany’s mid-range light-weight ceramic proppant.Exhibiting all the proper-ties of Santrol’s patentedG2 coating technology,DynaProp is designed as astress-curable proppantand consolidates only aftergrain-to-grain contactunder formation closurepressure. The resin protectsthe proppant base fromquick stress loading and provides addi-tional toughness resulting in highercrush resistance with bottomhole tem-peratures above 140˚F in the 9,000-psito 14,000-psi range.

• HyperProp G2—Santrol’s upper-rangesintered bauxite-based proppant pro-vides superior performance for mid- tohigh-closure stress applications andeffectively lowers the density of bauxitewhen combined with the resin coating,allowing easier fracture placement andreducing costs on a volumetric basis.HyperProp may be used in hydrauli-cally fractured wells with bottomholetemperatures above 140˚F and closuresin the 10,000-psi to 16,000-psi range.

“The downhole benefits of using Santrol’sG2 coating technology,” Harper said, “includeincreased thermal resistance to prematurecure in hot fracturing fluids with reducedshut-in times; increased cyclic loading resist-ance to meet well production demands; andincreased compatibility with all frac fluids.

“Also, G2 coatings do not adversely affectcrosslinkers and breakers, and they are unaf-fected by high-pH frac fluids.”

Big research, big reachIn addition to the company’s range of cur-

able coated proppants, Santrol also manufac-tures tempered proppants to produce lowfines percentages on crushing while main-taining high conductivity. These productsalso are layered with multiple resins toenhance their toughness.

Another Santrol downhole product,BioBalls, is an aqueous soluble perforationball sealer in its third iteration, Harper said.

“They are composed of the organic compound collagen, which is the mostfibrous protein found in living organisms,”he said. “Yet, unlike conventional rubber ball sealers, which are difficult to remove or drill out, BioBalls dissolve in any aqueous-based fluid, and the dissolution rate can be determined by adjustments influid pH and temperature.”

The newest BioBall product has highmechanical stability, superior high-pressureperformance and improved seating efficiency,Harper said. They can withstand differentialpressures in excess of 5,000psi and are rou-tinely tested to 3,000psi for quality control.

“Customers can be confident that BioBalls deliver maximum perforation diversion,” he said.

Santrol’s parent company, FairmountMinerals, is a diversified mining group, mar-keting resin-coated and raw sands to a variety

of industries, principal among which is theoil and gas extraction market.

In addition to the one at its Fresno site, where a full team of research chemistsworks on perfecting new products andimproving existing ones, Santrol has resin-coating plants in Roff, Okla.; Troy Grove, Ill.;Bridgman, Mich.; Monterrey, Mexico; andFredericia, Denmark. The plants operateunder ISO 9000 regulations. The companyalso controls and owns its own mines inWedron, Ill.; and Maiden Rock, Wis.; and hasan extensive network of rail-linked distribu-tion sites spread strategically in the UnitedStates, Canada and Mexico. ▲

37

SantrolP.O. Box 6392727 FM 521

Fresno, TX 77545Tel: (281) 431-0670Fax: (281) 431-0044

Web site: www.santrol.com

Page 37: Conductivity Endurance, Halliburton

38 CONDUCTIVITY ENDURANCE

COMPANY LISTINGS

BORDEN CHEMICAL INC.Implied vs. Applied Fracture ConductivityThe stimulation industry is reconsidering the true nature of fracture conductivity technology – and how it can improveand maintain that technology.

SAINT-GOBAIN PROPPANTSInnovative Particle Size Distribution and Higher Strength Yield Higher Fracture ConductivitySaint-Gobain Proppants concentrates on strength and innovation to deliver higher conductivity and value to thehydraulic fracturing industry.

MAGNABLEND INC.Filling the Bill for Custom-made Fracture Treatment ChemicalsTexas company helps develop, manufacture and blend several Expedite proppant flowback control products.

RHODIAMerging Worldwide Resources to Solve R&D Partners’ NeedsNew well conductivity enhancement services benefit from cross-fertilization among widespread labs and production sites.

NALCO ENERGY SERVICES DIVISIONResearch and Development Partnerships Help Drive Oilfield SuccessForging cooperative relationships with service providers creates teamwork to supply much-needed formation-level chemicals.

CARBO CERAMICS INC.Designing Fractures for Realistic Downhole Demands With a staff of field-proven petroleum engineers, a manufacturer works with customers to select the ideal proppant foreach stimulation treatment.

ECONOMY POLYMERS AND CHEMICALSKeeping an Eye on the Future for Polymers in Well Treatment FluidsHouston company raises the bar for guar-based products and works toward adding powder only for ‘on-the-fly’ fracfluid preparation.

SANTROLAn Intelligent Alternative in Combating Proppant Back-productionMultiple coats of uniquely formulated curable resin protect sand and ceramic propping materials from flowback andembedment, and greatly enhance conductivity and crush resistance.

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© 2005 Halliburton. All rights reserved.

Any frac job will boost your production

tomorrow. But what about 6 months from now?

How do you keep that post-frac flow and

maximize total production over the life of the

well? That takes Conductivity Endurance

technology from Halliburton.

It can triple your well’s total production—by

making your post-fracturing flow rates last

much longer. It works by keeping formation

fines from clogging the pores in your proppant

pack. Minimizing the effects of stress cycling.

Keeping the channels open. Keeping the

hydrocarbons flowing. Proven effective in

hard rock and soft.

To see the proof and learn about how

Conductivity Endurance can help you finish

strong, visit myHalliburton.com.

Halliburton has the energy to help.

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HALLIBURTON

Production Optimization