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B10.1 Introduction ...............................................................................................................................................................2B10.2 Mechanisms of formation damage, and how they apply to formate brines .........................................2

B10.2.1 Fluid-fluid incompatibilities ..................................................................................................................... 2B10.2.2 Rock-fluid incompatibilities ..................................................................................................................... 3B10.2.3 Solids invasion ............................................................................................................................................. 3B10.2.4 Phase trapping / blocking ....................................................................................................................... 3B10.2.5 Chemical adsorption / wettability alteration ..................................................................................... 4

B10.2.6 Biological activity ........................................................................................................................................ 4B10.3 Reservoir condition coreflood testing with formate brines ......................................................................4B10.3.1 Formate testing artifacts and pitfalls .............................................................................................. 4B10.3.2 How to perform a coreflood test on a formate brine or drilling fluid ..........................................7

B10.4 Formation water compatibility testing with formate brines ......................................................................9B10.4.1 Scale prediction using modeling software packages .................................................................10B10.4.2 Scale prediction using laboratory bottle testing .............................................................................11

B10.5 Comparison of formate brines with other high-density brines .................................................................11B10.5.1 Comparison with calcium bromide / calcium chloride brines .................................................... 11B10.5.2 Comparison with zinc bromide brine .................................................................................................12B10.5.3 Comparison with potassium hydrogen phosphate brine ............................................................12

B10.6 Comparison of formate drilling fluids with solids-weighted drilling fluids ...........................................13B10.7 Published field cases.............................................................................................................................................16

B10.7.1 Oriente, Ecuador, 1997 ..............................................................................................................................16B10.7.2 NAM, offshore Netherlands, 1997 .........................................................................................................19

B10.7.3 BP, Harding Field, offshore UK, 1999.....................................................................................................19B10.7.4 ExxonMobil, HPHT gas fields, Germany, 1996 2000 ...................................................................20B10.7.5 Western Canada, 1999 2004 .............................................................................................................20B10.7.6 Statoil, Huldra Field, offshore Norway, 2001 2003 .................................................................... 20B10.7.7 Shell, Brigantine Field, offshore UK, 2000 2001 .......................................................................... 22B10.7.8 OMV, Miano and Sawan Fields, onshore Pakistan, 2001 ..............................................................22B10.7.9 Norsk Hydro, Visund Field, offshore Norway, 2002 ......................................................................22B10.7.10 BP, Devenick Field, offshore UK, 2001 .................................................................................................23B10.7.11 Saudi Aramco, Pre-Khuff, Saudi Arabia, 2004 ................................................................................23B10.7.12 Petrobras, Manati, Brazil, 2008 ...........................................................................................................24

B10.8 Analyzes of production data from fields drilled and completed with formate brines ..................................25References ......................................................................................................................................................................................................27

The Formate Technical Manual is continually updated.To check if a newer version of this section exists please visit formatebrines.com/manual

SECTION B10COMPATIBILITY WITH THE RESERVOIR

NOTICE AND DISCLAIMER. The data and conclusions contained herein are based on work believed to be reliable; however, CABOT cannot and does not guarantee that similar resultsand/or conclusions will be obtained by others. This information is provided as a convenience and for informational purposes only. No guarantee or warranty as to this information, orany product to which it relates, is given or implied. CABOT DISCLAIMS ALL WARRANTIES EXPRESS OR IMPLIED, INCLUDING MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE AS TO(i) SUCH INFORMATION, (ii) ANY PRODUCT OR (iii) INTELLECTUAL PROPERTY INFRINGEMENT. In no event is CABOT responsible for, and CABOT does not accept and hereby disclaims liability for,any damages whatsoever in connection with the use of or reliance on this information or any p roduct to which it relates.

2013 Cabot Corporation, MA, USA. All rights reserved. CABOT is a registered trademark of Cabot Corporation.

VERSION 2 09/13

C O M P A T I B I L I T I E S A N D I N T E R A C T I O N S

F O R M A T E T E C H N I C A L M A N U A L C A B O T
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B10.1 Introduction

The introduction of low-solids drill-in and completionfluids based on halide brines in the 1970s was a majorstep forward in reducing damage to reservoirs andaccessing the full economic benefits of horizontalopen-hole completions. However, the brines were not

suitable for all wells. For instance, it soon becameapparent that the higher-density bromide brines had anumber of shortcomings as drill-in fluids. One of theseis incompatibility with reservoirs sensitive to fluidscontaining divalent cations. In this context, sensitivereservoirs include those with soluble SO4or HCO3in theirformation waters and those containing H2Sin their gasphase. Also, it was not possible to make a thermally-stable drilling fluid from halide brines, meaning thatthey could not be used to drill high-angle HPHT wellscompleted in open hole for maximum production rates.

This technology gap was filled by the development andproduction of formate brines [1][2], which differed frombromide brines by being compatible with all types ofreservoirs [3][4].

Shell and Mobil were the first companies to proveand use low-solids formate brines as non-damagingreservoir drill-in and completion fluids [5][6]. Brinesbased on sodium and potassium formate are nowroutinely used as drill-in and completion fluids in fielddevelopments where fluid density requirements do notexceed 1.60 g/cm3/ 13.35 lb/gal, e.g. see [7][8]. Statoilbecame the first user of cesium formate brine as drill-inand completion fluid in the Huldra gas / condensatefield development in January 2001 [9]. Since then,cesium formate brine has been used as drill-in fluidby Statoil, BP and Petrobras in 30 deep-gas wellconstructions, including five wells drilled in MPD mode.In all cases, cesium formate brine was also used as thewell-completion fluid.

Formate brines have revolutionized well constructionprojects by allowing operators to drill and completelong high-angle open-hole reservoir sections that canefficiently deliver recoverable hydrocarbon reserves.

Examples of this are the Huldra and Tune fields, whereformate brines have been used as combined drill-inand completion fluids [10]. These wells have deliveredalmost 100% of recoverable gas and condensatereserves in only ten years.

Formation damage has never been reported in anywells drilled or completed with cesium formate brine.In fact, Cabot is aware of only one instance whereformation damage has been reported from wells drilledand / or completed with formate brines since formates

were first introduced in the early 1990s. In this onecase, the cause of the damage was traced to an overlygenerous addition of carbonate / bicarbonate pH bufferand the problem was simply mitigated by reducing theamount of carbonate in the brine [11].

This section of the Formate Technical Manual outlinesknown mechanisms / causes of formation damageand explains why formate brines are unlikely to causeit. The two common methods for testing formationdamage potential of oilfield brines and fluids are thendiscussed. These are standard reservoir conditioncoreflood testing and formation water compatibilitytesting. In addition, the performance of some standardscale prediction software packages commonly used topredict scaling with reservoir water is compared. Thesection also includes the results of some formation

damage tests with other oilfield brines, and finally, theexcellent field performance of formate brines is reviewed.

B10.2 Mechanisms of formation damage, andhow they apply to formate brines

The apparent absence of formation damage in reservoirscontacted by formate-based fluids indicates that thesefluids cause minimal permanent changes in the relativepermeability of the reservoir to hydrocarbons. Toachieve this effect, formate brines and additives musteffectively leave the rock matrix, porosity, pore-liningminerals, and residual reservoir fluids in near-nativecondition following their removal from the near-wellborearea as a result of production. Alternatively, if theydo cause a degree of formation damage, it must betemporary or they must simultaneously stimulate thereservoir in such a way that overall measured skin isrelatively low.

In order to understand how formates can have thiseffect, it is instructive to look at the known causes offormation damage and how they might apply to fluidsformulated with formate brines. Bennion and Thomas [12]have identified the following causes of formation

damage mechanisms in well construction andintervention operations as detailed below.

B10.2.1 Fluid-fluid incompatibilities

Adverse reactions between invading drilling or

completion fluid filtrates and the in-situ fluids (oil or

formation brine) to form scales, insoluble precipitates,

asphaltic sludges, or stable emulsions [12].


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Formate brines contain nothing that cause adversereactions with formation fluids. Both alkali metalcations and formate anions are monovalent andvery soluble, so any precipitates that could formare water-soluble salts. However, levels of divalentcations in formation waters are not high enough to form

such precipitates with formate brines under reservoirconditions. Formate brines are free from surfactants andmultivalent ions, making it impossible for them to createstable emulsions or water-insoluble scales.

Since incompatibility with formation water is a commonproblem with other heavy-brine systems used aswell-construction fluids [13], this topic is discussed inmore detail in B10.4. In addition, B10.4 covers possibleincompatibility that can originate from carbonate ionsnormally added to formate brines as a pH buffer.

B10.2.2 Rock-fluid incompatibilitiesAdverse reactions between invading water-based

filtrates and sensitive pore-lining clays leading to

fines mobilization and associated reductions in

near-wellbore permeability [12].

Formate brines are known for their ability to stabilizeshale (see Section B11, Compatibility with Shale). Thiscan be attributed to their very low water activity and thepresence of beneficial ions, such as potassium, cesium,and formate. Based on this, formate brines are notexpected to cause any formation damage of this type.

Pore-lining smectite clays can swell and disintegratewhen contacted by a filtrate fluid that has lowersalinity than the native reservoir brine. As formatebrines usually contain clay-swelling inhibitors (KandCsions) and are rarely used at salinities lower than theformation water, it seems unlikely that they cause thistype of formation damage.

Deflocculation of certain types of pore-lining clays isknown to be another cause of formation damage inlow-salinity brines [14]. When low-salinity brines invadethe reservoir, the pore-lining clays undergo a process

of separation and movement through the pore system,leading to bridging and plugging of pore throats. Formatebrines are normally used at high salinity, so this form ofdamage mechanism is also highly unlikely to occur.

In 1997, Bishop [15] found that certain high-salinitybrines can cause formation damage by flocculatingkaolinite-type clays. Bishop investigated the differencebetween saturated NaClbrine and potassium formatebrine at the same density. He found that NaClbrinecaused severe formation damage in his coreflood tests

(74% reduction in return permeability), whilst in thepotassium formate brine this was significantly reduced(15% reduction in return permeability). Whether kaoliniteflocculation occurs or not depends on the criticalconcentration of electrolyte required for flocculation, i.e.the flocculation value. The flocculation value is known

to be lower for brines containing divalent ions than forthose based on monovalent ions, something that favorsformates over alternative high-density halide brines(CaCl2, CaBr2, and ZnBr2), which all contain divalent ions.

B10.2.3 Solids invasion

Penetration and blocking of reservoir pore throats by

solids suspended in drilling and completion fluids.

The permanent lodging of solids in the formation pore

throats can severely reduce permeability [12].

Solids invasion is a common source of formation

damage in conventional drill-in fluids containingsolid-weighting agents, such as barite [16].

As formate brines can provide the full density requirementsof drilling and completion fluid, use of intractable solid-weighting agents, such as barite, can be avoided. Ifsolid particles are required in the brine as filter cake orbridging agents, they can be screened and selectedon their ability to minimize formation damage potential.When solids are required as filter cake material informate-based drilling fluids, it is common practice to usesized calcium carbonate particles. Calcium carbonateused as bridging material is advantageous as it can besized to fit the pore throat. Furthermore, filtercakes liftoff easily, and are acid soluble.

There have been cases, e.g. in Alaska, where formatebrines have been successfully used as entirely solids-free drill-in fluids, relying solely on viscosifying additivesto provide fluid-loss control [17]. In contrast to otherhigh-density brines (CaCl2, CaBr2, ZnBr2), formate brineshave the advantage of being compatible with polymersto high temperatures, allowing formulation of solids-freedrill-in fluids for all well conditions.

B10.2.4 Phase trapping / blocking

Invasion and permanent entrapment of oil or

water filtrates in the near-wellbore region. These

trapped fluids can substantially reduce the relative

permeability of the reservoir to hydrocarbons [12].

Comparisons of logging data obtained during (LWD)and after (wireline log) drilling with formate brinesshow that formate filtrates are mobile and appear todisappear quite quickly from the near-wellbore area inlow-permeability gas reservoirs [18]. A suggestion


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of formate brine retention has been obtained in acoreflood test with very low-permeability (0.35 mD)sandstone core using gas production phases saturatedwith water at room temperature, but this effect isthought to be a laboratory artifact [19]. After changingover to a HPHT gas-humidifying system that saturates

the production gas with water at test temperature andpressure, coreflood test results with cesium formatebrine have been much better [19]. This is explained inmore detail in B10.3.1 below.

B10.2.5 Chemical adsorption / wettability alteration

The alteration of the reservoirs permeability to

hydrocarbons as a result of changes in the wettability

of the pore walls and throat surfaces[12].

Conventional drilling muds and completion fluids maycontain surface-active chemicals, e.g. emulsifiers,

oil-wetting agents, and corrosion inhibitors, which havebeen deliberately added to improve fluid performanceand / or mitigate performance deficiencies. Absorptionof these chemicals onto reservoir rock can changewettability and so alter permeability to hydrocarbons.

Formate brines have no surface activity, and are freefrom surface-active agents, so they are unlikely tocause any changes in the wettability of reservoir rocks.

B10.2.6 Biological activity

Reduction of formation permeability to hydrocarbons

as a result of microbial activity promoted by drilling or

completion operations [12].

Drilling and completion operations can introduce newmicroorganisms into reservoirs, or stimulate activity ofnative microorganisms already present in the reservoir.Conventional drilling fluids contain nutrients thatencourage growth of microorganisms.

Formate brines have low water activity and are naturallybiostatic or biocidal at densities higher than 1.05g/cm3/8.76 lb/gal (see Section A12, Biodegradability andBiocidal Properties). For this reason, they do not

biodegrade or support any form of microbial growth,either at the surface or downhole, when in theiractive (concentrated) form. Reservoir waters actuallycontain some formates [20], indicating that indigenousmicroorganisms are limited (probably by lack of anotheressential nutrient) in their ability to use formates as theircarbon and energy source.

B10.3 Reservoir condition coreflood testingwith formate brines

The aim of coreflood (or return permeability) testing is tostudy the effect of well construction, intervention andstimulation fluids on the permeability to hydrocarbonsof reservoir materials surrounding the wellbore [21].

The more sophisticated laboratories use reconditionedreservoir core plugs and simulated reservoir fluids andgases. They also conduct the tests at close to reservoirpressure and temperature for realistic time periods.The relative permeability of the reconditioned plugto a specific hydrocarbon phase is measured after asimulated drawdown to remove the filtrate and filter cakeresidues introduced by the test fluid.

B10.3.1 Formate testing artifacts and pitfalls

In their most advanced form, conducted at reservoirconditions with all fluid / gas phases present, coreflood

tests can provide a lot of useful information about thepotential of a fluid to cause formation damage arounda wellbore. However, the process of trying to simulatethe creation of a borehole, followed by well productionstart-up, under reservoir conditions in the laboratoryis quite difficult. Yet failure to precisely reproduce theactual reservoir environment in coreflood tests cangenerate wholly misleading results and conclusions.

Byrne et al. published a review of more than 40 coreflooding tests carried out by Corex Ltd. on formatebrines from 1996 to 2001 for a variety of operators [22].The tests had been conducted on many differentreservoir cores and some of the formation waters werehighly saline with salt concentrations greater than200,000 ppm.

Although the conclusions of this study are mainlypositive, especially in the case of gas reservoirs, thereare quite a few cases where reduction in permeabilityhas been experienced in formate brine laboratory tests,whilst very good production rates were obtained in thefield (Rhum [23][24], Huldra [9], Kvitebjrn [18]). Due todiscrepancies between results of standard corefloodtesting and field experience, further research on

coreflood testing in formate brines has been conducted.From this, we conclude that the following laboratoryartifacts / pitfalls can contribute to erroneous andmisleading test results for formates as detailed below.

Drawdown with dry gas

Evidence of formate filtrate residues retained insidelow-permeability gas reservoir core plugs hassometimes been found at the end of the test drawdownphase. Natural gas in its native environment is inthermodynamic equilibrium with the connate


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17.9

18.4

18.9

19.4

19.9

20.4

2.15

2.20

2.25

2.30

2.35

2.40

2.45

0 1 2 3 4 5 6 7

Den

sity[lb/gal]

Density[g/cm3]

Time [hours]

Brine at 65C, dry gas

Brine at ambient temperature, dry gas

liquid-water phase and is saturated with water vaporat reservoir conditions. Full water saturation of gasesused in laboratory coreflood tests may not always beachieved, and it is known that use of dry gas in suchexperiments can artificially reduce core permeability togas by dehydrating and crystallizing any brine residues

left within the cores.

This problem of permeability impairment, as a resultof water vaporization by unsaturated gas, mightbe expected to become more acute or evident inlaboratory tests with high-pressure high-temperature(HPHT) reservoir cores containing high-salinityformation brine and high-density drilling / completionbrine filtrates. These brines may contain saltconcentrations that are already close to saturationlevels and are therefore more susceptible to significantviscosity gain or crystallization by dehydration.

Unfortunately a lot of the earlier coreflood testsperformed with formate brines used dry nitrogen gasto simulate the reservoir gas. Formate brine retentionwas identified as the main cause of permeabilityloss in these tests [22]. A remarkable artifact createdby use of dry gas was seen in a coreflood test withformate brine at 200C / 392F. A return permeabilityof>100% of the original permeability was measuredin the core sample under reservoir conditions, butwhen the core was cooled to 60C / 140F some saltcrystallization occurred within the core and causedsevere permeability reduction. This artifact was

created by cooling brine filtrate residues, which hadbeen dehydrated by using gas that had not been watersaturated at test temperature.

Cabot has carried out some simple tests to look at theeffect of flowing dry nitrogen gas through formate

brine [25]. A 2.20 g/cm3/ 18.3 lb/gal cesium formatesample was heated to 65C / 149F and purged withdry nitrogen gas. Brine density was measured as afunction of purging time. The results are shown inFigure 1. As can be seen, even at this rather low testtemperature (65C / 149F), a significant increase in brinedensity occured as a result of dehydration by dry gas.

A more sophisticated study was carried out by Downs [19]to investigate the effect of gas humidification levelson gas permeability of North Sea HPHT reservoir corematerial exposed to high-density cesium formate

brine under HPHT conditions in laboratory corefloodingexperiments. Results from the coreflooding experimentsat 200C / 392F indicate that full HPHT-humidificationof the gas phase resulted in higher gas returnpermeability when compared with a test using gashumidified at room temperature and high pressure. Thedifference can be explained by studying the equilibriumwater content of nitrogen gas as a function of pressureand temperature, shown in Table 1. High pressure (34MPa / 5,000psi) gas saturated with water at roomtemperature contains almost 400 times less waterthan the same gas saturated at 200C / 392F.This means that gas saturated at room temperature

Figure 1Density of 2.20 g/cm3/ 18.36 lb/gal cesium formate brine as a function of time while sparging with nitrogen gas. The

significant brine-density increase seen in the blue curve is a result of purging dry gas through formate brine held at 65C / 149F.


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can pick up a lot of water while passing through thebrine-saturated core under HPHT conditions during thedrawdown phase. This finding highlights the importanceof ensuring that any gases used in HPHT coreflood tests

are fully saturated with water vapor at test temperatureand pressure. It seems likely that the impact of gashumidification levels is amplified in very low-permeabilitycores subjected to high drawdown pressures.

Gravity drainage

As mentioned previously, microscopic examinationof low-permeability gas reservoir cores flooded withformate brines can sometimes show evidence ofretained formate filtrate within the cores after cleanupby drawdown. However, comparisons of logging dataobtained during drilling (with LWD) and after drilling (withwire line) with cesium formate brine show that formatefiltrates in gas reservoirs are mobile and replaced bygas over time [18]. It is thought that movement offormate filtrates away from high-angle wellbores is theresult of gravity drainage. Unfortunately this drainagephenomenon cannot be easily reproduced in laboratory-scale linear coreflood tests with tiny 5 cm core plugs.This inability to simulate gravity drainage effects inthe laboratory may impact negatively on the results ofcoreflood tests with heavy formate brines.

Use of unrealistic gas phase

Return permeability tests on gas reservoir cores should

use realistic gas compositions. The compositions shouldinclude CO

2and H

2Sif they are present in the reservoir.

The presence or absence of these acid gases can impactsignificantly on results of return permeability tests. Forinstance, formate brines can contain soluble cesium,potassium, or sodium carbonate, which are added tothe fluid as part of the pH-buffering package. Althoughunseen in coreflood tests, buffered formate brines canpotentially form calcium carbonate precipitates whenmixed with reservoir waters containing a lot of solublecalcium. In a case where there is reason to believe that

carbonate in the buffer can precipitate out with calciumfrom formation water, one should consider reducingthe amount of soluble carbonate in the fluid. Solublecarbonate is added to formate brines so that fluids can

withstand large amounts of CO2ingress. A large amountof buffer is therefore only needed in brines used inreservoirs with significant levels of CO

2gas. In such a

reservoir environment, with a lot of acid gas present,it is doubtful that calcium carbonate precipitate canform anyway. Furthermore, any calcium carbonate thatmight form is likely to dissolve when the well is put onproduction and CO2-containing gas flows through thepore spaces. In reservoirs without CO2, the buffer can bereduced to a much lower level and soluble bicarbonateused rather than carbonate.

H2Sin the gas phase is not thought to have any

adverse effects on formate brine, but it causes zincsulfide to precipitate from zinc bromide brine. Ifthe purpose of a coreflood study is to compare theperformance of formate brine with zinc bromide brinein a reservoir containing H2S, then H2Sshould alwaysbe included in the test gas.

Duration of drawdown

In the field, it is observed that gas / condensate wellsdrilled and completed in open hole with formate brinestake up to seven hours to fully cleanup as they aregradually beaned up during production tests.

During the cleanup period, the well unloads any brinepreviously lost to the formation or left under the packer,and flow channels are created in the filter cake liningthe borehole wall. Full cleanup is indicated by steadywellhead pressure, steady hydrocarbon flow ratesand absence of any further brine production. In thewell clean up shown in Table 2, the eventual gas flowrate or flux at steady-state production was around 0.5liters per square centimeter of borehole surface perminute as measured at the surface. Full cleanup takes

Table 1 The equilibrium water content of nitrogen gas as a function of pressure and temperature.

(Source: AQUAlibrium 3.1 copyright 2006 FlowPhase Inc.)

Gas pressure(psi)

Equilibrium water content [ppm]

20C / 68F 75C / 167F 125C / 257F 175C / 347F 200C / 392F

14.7 23,165 381,987

100 3,479 56,997 342,427 500 768 12,145 71,895 275,272 476,445

1,000 432 6,543 37,914 143,983 250,102

2,000 267 3,743 20,865 77,429 133,911

3,000 212 2,803 15,125 55,984 94,429

5,000 185 2,324 10,415 36,631 62,114

8,000 25,799 43,125


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time because initially the gas tends to channel and fingerthrough paths of least resistance, by-passing some brinepresent in the least permeable areas of the reservoir.

In laboratory coreflood tests, it is important that testcores are subjected to realistic cleanup times underrealistic beaning up and draw-down conditions. Thisapplies particularly to time spent flowing the core at thehighest drawdown pressure where the highest gas fluxrates might be expected to achieve most efficient cleanup. Failure to do so can result in incomplete brine cleanup, high residual water saturations and unrealisticallylow return permeabilities to gas and condensate.

B10.3.2 How to perform a coreflood test on a

formate brine or drilling fluid

The recommended procedure for conducting a corefloodtest with formate brine on a core from a gas reservoir isshown in Figure 2.

When assessing return permeability results fromcoreflood tests conducted by other parties, always auditthe experimental procedures against this checklist:

Was real (target) reservoir core used? Each reservoir

has its own unique mineral, water and gas chemistrythat interact in their own special way with invadingfiltrates.

Was the core properly cleaned (to remove coringmud) and then reconstituted back to residual watersaturation with simulated reservoir water?

Was water composition a close match to reservoirconnate water sampled from earlier exploration andappraisal wells?

Was the core equilibrated at reservoir conditionsbefore testing?

Did original core permeability measured at reservoirconditions with gas or liquid phases closely resemblethe reservoir hydrocarbons? Was the gas humidifiedat HPHT? Was a low gas flow rate used to measurereturn permeability?

(For a completion brine) Was the core pre-flushedwith realistic drilling fluid (filtrate) under dynamic andstatic conditions to create a flushed zone?

Was the test fluid circulated past the core face for anumber of hours at realistic overbalance pressure?

Was the test fluid then left static, at balance orclosed in, under reservoir conditions for a number ofdays to allow hydrothermal chemistry to work?

Was the core then subjected to a realistic draw-down regime, simulating the planned drawdown orbeaning-up operation to be used in the field?

Was the back-flowing gas or liquid flowed at eachdrawdown pressure until stable flow had beenachieved?

Were at least 2,000 pore volumes of fluid or gasback-flowed through the core in total, to take thecore back to irreducible water saturation? Preferably,was flow maintained at maximum drawdown for atleast several hours?

Was the core's return permeability then measured

at low flow rate, under reservoir conditions, with thesame gas / fluid used to measure initial permeability?

If the reservoir contains CO2, did the test gas containroughly the same concentration of CO2? Be absolutelysure that lack of CO2does not impact test results.

Was the purpose of the test to compare cesiumformate with zinc bromide? If this was the intent,was a realistic amount of H2Sincluded in thedrawdown gas?

Table 2 Production start-up data from a North Sea HPHT well drilled and completed with screens in open hole with

cesium formate brine.

Elapsed time[hours]

WHP[bar]

Condensate[m3/day]

Water[m3/day]

Gas[MMm3/day]

Roxar[bar]

GOR Comment

0 247

2 286 0 630 0 660 Beaning up and unloading

4.5 508 537 0 0.9 660 Shut down for 30 minutes

5 511 623 258 1.5 660

6 520 660 10 1.4 660 2,181

7 520 632 0 1.4 660 2,278

8 521 608 0 1.4 660 2,366

9 521 618 0 1.4 660 2,330

10 521 639 0 1.4 660 2,253

11 521 615 0 1.4 660 2,340


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Figure 2Recommended procedure for coreflood testing of formate brines with gas.

Formation damage prediction by laboratory corefloodingRecommended test procedure for formate brines with gas

Select appropriate reservoir core sample and identify best sections to plug (by CT scan, etc.).

Drill core plugs, using clean mineral oil as drill lubricant.

Clean core plugs with solvents under mild conditions. Measure initial permeability and select suitable plugs for testing.

Carry out dry and cryogenic SEM to determine initial condition of core sample.

Prepare synthetic formation brine, matching composition of water sampled from the reservoir.

Prepare and humidify a gas composition matching reservoir gas. Ensure that gas is humidified under reservoirconditions. Use nitrogen gas if unable to handle hydrocarbon gases. If realistic amounts of CO2and H2Sare notadded to the test gas, ensure that this does not impact test results.

Prepare core sample to irreducible formation water saturation with humidified nitrogen gas by centrifuging for24 hours at 4C / 39F.

Determine effective permeability of plug to humidified gas* at ambient pressure and temperature,and low flow rate.

Load sample into core holder and increase pressure to overburden conditions.

Bring system up to test, i.e. reservoir conditions, and allow system to equilibrate.

Determine effective permeability to humidified gas* under reservoir pressure and temperature conditions information-to-wellbore direction.

Circulate test fluid (brine or mud) across sample wellbore face at overbalance, or inject brine at set flow ratefor 10 20 pore volumes of brine, in the wellbore-to-formation direction all at reservoir conditions. Recorddifferential pressure across the core as a function of time.

On achieving 10 pore volumes of filtrate volume losses, stop further flow and leave core sample to soak at testpressure and temperature for a static period of at least 48 hours.

Create drawdown pressure at the wellbore face, and increase in steps up to the highest level to be used inthe field during production cleanup, inducing a gas flow in the formation-to-wellbore direction to clean up thecore. Simulate, as far as possible, the drawdown ramping-up procedure to be used in the production start-

up program and use representative gas humidified at test conditions*. Maintain each drawdown pressureuntil gas flow through the core is stable, recording gas flow rates at each stage. Ensure core is subjected tomaximum drawdown pressure for at least two hours to simulate real production test conditions and createrealistic core dehydration.

If testing with mud, determine filter cake lift-off pressure.

Determine effective permeability of core plug to humidified gas* at reservoir pressure and temperature andlow flow rate in formation-to-wellbore direction.

Cool, depressurize core holder, and offload core sample. Photograph.

Centrifuge to irreducible fluid saturations under gas.

Determine effective permeability of plug to humidified gas* at ambient P/T and low flow rate**.

Take samples from ends (external and internal) of core plug for SEM analysis (normal and cryogenic) forevidence of changes in mineralogy, fluid distribution, and movement of pore-lining clays.

Carry out dry and cryogenic SEM to determine final plug condition.

* Gas must be humidified at temperature and pressure of the core, otherwise it dries out the core's inside and causes

brine crystallization. Always use realistic levels ofH2Sgas during comparison with zinc bromide brine. If CO

2can

make a difference to the chemistry inside of the core plug, it should be added to the test gas.

** Cooling and depressurization cause lab artifacts if any formate brine is still present in plug. Any measurements made

after cooling the plug are not representative of how the reservoir behaves with formate brine residues present.


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If the answer to any of these initial questions is "no"then the results were not obtained under realisticconditions and cannot be trusted to predict theoutcome of interactions between the well constructionfluid and reservoir. The results certainly cannot be usedto select the best well construction fluid for a high-cost

and / or high-value field development.

B10.4 Formation water compatibility testingwith formate brines

Formation waters are typically solutions of sodiumchloride containing varying and lesser amounts ofmultivalent solutes such asBa, Ca, Sr, Mg, Fe, HCO3, CO3,and SO4. In some North Sea HPHT fields, the solublemineral content of formation waters is as high as 400 g/L,mostly as NaCl, but with multivalent cation contents of30 40 g/L in some cases. When drilling or completion

fluid filtrates invade reservoirs containing residualformation water (typically at 20% v/v of pore space) thereis scope for chemical interactions between the two fluidsto create precipitates. The precipitates are placed in threegroups according to their ease of removal:

i. Water-soluble precipitates:Typically salts where atleast one monovalent ion forms when concentrationsof ions present in the blended solution exceed theirsolubility products. Examples of such precipitatesare NaCl, KCl,and K

2SO

4. These can be re-dissolved

by flushing with low-salinity water.

ii. Acid-soluble scales: Scales of divalent ions that aredissolved when contacted by acid. Examples of suchscales are CaCO3and MgCO3.

iii. Insoluble scales: Scales of divalent ions that areinsoluble in both water and acid. Examples of suchscales are BaSO4and SrSO4. Once formed in thereservoir, these scales are very difficult to remove.

Whether brine is likely to form scale or not dependson the nature and concentration of ions in the brine.Divalent halide brines containing high levels of Ca2+and

Zn2+form water-insoluble scales when contacted byformation waters containing soluble carbonate (CO

32-)

or sulfate (SO42-). Another example of multivalent brine

is potassium phosphate brine, which contains thetrivalent ion PO4

3-. This brine precipitates out water-insoluble scales when in contact with reservoir watercontaining even low levels of divalent cations, e.g. Ca2+,Mg2+, Fe2+.

Monovalent brines are brines comprising of onlymonovalent ions (cations and anions). Formate brines

are the only high-density monovalent drilling andcompletion brines in use today. Because they onlycontain monovalent ions, they can only form water-soluble precipitates of Group i type when mixedwith formation waters. Water-soluble salts that cantheoretically form with formate brines are salts of alkali

metal cations, Na, K, and Cs. All alkali metal salts arevery water-soluble and it is doubtful if any formationwater contains high-enough concentrations of anydivalent anions to form such precipitates. The otherwater-soluble salts that can precipitate are formate saltsof divalent cations, such as calcium and magnesiumformate (Ca(COOH)2and Mg(COOH)2). Such divalentformate salts are also quite soluble in water, and it isvery unlikely that any formation water is rich enough incalcium or magnesium to trigger such precipitation.

To verify this, testing was carried out on 2.20 g/cm3 /

18.36 lb/gal unbuffered cesium formate brine and a1.57 g/cm3/ 13.1 lb/gal unbuffered potassium formatebrine [26]. These unbuffered formate brines wereblended in several ratios with formation waterscontaining various amounts of calcium, and the resultingblends were monitored for signs of precipitation at threedifferent temperatures (20, 90, and 130C / 68, 194,and 266F) and several brine-to-formation-water blendratios. All samples were seeded with calcium formatecrystals to avoid super saturation. At the highesttemperatures (130C / 266F) both of these formatebrines were fully compatible with formation waterscontaining 40,000 mg/L calcium. A slight amount ofprecipitate was found with formation water containing50,000 mg/L calcium when formation water andformate brine were blended in a 50:50 ratio. At highertemperatures, solubility of calcium formate is evengreater and higher levels of calcium are tolerated.

If any formation water is so high in calcium that calciumformate can precipitate from concentrated formate brines,there is always an option to design less concentratedformate brines by altering formate brine composition. In acesium / potassium formate brine blend, this equates toincreasing the amount of cesium formate and water, while

lowering the amount of potassium formate.

Given that formate brines seem to be almostincapable of forming precipitates when blended withformation water, the only sources of precipitatesare contaminants or additives. One frequently usedadditive in formate drilling and completion fluids is a pHbuffering compound, potassium carbonate. A commonconcern has been that soluble carbonate buffer canprecipitate out with divalent cations in formationwaters to form calcium or magnesium carbonate


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scales. Such precipitation has been seen in laboratorybottle testing, as described below. However, there areseveral reasons to believe that this kind of scaling doesnot occur in the field:

Formate brines have been used in the field since

1993, and with the exception of one instance [11], noformation damage has been reported.

Carbonate scales are always acid soluble, and cantherefore easily be treated with an acid soak. However,no such treatment has ever been required in any oneof hundreds of field applications of cesium formatebrine. Cabot is also unaware of acid stimulationrequired in any potassium or sodium formate jobs.

Buffer concentration is adjustable. Significantamounts of buffer are only required in applicationswhere reservoir gas contains significant amounts ofCO

2. If any carbonate scale forms in such a reservoir,

it is likely to dissolve when CO2-containing gas is laterproduced through this reservoir rock. If the reservoirgas doesn't contain CO

2, no (or very little) buffer is

needed.

In the one and only case of reported formation damageafter drilling with sodium / potassium formate brine-baseddrill-in fluid [11], the operator was able to solve the reportedproblems simply by reducing the carbonate concentrationin its fluid. The problems occurred in a HPHT gasreservoir in Germany where formation water containedunusually large amounts of soluble calcium. The authorsreported that the scaling problem was remedied simplyby adjusting formate brine pH down to 9.5. The pH wasmeasured on neat (undiluted brine). This is not therecommended method for measuring pH in concentratedformate brines (see Section A6, pH and Buffering). Inorder to compare recorded pH readings to importantparameters, such as pKaof carbonate / bicarbonate, it isnecessary to dilute the brine before measuring pH. Basedon experience with concentrated formate brines, however,one can assume that the diluted pH of the German brinewould be in the range slightly above 8.5. Since the pKaofcarbonate / bicarbonate is about 8.2, we can concludethat the remedial pH treatment converted most of the

carbonate present in the buffer to bicarbonate. Themonovalent bicarbonate ion (HCO

3-) does not precipitate

out with divalent calcium ions. An alternative methodfor solving the problem is to just add less carbonate(CO3

2-) buffer component to start with. Large amountsof carbonate buffer are only required in completionapplications where reservoir gas contains a lot of CO2.

Two methods are commonly used to predict precipitationand scaling problems in completion brines. These are:

Scale prediction using various modeling softwarepackages.

Laboratory bottle testing.

Both methods have serious limitations when appliedto formate brines and results should be treated with

caution. Some problems arising from using thesemethods with formate brines are discussed below.

B10.4.1 Scale prediction using modeling software

packages

There are several commercial software tools availablethat claim to provide predictions about the possibilityof scale and precipitates forming when completionbrines are mixed with formation waters. The softwarepackages are said to be able to predict the onset ofscale precipitation as a function of temperature andpressure. When using any of these tools to predict

scaling or precipitation events from mixing formationwaters with formate brines, be aware of the followinglimitations:

Some of these software packages do not allow forcesium formate to be included in the completionbrine as these ions are not available in theirdatabase. The common way for users to solve thisproblem is to view cesium formate as water, and onlyinclude the additives, i.e. carbonate / bicarbonatebuffer. The problems with this approach are:- Any precipitate of cesium or formate will not be

identified. In reality, this is not a problem as cesiumor formate salts are unlikely to precipitate in anycommon formation water.

- Water does not have the same solvency andproperties as cesium formate. This is a big problemas certain scales, such as barium sulfate, are highlysoluble in cesium formate brines, but not in water.The software may therefore wrongly suggest thatsulfate scales can form in cesium formate brine.

Some of these scale prediction software packages allowfor the inclusion of sodium and potassium formate,and some even accommodate a cesium formate brine

environment. However, there are still problems:- These tools do allow for prediction of any Cs, K, Na,

or formate salts that can form. Such precipitatesare, however, highly unlikely to form due to theirhigh water solubility.

- Although the user is allowed to enter a largeamount of formate brine into the model, the modeltreats it as water when it comes to solvencyproperties, i.e. the ability of formate brine todissolve scales, which is the same problem asnoted above.


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- The assumed solubility of cesium formate in wateris incorrect, and the software therefore predictsthat self-precipitation takes place in concentratedbrine. Consequently, the user needs to reducecesium formate concentration to a level whereself-precipitation is not predicted.

In summary, none of the scale prediction packagesevaluated by Cabot are capable of considering thesolvency properties or water-structuring (salting out)effects of formate brines. Formate brines are powerfuldissolvers of sulfate scales. If this property is notconsidered by the software, any scale predictionsfor formate brines are simply wrong. For example,formate brine contaminated with a certain amount ofdivalent sulfate ions (SO

42-), can tolerate a large amount

of barium ions in formation water, without forminginsoluble barium sulfate (BaSO

4) scale (see Section B12,

Solubility of Minerals and Salts in Formate Brines). Anyscale prediction tool, however, assumes that BaSO

4is

just as insoluble in formate brines as in water, and theresults of the scale prediction exercise are erroneous.

As none of the scale prediction tools available todayare properly calibrated for use with formate brines, theyall give misleading projections. Until the calibrationproblem is fixed, the only way to get a realistic pictureof formate brines compatibility with formation watersunder HPHT conditions is to conduct coreflood testsunder reservoir conditions.

B10.4.2 Scale prediction using laboratory bottle testing

It is common practice to perform reservoir watercompatibility checks in the laboratory by mixingcompletion brine and formation water together in arange of different blend ratios in a bottle under ambientconditions and observe the outcome. The appearance ofturbidity or precipitated solids is taken as an indicatorthat the completion brine is incompatible with theformation water and might cause formation damage.If such tests are carried out on formate brines, it ishelpful to be aware of the pitfalls:

Leaching silicates: Formate brines can leachsilicate out of borosilicate glass, which is evidentthrough white precipitate in the brine (see SectionB12, Solubility of Minerals and Salts in FormateBrines). The rate of this reaction is very dependenton the concentration of formate in solution andtest temperature. If concentrated potassiumformate brine is heated to around 100C / 212F in aborosilicate bottle, white precipitate may already beobserved within a few hours. Such precipitate formsin any borosilicate bottles that contain concentrated

formate brines, and interferes with the visualobservation of salt precipitation / scaling. Unfortunately,the only transparent bottles suitable for testing fluids atreasonably high temperature are made of borosilicateglass. Leaching seems restricted to borosilicate glassand does not occur with sand, quartz or other silicate

materials. Temperature: With the exception of carbonates,

salt precipitates generally form more readily atlower temperatures. This means that precipitatesgenerated in laboratory bottle mixing tests atambient temperatures may not form at reservoirtemperature. Formation of precipitates at ambient /low test temperature is therefore not predictive ofwhat might happen in the reservoir. Carbonate-typeprecipitates exhibit the opposite behavior, wherescales are more likely to form at higher temperature.

Pressure: Testing at low / ambient pressure can

cause similar problems to testing at low temperature,although the effect may not be as marked. With theexception of carbonates, salt precipitates generallyform more readily at higher pressures.

B10.5 Comparison of formate brines with otherhigh-density brines

Full compatibility with reservoir components andany filtrates from preceding well operations is akey requirement for any brine used in drilling andcompletion. Currently there are four different classesof brine used in well construction and interventionoperations (see Table 3).

Each of these groups of brines has different degreesof compatibility with reservoir components and otherfiltrates, as described below.

B10.5.1 Comparison with calcium bromide / calcium

chloride brines

Brines composed of calcium bromide (CaBr2) and

calcium chloride (CaCl2) can reach density of about

1.70 g/cm3/ 14.2 lb/gal. These brines contain largeamounts of divalent Ca2+cations, up to about 4.5 mol/L,

which makes them incompatible with formation waterscontaining carbonate, bicarbonate, and sulfate [27]. Theycan also form cement-like materials with zinc debrisfrom perforating guns, and make stable emulsions withoil-based mud residues, which creates a substancewith consistency of peanut butter [28].


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B10.5.2 Comparison with zinc bromide brine

Zinc bromide (ZnBr2) is the only commercially availablebrine that reaches the same density as cesium formatebrine. Zinc bromide brine is acidic with a pH of less than 2,hazardous and a priority marine pollutant. It is consideredtoo high-risk to use in Europe, where it has been replacedby cesium formate brine, but is still used occasionally in

certain regions of the world, such as the Gulf of Mexico.

Zinc bromide causes extensive formation damage andtubular scaling in reservoirs containing H2Sas it formszinc sulfide scale (ZnS). It only needs 2 ppm of H2Sin the reservoir gas to create formation damage [29].Figure 3 shows the appearance of buffered 2.20 g/cm3/18.4 lb/gal cesium formate brine and 2.27 g/cm3/ 18.9 lb/galzinc bromide brine after charging with 5 psi H2Sandstirring for 16 hours at ambient temperature. The zincbromide solution has turned completely opaque fromprecipitation of ZnS.

Zinc bromide also forms scales with formation waterscontaining carbonate, bicarbonate and sulfate, and, likecalcium bromide brine, it makes stable emulsions withoil-based mud residues.

B10.5.3 Comparison with potassium hydrogen

phosphate brine

Potassium hydrogen phosphate brine, comprising of ablend of dipotassium hydrogen phosphate (K

2HPO

4) and

potassium dihydrogen phosphate (KH2PO

4), has been used

as completion and workover fluid in China and Indonesia.The maximum density achievable with potassium

hydrogen phosphate brine is thought to be about1.78 g/cm3/ 14.9 lb/gal, although lower density brines havebeen found to crystalize at ambient conditions.

When these brines invade a reservoir they cause twotypes of formation damage: Formation of insoluble scales on contact with

multivalent cations in formation water. For example,in a very typical formation water containing solublecalcium and iron, the trivalent phosphate anionreacts to form tricalcium phosphate [Ca

3(PO

4)

2],

hydroxylapatite [Ca5(PO4)3OH], ferric hydroxide[Fe(OH)

3], and strengite [FePO

42H

2O]. The phosphate

scales form hard bone-like deposits, whereas thehydroxide forms gels.

Phosphates absorb strongly onto mineral surfaceswhere they can form precipitates and complexinsoluble salts from exposure to multivalent cations[30][31]. These absorption-reaction products blockpore throats and reduce formation permeability.

IPTC 14285 [32] describes a laboratory study thatcompares the influence of cesium formate and potassiumhydrogen phosphate brine invasions on gas permeabilityof low-permeability sandstone cores invaded by the brine

under HPHT conditions in a coreflood test rig.

The brines tested were: Cesium formate brine at density of 2.20 g/cm3/

18.4 lb/gal buffered with 6.25 ppb K2CO3and3.75 lb/gal KHCO3. pH = 10.5.

Potassium dihydrogen phosphate / dipotassiumhydrogen phosphate brine blend at density of1.64 g/cm3/ 13.7 lb/gal. pH = 9.32. The brine wasmade from analytical grade phosphate saltsdissolved in distilled water.

Table 3Brine classes used in well construction and intervention operations.

Brine type Chemical compositionDensity range

[g/cm3] [lb/gal]

Monovalent halides NaCl, KCl, NaBr, and their blends 1.0 1.5 8.3 12.5

Divalent halides CaCl2, CaBr2, ZnBr2, and their blends 1.0 2.3 8.3 19.2

Phosphate brines1)

Blends of K2HPO4and KH2PO4 1.0 1.7 8.3 14.2Formate brines NaCOOH, KCOOH, CsCOOH, and their blends 1.0 2.3 8.3 19.2

1) Limited use in China and Indonesia.

Figure 3 Samples of a 2.27 g.cm3/ 18.9 lb/gal ZnBr2

brine and a 2.20 g/cm3/ 18.3 lb/gal buffered cesium

formate brine after charging with H2Sfor 16 hours at

ambient temperature. A significant amount of insoluble

precipitate forms in the zinc bromide sample.


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C A B O T

The tests were carried out at 175C / 347F in a HPHTcoreflood test rig operated by Corex, a company withconsiderable expertise in formation-damage testing. Thesynthetic formation brine used in the tests (see Table 4)was based on water sampled from an HPHT well in theNorth Sea.

The source of core plug material for the experimentswas Clashach sandstone with absolute gas permeabilityvalues close to 20 mD. The Clashach sandstone withporosity of around 10%, low argillaceous content,and high homogeneity is good standard material forcoreflood tests of completion fluid candidates for tightgas reservoirs.

The coreflood test was carried out according tothe recommended procedure described previously(Figure 2). The cleaned core plugs were saturated withformation water and taken down to irreducible formationbrine saturation. Exposure of the core to the completionbrines was carried out under the following pressureconditions: Overburden pressure of 8,150 psi, core porepressure of 5,800 psi, confining pressure of 2,350psi, and final drawdown pressure of 100 psi. The coreswere flushed with 10 pore volumes of brine, and givena 48-hour static soak. Drawdown was then applied tothe wellbore side of the core to create a flow of HPHThumidified nitrogen gas, which simulates bringing thewell back onto production. Drawdown pressures of 5, 10,25, 50, 75, and 100 psi were used.

Relative permeability measurements were taken atthe end of each test sequence to determine levels ofpermeability alteration caused by exposure to the brines.Results are shown in Table 5. The core exposed tophosphate brine lost 91.6% of its permeability, whilst thecore exposed to formate brine gained a small amount ofpermeability from the exposure.

SEM and cryogenic SEM analyses show that the coreplug exposed to phosphate brine was clogged withphosphate scale. The phosphate scale deposits wereup to 35 m in length. See Figure 4.

B10.6 Comparison of formate drilling fluidswith solids-weighted drilling fluids

The first fluid to contact the formation is drilling fluid.Since this contact occurs before the filter cake is laiddown, drilling fluid and drilling fluid filtrates can deeply

invade the formation and cause incompatibility withboth fluids and pore-lining material. Solid-weightingmaterial can invade the formation before the filtercake is built and small solid particles may also fail tobe screened out by the filter cake. Solids can causesevere plugging when allowed to enter into theformation. In addition, the filter cake itself can causedamage if it is not easily removed when the well is puton production. Incomplete removal of the filter cake canlead to reduced well production due to excessive skinand expensive stimulation treatments may be required.

One of the problems with traditional water- and oil-based drilling fluid is that solids are needed for densitycontrol, and there is very little control over both particlesize and concentration of solids used. In formatedrilling fluids, density is controlled by brine type andconcentration, and the only solids needed are thoseused to form the filter cake. About 43 kg/m3/ 15 ppbcalcium carbonate, containing a blend of various sizes,has been found to give very low fluid losses.

To avoid established well control problems associatedwith traditional weighting material, such as barite,service companies now offer mud formulations where

barite is replaced with micro-sized weighting particles.These are particles with an average size in the range of 1 5 m. By using potassium formate as base fluid ratherthan oil or water, the amount of particles needed canbe brought down to an absolute minimum. Micro-sizedbarite cannot be used with potassium formate due to itshigh solubility in potassium formate brine (see SectionB12, Solubility of Minerals). Manganese tetraoxide ismicro-sized weighting material with average particlesize of about 1 m, which is compatible with formatebrines (see Section B5, Compatibility with Additives).

Table 4Ionic composition of reservoir water used in Corex coreflood test.

Na K Ca Mg Ba Fe Cl HCO3

Ion concentration [mg/L] 31,190 300 2,300 350 1,000 10 53,500 610

Table 5 Permeability measurements on Clashach core plugs before and after exposure to phosphate and formate brines.

Brine systemTemperature Initial permeability

[mD]Final permeability

[mD]

Change inpermeability

[%][C] [F]

Phosphate 175 347 10.2 0.86 -91.6

Formate 175 347 23.0 24.8 +7.8


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As little is known about the impact of these micro-fineparticles on formation compatibility, a standard corefloodstudy was conducted by Corex, UK, to investigate theeffect of micronized particles on formation compatibilityof formate drilling fluids. Two drilling fluids were compared;one standard low-solids formate drilling fluid based on acesium and potassium formate blend, and one potassiumformate drilling fluid weighted to the same density withmanganese tetra oxide [33]:

1. 1.76 g/cm3/ 14.7 lb/gal potassium / cesium formatedrilling fluid.

2. 1.76 g/cm3/ 14.7 lb/gal potassium formate drillingfluid weighted with micro-fine weight material.

Fluid formulations and fluid properties are shown inTable 6 and Table 7 respectively.

The tests were carried out at 149C / 300F in a HPHTcoreflood test rig. The synthetic formation brine usedin the tests (see Table 8) was based on water sampledfrom an HPHT well in the North Sea.

The source of core-plug material for the experimentswas Clashach sandstone with absolute gas permeabilityvalues between 20 and 30 mD and porosity of around10%, low argillaceous content, and high homogeneity.

The coreflood test was carried out according to therecommended procedure described previously (Figure 2).The cleaned core plugs were saturated with formationwater and taken down to irreducible formation brinesaturation. Exposure of the core to drilling fluids wascarried out under dynamic conditions for 48 hours andthen followed by a static period of 48 hours. Overburden

pressure was 8,150 psi, core pore pressure was 5,800 psi,confining pressure was 2,350 psi, and final drawdownpressure was 100 psi. Drawdown was then applied tothe wellbore side of the core to create a flow of HPHThumidified nitrogen gas, which simulates bringingthe well back onto production. Gas flow rates inducedby drawdown, as a function of cumulative gas flowthroughput for the two brines, are shown in Figure 5. Theflow rate is about six times higher in the core exposed tolow-solids formate drilling fluid than in the core exposed topotassium formate drilling fluid weighted with micronized

Figure 4SEM photos of unexposed pore throats (left) and pore throats exposed to phosphate brine (right). The sand

grains and pore throats exposed to phosphate brine are covered in a blanket of phosphate scale.

Before test After test


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C A B O T

manganese tetraoxide. This is despite initial permeabilityof the core plug exposed to manganese tetraoxide-weighted fluid being slightly higher (28.7 mD) than theone exposed to low-solids potassium / cesium formatefluid (20.9 mD).

Relative permeability measurements were taken at theend of each test sequence to determine the level ofpermeability alteration caused by exposure to the twodrilling fluids. Results are shown in Table 9. The core

exposed to drilling fluid formulated with micro-sizedweighting particles had lost 92.8% of its permeability.For comparison, permeability loss for the core exposedto standard formate drilling fluid was 21.1%.

The filter cakes formed during the two tests werethoroughly inspected. Filter cake from the fluidweighted with micro-sized particles was about 3 mm thickand adhered firmly to 100% of the wellbore face of the coresample. For comparison, the filtercake from the potassium /

Table 6 Formulations for two formate drilling fluids tested and compared at Corex.

Base fluid CsFo / KFo fluid KFo fluid with solid-weighting material

CsCOOH (2.20 g/cm3) 96.8 mL 0 mL

KCOOH (1.570 g/cm3) 240.0 mL 314.0 mL

Additives Concentration [ppb] Concentration [ppb]K2CO3 5.0 5.0

Flowzan 0.7 1.0

ExStar HT 3.5 3.5

Aqua PAC ULV 3.5 3.5

Baracarb 5 5.0 5.0

Baracarb 25 2.5 2.5

Baracarb 50 7.5 7.5

Solid-weighting material (5m) 0 109.0

Total additives 27.7 137.0

Table 7 Properties before and after hot rolling for two drilling fluids tested and compared by Corex.

Properties beforehot rolling

CsFo / KFo fluid KFo fluid with solid-weighting material

BHR AHR (16 hours at 149C / 300F) BHR AHR (16 hours at 149C / 300F)

Density g/cm3 1.76 1.76

pH 10.02 10.35

Fann 35, 600 RPM 95 83 180 92

Fann 35, 300 RPM 59 50 111 58

Fann 35, 200 RPM 46 38 92 43

Fann 35, 100 RPM 29 23 60 26

Fann 35, 6 RPM 7 4 15 4

Fann 35, 3 RPM 5 3 11 3

Gels 10" [lb/100 ft2] 6 3 14 4

Gels 10' [lb/100 ft2

] 7 4 52 16PV 36 33 69 34

YP 23 17 42 24

HPHT fluid loss1)[mL] 6.8 4.8

Spurt loss [mL] 0.2 0.2

Cake thickness [mm] 1.0 1.0

1) 500 psi, 149C / 300F.

Table 8Ionic composition of reservoir water used in the Corex coreflood test.

Na K Ca Mg Ba Fe Cl HCO3

Ion concentration [mg/L] 31,190 300 2,300 350 1,000 10 53,500 610


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C A B O T

Figure 6 a) Filtercake left on wellbore face after testing with potassium formate drilling fluid with micronized weighting

material, b) dry SEM photo of wellbore face after testing with potassium formate drilling fluid with micronized weighting

material, c) filtercake left on wellbore face after testing with a standard potassium / cesium formate drilling fluid, d) dry

SEM photo of wellbore face after testing with a standard potassium / cesium formate drilling fluid.

a) Filter cake left on wellbore

face of core exposed to

drilling fluid with micronized

weighting material.

b) Dry SEM photo of wellbore face

after testing with drilling fluid

with micronized weightingmaterial.

c) Filter cake left on wellbore

face of core exposed to

standard potassium / cesium

formate drilling fluid.

d) Dry SEM photo of wellbore face

after testing with standard

potassium / cesium formate

drilling fluid.


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Figure 7Porelining cryogenic SEM of a) unexposed pore throats, b) pore throats in a core plug after exposure to a

potassium formate drilling fluid weighted with micronized manganese tetraoxide, c) pore throats in a core plug after

exposure to standard potassium / cesium formate drilling fluid.

a) Pore throat before fluid exposure.

b) Pore throats in a core plug after exposureto potassium formate drilling fluid

weighted with manganese tetra oxide.

c) Pore throats in a core plug after

exposure to standard potassium /

cesium formate drilling fluid.


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C A B O T

The horizontal section was drilled in 30% of the AFEtime planned. The well was tested and brought ontoproduction with zero skin damage, a productivity indexof 14 and production volume of 13,000 bbl/day. Theseresults far exceed production from an offset well drilledin the same formation by another operator using a

different mud system.

B10.7.2 NAM, offshore Netherlands, 1997

The development well K14-FB 102 was completed asa dual-lateral to optimize production capacity andreservoir drainage from tight Rotliegend sandstone inan offshore gas play in the Dutch sector of the NorthSea [35][36]. The two 57/8" horizontal productionintervals were drilled and completed in open hole usingsodium formate drill-in fluid. Sodium formate waschosen to maximize production from an area of thefield with poor reservoir quality.

A previous well, K14-8, had been drilled, completed, andtested in 1979 in the same area of the field. Despitebeing perforated under drawdown conditions, thiswell, which was drilled with low-toxicity oil-based mudfollowed by mud-acid stimulation, failed to produce atcommercial gas rates.

For K14-FB 102, the fluid was formulated with sodiumformate as base fluid, calcium carbonate as bridgingagent, purified xanthan biopolymer as rheology modifier,and modified starch for fluid-loss control. The systemwas rheologically engineered for the targeted intervalwith minimum solids content, and designed arounddesired LSRV measured at low shear rate for holecleaning, overall drilling performance, and minimizingfiltrate invasion. Sodium formate drill-in fluid, usedinstead of mineral oil-based fluid, allowed the operatorto make beneficial modifications to standard drillingpractice, with positive results:

It exhibited superior hole-cleaning qualities throughoutthe entire interval and no significant drag wasobserved during drilling. It eliminated the need forpills to assist with hole cleaning.

Flow rates can be increased from typically195 250 gal/min to 290 gal/min because of thereduced frictional pressure losses of the brinesystem. A pressure reduction of 33% was achieved.

It reduced the need for backreaming out of the holefor hole cleaning.

It achieved faster-than-expected penetration becauseincreased flow rates enhanced turbine performance.As a result of high ROP, a 35% reduction in totalreservoir drilling time was achieved.

The well was completed one leg barefoot and onewith a pre-drilled liner (PDL) and lifted into productionusing nitrogen pumped through coiled tubing into thePDL leg. A 1.27 g/cm3/ 10.6 lb/gal sodium / potassiumformate brine was used as completion fluid. No stimulationor remedial work was applied. The well exhibited self-

cleaning behavior, indicating that the planned filtercake lift-off approach had been successful. Resultingproduction capacity was 40% above expectation and anear-zero mechanical skin indicated that the well hadbeen completed with minimal residual drilling-induceddamage. The increase in production compared toexpectation was thought to be a combined effect ofthe additional drilled lateral and low impairment of thesodium formate drill-in fluid.

An MPLT log was run to determine cleanup effectiveness,and the extent that varying permeability zones were

contributing. Significant contribution was seen from theoriginal hole. This confirmed the wells self-cleaningattributes as a result of the drill-in fluid and filter-cakedesign. Pressure build-up data yielded a near-zero skinfor the well and the low total skin value indicates that thereservoir interval was completed with minimal residualdrilling-induced damage.

B10.7.3 BP, Harding Field, offshore UK, 1999

A high-angle, openhole, gravel-pack well was drilledwith potassium formate drill-in fluid [37]. The reservoirconsisted of sand / shale sequences with a net-to-gross of approximately 60%. The intra-reservoir shalecomprised layers varying in thickness from severalmeters to less than a millimeter. It also contained ahigh level of reactive smectite clay (80% of the claycontent). The individual sand bodies comprised clean,well sorted, 3 4 Darcy unconsolidated sands.

The potassium / sodium formate drill-in fluid waschosen because of its ability to stabilize these highlyreactive intra-reservoir clays, as well as its ability todeliver a gauge hole, give minimal formation damage,form an easily removable filter cake, and provideminimal screen plugging potential. The fluid also

couldn't cause HSE-handling or operational problems.

Laboratory work was part of the selection process;cage dispersion tests on reservoir shale gavegreater recoveries in formate brine, compared withconventional sodium chloride or sodium / potassiumchloride brines with added glycol. The drilling fluidformulation was simple, consisting of potassium /sodium formate brine, 4 lb/bbl biopolymer viscosifier,5 lb/bbl modified starch for fluid-loss control, and sizedcalcium carbonate as bridging agent.


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The reservoir section was drilled without any problems,and the gravel pack was placed with ViscoelasticSurfactant (VES) carrier fluid based on 5% sodium chloride.An enzyme-based breaker fluid was used to remove thefilter cake. The well cleaned up very rapidly.

BP could not gauge the exact magnitude of mechanicalskin due to the uncertain estimate of formation kv/kh.Nevertheless, BP concluded that the operation was acomplete success based on excellent well performancedata (IPR vs. TPR).

B10.7.4 ExxonMobil, HPHT gas fields, Germany,

1996 2000

ExxonMobil has used formate-based reservoir drillingand completion fluids in more than 15 high-temperaturegas wells in northern Germany [5]. The performance ofthese fluids was reviewed in 2000 [6].

Formate brines were chosen to eliminate drillingproblems that had occurred in previous wells. Theproblems encountered with conventional water-based polymer mud included inadequate solidssuspension, poor solids transport, stuck pipe, andtight holes. ExxonMobils migration to formate-basedfluids eliminated most problems and brought wellconstruction costs under control.

The drilling fluids were formulated using sodiumformate, potassium formate, or a blend of the two.Biopolymers were added for viscosity control, fluid-lossagents, and sized calcium carbonate (1 3%) for porebridging. Laboratory coreflood testing was conductedto assess potential for formation damage. A sodiumformate-based fluid system was compared to anoil-based drilling fluid. Core permeability to gas wasmeasured before and after mechanical cleanup with a

jetting tool. Results indicated a significant increase inreturn permeability with formate-based fluid.

Formate brines were used in 83/4" holes drilledthrough the pay zone with emphasis on hole cleaning,minimizing formation damage, and optimal hydraulics.

Maximum fluid density was 1.55 g/cm3/ 12.9 lb/gal.The majority of wells were drilled and completed in thereservoir section without any borehole or fluid-relatedproblems. There was no sticking, no cutting bedsencountered, and torque and drag were immediatelyreduced after displacement to formate mud. A numberof wells encountered considerable salt formation.

Total fluid and maintenance costs were significantlyreduced in the overall project. Other benefits attributedto the formate-based reservoir drilling fluid included:

25% lower pump pressure. 25% increased ROP. 100% success rate in running production liner.

Once the wells had reached TD, used drilling fluid wasprocessed through normal solids-control equipment to

remove the majority of bridging agents and drill solids.The processed fluid was then used as completion fluidduring the completion phase. The wells were put onproduction with a typical production rate 35% higherthan expected (or higher than previous offset wells).

B10.7.5 Western Canada, 1999 2004

Over 300 wells were drilled in Western Canada over fiveyears with low-concentration potassium formate drillingfluid. Low-concentration potassium formate brinestabilized troublesome shales (Blackstone, Fernie, andFort Simpson) in Alberta and British Colombia. This shale-

stabilizing fluid, even in small amounts, not only greatlyimproved drilling performance by reducing trouble timeand eliminating stuck pipe, but produced gauge holesand improved well production [38][39][40].

B10.7.6 Statoil, Huldra Field, offshore Norway,

2001 2003

Huldra is a gas condensate field in the Norwegiansector of the North Sea operated by Statoil ASA. Duringdrilling and completion of this field, high temperatureand pressure conditions were encountered in thereservoir section (675 bar, 150C / 302F). Thedifference between pore pressure and fracturepressure gradient was small in the reservoir. The Huldragas stream contained 3 4% CO

2and 9 14 ppm H

2S.

Wells were drilled at a 45 55 inclination through thereservoir and completed with 300-micron single-wire-wrapped screens.

When the first production well was drilled in this fieldwith oil-based mud, a severe well kick was experiencedwhile running sand screens. The main reason was aloss of drilling-fluid density due to barite sag duringthe wiper trip. A cesium formate-based drill-in fluidwas therefore selected for the following wells, primarily

for well control [9]. The cesium formate fluid wentthrough thorough evaluation and testing. The mainbenefits identified with the cesium / potassium formatebrine compared with the oil-based fluid were: no sagpotential, low ECD, less screen-plugging risk, low solids,use of solids that could be acidized (CaCO3), low gassolubility, environmentally friendly, and quick thermalstabilization during flow checks.

Return-permeability testing predicted reduction information permeability after drawdown in the range


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of 36 70% [22], see Table 10. Further testing showedthat incorporating treatment with dilute organic acidto remove residual filter cake was effective in restoringcore permeability to its near-native state (Table 11).

Initial return-permeability results were not particularlygood, and in other circumstances might have led toformate brine being rejected as drilling-in fluid, butresults after acid treatment indicated that the damagewas shallow and tractable. The operator decided togo ahead and use formate fluid, knowing that anyformation damage could be removed by a simple acidsoak at balance.

The drilling operation itself was characterized by goodhole stability, low ECD and good hole cleaning. Excellentrheology and thermal stability of the drilling fluid ledto rig-time savings from faster tripping speeds, fastercasing-running speeds, less mud conditioning and fewerwiper trips. ROP was also good. The drilling fluid wascirculated over a combination of 250, 300, and 400-meshshaker screens before the completion screens were run.After running screens, the drilling fluid was replaced withfiltered potassium / cesium formate completion brine.

Statoil reports that the six Huldra wells drilled andcompleted with formate brines were each producingwith excellent average productivity indices of around1.9 million scf/day/psi. In fact, plateau production rateswere achieved from the first three wells of the six-well project. The Huldra project manager is quoted assaying: For the specific conditions of the Huldra fieldthere is no realistic fluid alternative for successfullydrilling and completing the wells. There were noobvious signs of formation damage in the wells, andno acid stimulation was required. This suggests thatthe coreflood test results were misleading, i.e. tooconservative. With todays knowledge about coreflood

testing of formate brines (see B10.3.1) it seemsprobable that the poor laboratory results were anartifact, perhaps originating from nitrogen gas that wasnot humidified at test conditions to flow back the core.

During 2002 2003, average gas production ratesfrom the Huldra field were 7 8 MMm3/day. The wells,and the residual filter cake lining the open boreholes,cleaned up naturally during the early production phase.Huldra is estimated by the Norwegian PetroleumDirectorate (NPD) to have recoverable reserves of

Table 10Huldra coreflood test results after drawdown.

Sample FluidFiltrate loss

[mL]

Base perm.Kg@Swi

[mD]

Perm.after mud

drawdown[mD]

% change onbase perm.*

Perm. aftermudcakeremovedand plug

spun down[mD]

% change onbase perm.

Filtratespun out

[mL]

1A Formatefield mud 15.419 1,416 881 -37.8 990 -30.8 0.19

2BFormatefield mud 11.719 2.88 0.982 -65.9 1.17 -59.4 0.083

6AOptimizedformate DIF 10.564 1,978 1,272 -35.7 1,675 -15.3 0.30

3BOptimizedformate DIF 8.388 7.47 2.27 -69.6 3.64 -51.3 0.17

* Possibly due to dry gas used during drawdown.

Table 11Huldra coreflood test results after drawdown and dilute acid soak.

Sample Fluid Filtrate loss[mL]

Base perm.

Kg@Swi[mD]

Perm.after mud /drawdown

/ remedialacid soak/ second

drawdown[mD]


Perm. aftermudcake

removedand plugspun down

[mD]


Filtrate

spun out[mL]

7AFormatefield mud 18.247 2,198 2,341 6.51 2,406 9.46 Trace

6BFormatefield mud 12.355 3.47 3.56 2.59 3.81 9.74 0.05

8AOptimizedformate DIF 12.484 1,988 1,982 -0.30 2,027 1.96 Trace

4BOptimizedformate DIF 10.003 10.9 10.7 -1.83 11.2 2.75 0.05


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16.6 billion m3of gas and 5.0 million m3of oil / condensate.Production records on the NPD website indicate thatby the end of the seventh year of production the sixHuldra field wells had delivered 77% of recoverable gasreserves and 87% of recoverable condensate reserves.Cumulative production is now close to 100% of original

estimates of recoverable reserves (see B10.8).

B10.7.7 Shell, Brigantine Field,

offshore UK, 2000 2001

Between October 2000 and March 2001, Shell drilledthree horizontal wells in the North Sea Brigantine fieldand completed them using ESS (Expandable SandScreen) technology [41]. For these ESS operations, Shellrequired a mud system with the following functionality:

Provides a gauge hole. Maintains borehole stability during drilling and ESS

running / expanding. Aids good hole cleaning. Exhibits good fluid-loss control by formation of

an external filter cake on the wellbore. Maintains hydrostatic well control. Reduces friction while running and expanding ESS. Flows through ESS during expansion without

blocking 230-micron screens. Non-damaging to the formation, sand screens and

the environment.

The mud systems considered were potassium chloridepolymer, sodium chloride polymer, sodium formate,LTOBM, and sodium / potassium formate. The LTOBMwas rejected because it did not pass the flow testthrough the 230-micron screen. A formate system waspreferred over the chloride systems due to beneficialshale-stabilizing properties demonstrated duringprevious use of formates by Shell. This, combined withthe fact that much of the weight was provided by thebase brine, made the formate system the preferredalternative.

The formate fluid was prepared with a calcium carbonateparticle-size distribution specifically designed not to

plug the 230-micron screens. Testing of this systemresulted in return permeability of 70 90% compared to15 55% for LTOBM.

The three wells were drilled and completed 32 daysahead of plan, achieving initial gas production rates23% 40% higher than expectations.

B10.7.8 OMV, Miano and Sawan Fields,

onshore Pakistan, 2001

OMV has published two papers on the developmentand successful use of formate brines as reservoirdrilling and completion fluids in the Miano and Sawanhigh-temperature gas fields located in the Sindh area

of Pakistan [42][43].

OMV's first paper [42] and presentation slides describethe development and application of low-solids potassiumformate brine as drill-in and completion fluid for the 6"hole section of well Miano-9, where the main challengewas high overbalance of 1,700 psi and high BHST of177C / 350F. A low-solids formate fluid was vital in theoperation to avoid plugging sand screens. The drillingoperation was trouble-free with zero losses in 10 5,000 mDsandstone, a perfect caliper and exceptional loggingresults. The well was displaced to clean 1.1 g/cm3/

9 lb/gal potassium formate brine before running anexpandable sand screen and a 22Cr completion. Theexpected production was


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Visund has proven to be a highly complicated reservoirwith complex geology. Permeabilities ranged from300 to 3,000 mD. The wells were drilled and completedwith long horizontal sections to reach several targetswith one well. They have relatively high pressures andtemperatures (440 bar, 115C / 311F). Sand prevention

was obtained by oriented perforating in the directionof maximum stress.

The drilling time of these wells was long, which resultedin long exposure of high overbalanced drilling fluids tothe formation. This produced a deep mud filtrate invasionzone around the wellbore. The first wells were perforatedusing a standard oriented perforating system with zinc-cased charges in 1.

compatibilidad de los fluidos del yacimiento

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