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JPT NOVEMBER 2006 57

In the Belank field, reservoir temper-atures average 315F and reservoirsections are 3,500 to 4,500 ft drilledhorizontally. A low-solids, brine-basedreservoir drilling fluid was requiredbecause the wells use premium screensfor sand control. Six wells were drilledwith the sodium formate-based reser-voir-drilling and completion fluids. Theparticle-size distribution and concentra-tion of the calcium carbonate (CaCO3)

bridging solids were monitored closelywhile drilling to ensure that filter-cakequality was not compromised.

IntroductionThe Belanak field is an oil-produc-ing field off the coast of Indonesia.Reservoir temperatures average approx-imately 315F. Six horizontal-well com-pletions were planned from the BelanakA platform. A water-based drilling fluidwas selected for drilling the 81/2-in.horizontal reservoir sections, some aslong as 4,500 ft and many with tortuous

well paths. The bottomhole temperature(BHT) exceeded the temperature rangeof conventional water-based reservoir-drilling-fluid components. In addition,the remoteness of the platform fromthe supply base and the limited supplyof drill water at the supply base weremajor issues. As a result, laboratorywork on the drilling-fluid design hadto consider supply-chain limitations as

well as the technical issues that usuallydominate fluid design.

Fluid design focused on the following. Developing a drilling fluid that

would be stable under long-term expo-sure to temperatures as high as 315F.

Determining the minimum con-centration of CaCO3 bridging agentrequired to generate a clean, treatablefilter cake without compromising filter-cake quality.

Identifying a suitable scale inhibitorto prevent precipitation-related forma-tion damage if the limited water supplyforced the completion brine and drill-ing fluid to be mixed with seawaterinstead of drill water.

Laboratory TestingBase-Fluid Selection. Discussion be-tween the operator and fluids providerresulted in agreement that the fluidformulation not only should be compat-ible with the sand-screen completion,but also maintain fluid-loss-control and

rheological properties for a minimum of48 hours exposure to BHT. Both water-based and nonaqueous-based formula-tions were considered.

Use of natural polymers, such asxanthan gum and starch, for fluid-losscontrol and viscosity was consideredadvantageous because of the ability toremove them chemically once the wellwas completed. However, drilling flu-ids made with xanthan and starch canbegin to exhibit property degradationfrom prolonged exposure to tempera-tures greater than 250F.

The required density was determinedto be 9.8 to 10.5 lbm/gal. Three base fluidswere tested: potassium chloride, sodiumchloride, and sodium formate. Thesebrines were selected for economic viabil-ity, ease of logistics, and in the case ofsodium formate, technical performance.

Fluid Optimization. Extensive labo-ratory testing was conducted over a

2-year period to determine the optimalbrine-based fluid that would be ther-mally stable to 315F and also wouldbe tolerant of drill solids. The resultsof the initial performance tests clearlyidentified the sodium formate-basedfluid as the most stable after prolongedheat aging at 315F. As a result of thesetests, sodium formate was selected asthe basis for the reservoir drilling fluid.All subsequent laboratory testing was

conducted with sodium formate.Formate-based brines were first

recognized as having the ability toextend the thermal stability of naturalpolymers in the late 1980s and early1990s. Their first applications in thefield were in the early 1990s, and theiruse as the basis of reservoir-drillingand completion fluids has becomewidespread since then. Their abilityto preserve conventional polymers attemperatures greater than 300F, andin some cases up to 400F, has beenthe primary reason for their selection.

A comparative analysis betweenxanthan gum and schleroglucan wasconducted to determine the optimumviscosifier for the fluid. Xanthan gumperformed substantially better in regardto thermal stability and was chosen asthe primary viscosifier for the system.

A minimum of 30 lbm/bbl of sodiumformate was maintained in the fluidfor thermal stability. Laboratory test-ing verified that 15 lbm/bbl of sodiumformate was not sufficient to maintainhigh-pressure/high-temperature (HP/HT) fluid-loss control.

Solids-contamination testing wasconducted to determine the toleranceof the fluid for contamination with30 lbm/bbl of drill solids; 20-lbm/bblof formation sand and 10 lbm/bbl ofshale were used for the drill solids.Addition of the drill solids to the fluiddid not have any adverse effect on thefluid rheology, but it did affect theHP/HT fluid loss significantly.

This article, written by AssistantTechnology Editor Karen Bybee, con-tains highlights of paper SPE 98347,

Formate-Based Reservoir-Drilling FluidResolves High-Temperature Challengesin the Natuna Sea, by R.J. Bradshaw,SPE, R.M. Hodge, SPE, and N.O.Wolf,SPE, ConocoPhillips Co., and D.A.Knox, SPE, C.E. Hudson, SPE, and E.Evans,SPE,M-I Swaco,prepared for the2006 SPE International Symposium andExhibition on Formation Damage Control,Lafayette, Louisiana, 1517 February.

Formate-Based Reservoir-Drilling Fluid MeetsHigh-Temperature Challenges

DRILLING AND COMPLETION FLUIDS

For a limited time, the full-length paper is available free to SPE members at www.spe.org/jpt. The paper has not been peer reviewed.

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CaCO3. CaCO3 was selected as thebridging agent because of the broadrange of particle-size-distribution blendsavailable to generate a thin, tough filtercake, and because the filter cake couldbe dissolved with acid once the wellwas completed. Laboratory testing andfield experience concluded that a load-ing of 50 to 60 lbm/bbl would provide

a high-quality, low-permeability filtercake. However, the quantities of CaCO3required to build a reservoir-drillingfluid with this CaCO3 concentration forthe Belanak development would haveplaced extreme pressure on the supplychain and were considered impractical.

Laboratory work to optimize the solidsloading focused on formulating a drillingfluid that would generate a good-qualityfilter cake with the minimum concentra-tion of CaCO3 and a moderate drilled-solids concentration. Because of the vari-able pore structure through the reservoir,

the particle-size distribution of the bridg-ing agent must have the ability to bridgea wide range of pore sizes. The CaCO3blend used was selected on the basis ofideal packing theory and was validatedwith extensive fluid-loss testing.

The objective of the testing was toformulate a fluid with a fluid loss of lessthan 12 mL after 30 minutes at 315Fand 200-psi overbalance with a spurtloss of less than 2.0 mL. Laboratorytesting identified that a fluid with a45-lbm/bbl CaCO3 loading would meetthe required specifications.

Drilling ExperienceProperties and performance of the fluidwere monitored closely while drillingthe reservoir sections to ensure thatfluid behavior was in line with expecta-tions. A laboratory technician was sentto the rig to perform on-site fluid test-ing for each 200-ft drilled interval. Thisgave mud engineers the time to man-age and maintain the system withinspecifications. Continuous monitoringensured a more uniform filter cakethroughout the horizontal section.

Particle-Size Distribution. Particle-size-analysis results were used todetermine the effect of drilling onparticle-size distribution. Particle-sizedistribution varied as drilling beganand after each addition of fresh res-ervoir-drilling fluid. Most notable is

that there appears to be no discernableincrease in the fine material caused byCaCO3 grinding while drilling the longhorizontal section. However, there is arapid decrease in the coarse end of theparticle-size distribution (most nota-bly at 10,300 and 11,300 ft). Thesedecreases in the coarse fraction gener-ally can be attributed to removal of

the larger-sized particles by the solids-control equipment.

Hole Cleaning. During well planning,it was established that good hole clean-ing in the long horizontal sectionscould be a problem. Hydraulics model-ing indicated that high pump rates andgood pipe rotation would be requiredto prevent cuttings beds from formingin the low end of the well. Despite thethermal stabilizing properties of thefluid, some thinning was seen on pro-longed exposure to BHT. Increasing the

low-shear-rate viscosity (LSRV) of thedrilling fluid from 40,000 to 60,000 cphelped improve hole cleaning, as didpumping occasional low-viscosity/high-viscosity sweeps.

Additive Consumption. Maintainingfluid-loss control within specificationwas easily attainable, indicating that thebase fluid was stabilizing the starch-based fluid-loss-control agents. Spurtloss increased intermittently, but thiswas resolved by addition of coarse-gradeCaCO3.

Fluids engineers at the rigsite main-tained a theoretical fluid compositionon the basis of a mass balance of drymaterials and premix added and fluidlost by various means. The fact that thestarch remained approximately constantthroughout the drilling of each wellindicates that the starch was being stabi-lized presumably by the combination offormate and other chemical stabilizers.The xanthan content at total depth (TD)typically was in the 2.0- to 2.5-lbm/bblrange, whereas the premix from the liq-uid mud plant contained approximately

1.25 to 1.5 lbm/bbl. Part of the differ-ence may be explained by the need toincrease polymer concentration to attainthe revised 60,000-cp LSRV.

Completion Experience. Once drilledto TD, the wells were completed witha standalone sand screen. Once the

well was drilled and the hole condi-tioned, the open hole was displacedto a solids-free version of the reser-voir-drilling fluid to ensure that goodfluid-loss control was maintained whilepulling out the drillstring and pick-ing up the completion string. Fielddata from previous wells demonstratedthat the solids-free pill had the ability

to heal (seal) ruptures in filter cakecaused by tool movement across theopen hole.

Once the casing had been scrapedclean, the casing was displaced to com-pletion brine with a combination ofsolvent and surfactant wash pills. Thelower completion then was assembledand run in the hole. Once the lowercompletion was at TD, the well wasdisplaced to completion brine, then theopen hole was displaced to the chelat-ing-agent breaker solution. The breakersolution was allowed to soak the filter

cake while the wash pipe was pulled, theupper completion was run, and the wellwas brought on production. This expo-sure time ranged from 15 to 110 days.

Of the six wells completed, fiveare producing at expected rates. Thesixth well is not producing to expec-tations, and the reasons for this areunder investigation.

ConclusionsThe successful drilling and comple-tion of these wells is attributable tothe extensive front-end engineering of

the reservoir-drilling fluid. The logisti-cal limitations imposed by the remotelocation were addressed, and a fluidformulation was found that did notcompromise technical performance.

Use of formate salt as a thermal sta-bilizer of conventional water-based res-ervoir-drilling-fluid polymers helped toensure that a drilling fluid could beformulated to drill long horizontal open-hole sections without the use of synthet-ic polymers or nonaqueous-based fluid.Because of this, the filter cake could beremoved effectively with a less-aggres-

sive, noncorrosive breaker solution.Monitoring the particle-size distri-

bution at regular intervals helped toensure that the reduced CaCO3 loadingimposed by the logistical constraintsdid not affect filter-cake quality or thefluid-loss properties of the reservoir-drilling fluid adversely. JPT