Section B5 Compatibility with Additives

P A G E 1S E C T I O N B 5

Section B5Compatibility with Additives

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 results and/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, or any 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 product to which it relates.

© 2009 Cabot Corporation, M.A.-U.S.A. All rights reserved. CABOT is a registered trademark of Cabot Corporation.

B5.1 Introduction ............................................................................................2B5.2 Biopolymer compatibility ........................................................................2 B5.2.1 Compatibility with xanthan gum ......................................................2 B5.2.2 Stability of starch and PAC ..............................................................3 B5.2.3 Compatibility with other biopolymers ..............................................3 B5.2.4 Stretching the limits .........................................................................3B5.3 Compatibility with synthetic polymers ...................................................3 B5.3.1 Synthetic viscosifiers – the ‘4mate-Vis’ family .................................3 B5.3.2 Acrylamide copolymer ....................................................................10 B5.3.3 DrisTemp ........................................................................................10B5.4 Compatibility with clays ........................................................................ 10 B5.4.1 Sepiolite ..........................................................................................10B5.5 Compatibility with lubricants ................................................................ 10 B5.5.1 Laboratory testing .......................................................................... 11 B5.5.2 Field experience .............................................................................15B5.6 Compatibility with weighting material .................................................. 16B5.7 Compatibility with corrosion inhibitors ................................................. 16B5.8 Compatibility with biocides .................................................................. 16B5.9 Compatibility with H2S scavengers ...................................................... 17 B5.9.1 H2S scavengers that work in formates ...........................................17 B5.9.2 OCT – comparison study ................................................................18 B5.9.3 Ironite Sponge testing at Westport ................................................19B5.10 Compatibility with antioxidants ............................................................20B5.11 Compatibility with oxygen scavengers ................................................20B5.12 Compatibility with defoamers .............................................................. 21 References ........................................................................................... 21

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

COMPATIBILITIES AND INTERACTIONS

F O R M A T E T E C H N I C A L M A N U A LC A B O T S P E C I A L T Y F L U I D S

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C A B O T S P E C I A L T Y F L U I D S

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F O R M A T E T E C H N I C A L M A N U A L

S E C T I O N B 5

B5.1 Introduction

One of the great advantages of formate-based drilling and completion fluids is that they have a range of beneficial properties and need few additives to improve their performance.

Formate brines are not significantly corrosive to metals and do not normally require the addition of corrosion inhibitors or oxygen scavengers. In fact, corrosion inhibitors should be avoided completely unless the conditions are particularly extreme. Formate brines are naturally dense and do not require the addition of solid weighting agents, except in emergency situations. Biocide additions are not generally needed either, because the low water activity of the brines discourages the growth of micro-organisms. An exception to this rule might be lower-density drilling fluids (see Section A12 Biodegradation and Biocidal Properties). Another interesting characteristic of formate brines is their natural lubricity, meaning that no lubricant additives are normally required.

The one additive that really is of crucial importance in formate-based drilling and completion fluids is the carbonate / bicarbonate pH buffer (See Section A6 pH and buffering). Additives that are used when required are pseudoplastic viscosifiers for rheology modification and filtercake materials (bridging agents and polymers) for fluid loss control. Other additives that are normally not used, but could potentially give some benefits under extreme conditions, are H2S scavengers, oxygen scavengers, and antioxidants.

B5.2 Biopolymer compatibility

Biopolymers are commonly used as viscosifiers and fluid loss control agents in a variety of oilfield fluids. Formate brines have a unique ability to stabilize biopolymers to very high temperatures. Other high-density oilfield brines suffer from severe limitations in their compatibility with these polymers at high temperatures. Furthermore, heavy divalent brines (CaCl2, CaBr2, and ZnBr2) cause additional incompatibility problems at all temperatures due to problems of hydration and cross linking.

Polymers behave differently when they are exposed to high temperatures. Some polymers, typically biopolymers, have what is called a transition temperature. When these polymers are heated to their transition temperature a sudden drop in viscosity is experienced. Other polymers, without a transition temperature, lose their viscosity gradually as they are heated.

B5.2.1 Compatibility with xanthan gum

The most commonly used biopolymeric viscosifier, xanthan gum, is a high molecular weight poly-saccharide. It has a high degree of viscoelasticity and forms fluids with excellent shear thinning rheology. Transition temperature of xanthan gumWhen the xanthan gum molecule is exposed to high temperatures, it undergoes an order-disorder conformational change. The temperature at which this conformational change occurs is called the transition temperature or the melting temperature (Figure 1).

This conformational change is accompanied by a massive loss in viscosity (Figure 2) and an increase in the rate of hydrolytic degradation by two orders of magnitude. The polymer will regain some viscosity when the temperature is lowered below its transition temperature if the exposure time is short. After long duration exposure to temperatures above the transition temperature the polymer will degrade, and experience a permanent loss of viscosity.

The transition temperature of xanthan gum depends on the nature and concentration of the other solutes present in the medium in which it is dissolved. Shell researchers Clarke-Sturman and Sturla [1] discovered in 1986 that high levels of alkali metal formates in solution had the ability to raise the transition temperature of xanthan and enhance its stability at high temperatures (see Figure 3).

The transition temperature of xanthan in formate and a variety of other brines has been measured [2] and compared in Figure 4.

Long-term stability of xanthan gumThe effects of various oilfield brines on the transition (melting) temperature of xanthan can have an immediate impact on the downhole rheology of drilling and completion brines, but they cannot be used to predict absolute temperature stability limits in the field. Even though a particular brine might maintain xanthan in its ordered state, preventing catastrophic viscosity collapse, the polymer molecules may still degrade over time as a result of oxidative and hydrolytic attack.

The amount of time the xanthan polymer needs to be stable in the fluid at a given temperature depends on the application. For drilling fluid formulations, some degree of stability over a period of 16 hours is generally considered to be about right. The 16-hour stability limit of xanthan in some standard oilfield brines has been measured by Shell [2]. The thermal stability limit in these experiments was defined as the temperature at which the fluid experienced a 50% permanent loss of viscosity


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after exposure for 16 hours. Figure 5 shows how the 16-hour thermal stability limit of xanthan compares to its transition temperature in a range of saturated oilfield brines.

B5.2.2 Stability of starch and PAC

The typical biopolymers used in water-based drilling fluids are xanthan gum, PAC (poly anionic cellulose), and a variety of starches. Although the latter do not have transition temperatures like xanthan, it has been shown [2] that the temperature stability of these two polymers is also dependent on the solute type and concentration in the base solvent. The 16-hour thermal stability temperature is again defined as the temperature at which the polymers experience a 50% viscosity loss after 16 hours’ exposure. Figure 6 shows the 16-hour stability temperature for xanthan, an ultralow viscosity PAC (Antisol FL10), and a commonly used cross-linked derivatized starch (TBC FL7 plus) in a variety of saturated oilfield brines.

B5.2.3 Compatibility with other biopolymers

Formate brines are also very compatible with other biopolymers such as:• Chitin:a natural polysaccharide composed of

long-chains of acetyl-glucosamine (derived from oyster shells).

• Scleroglucan:a neutral non-ionic polysaccharide derived from fungal fermentation.

• Microfibrouscellulose(MFC): this product is available from Baroid under the tradename of N-Vis-HB (formerly Kelco’s ‘Cellulon’) It is a polysaccharide, with the same polymeric cellulose backbone as xanthan, but it behaves very differently from xanthan or scleroglucan in that it is only partially soluble in brines. In addition to providing some viscosity, this polymer also imparts some fluid-loss control properties.

• Guargum: a self cross linking polymer that is compatible with high pH fluids. In formate brines,

Guar gum has been found to be useful in the following applications:

- Clear lost circulation material.- To encapsulate aerogel type materials.

A biopolymer that is incompatible with formate brines is Hydroxyethyl Cellulose (HEC). This polymer requires a relatively low pH in order to hydrate and is therefore incompatible with formate brines.

B5.2.4 Stretching the limits

Various chemicals have been used to further extend the stability of polymers in formate brines. These chemicals (e.g. magnesium oxide, potassium iodide, glycols and amines) all offer additional antioxidant capacity and may extend the polymer thermal stability ceiling significantly. A potassium formate milling fluid with xanthan gum was formulated with a 16-hour temperature stability at 204°C / 400°F. This fluid was later successfully used at the same temperature in the field [14].

B5.3 Compatibility with synthetic polymers

Formate brines are compatible with many commercially available synthetic polymers that are used for viscosity and fluid-loss control.

B5.3.1 Synthetic viscosifiers – the ‘4mate-Vis’ family

Three synthetic polymers 4mate-vis-HT, 4mate-vis-HML and 4mate-vis-XHT-HML are offered by Cabot Specialty Fluids specifically to provide rheology control in formate fluids at high temperatures.

4mate-vis-HT4mate-vis-HT is a synthetic AMPS (Acrylamido-methyl-propane sulfonate) co-polymer specially developed for use in formate brines. This is a linear polymer, and does not exhibit pseudoplastic rheology. Because of this its use is limited to high temperature sweeps and displacement pills. It can be used at temperatures up to 218°C / 425°F, and is stable for 30 days at 190°C / 375°F.

Table 1 and Table 2 show the rheological properties of a 2.3 s.g. cesium formate brine viscosified with 10 and 12 ppb of 4mate-vis-HT and hot rolled for 16 hours at 190°C / 375°F. Fann 70 test results indicate that at concentrations of 10 ppb and higher, the polymer provides very good rheological properties up to 204°C / 400°F.

Figure 7 shows long-term stability of 4mate-vis-HT. Rheological properties for 6 ppb 4mate-vis-HT in a 2.3 s.g. cesium formate brine at 190°C / 375°F are shown as a function of time.

Figure 1 Behavior of xanthan gum when heated to its transition (melting) temperature


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Vis

cosi

ty

Temperature

Transition temperature

Thermal thinning

Reversible

0

5

10

15

20

25

30

35

40

45

40 60 80 100 120 140 160 180 200

Temperature [°C]

Vis

cosi

ty [c

P] Water

Potassium formate

Figure 2 Viscosity of a typical biopolymer with transition temperature (e.g. xanthan) as a function of temperature.

Figure 3 Viscosity (Fann 35, 300 rpm reading equivalent) of xanthan in water and in a potassium formate brine as a function of temperature.


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Xanthan transition temperature vs. brine density

70

80

90

100

110

120

130

140

150

160

170

180

190

200

210

1 1.05 1.1 1.15 1.2 1.25 1.3 1.35 1.4 1.45 1.5 1.55 1.6 1.65

Specific gravity

Tran

sitio

n te

mp

erat

ure

[°C

]

Potassium formatePotassium chlorideSodium formateSodium chlorideCesium formate

Sodium bromideCalcium chlorideZinc bromideCalcium bromideWater

Xanthan transition temperature vs. brine density

160

180

200

220

240

260

280

300

320

340

360

380

400

420

8 8.5 9 9.5 10 10.5 11 11.5 12 12.5 13 13.5 14

Density [ppb]

Tran

sitio

n te

mp

erat

ure

[°F]

Potassium formatePotassium chlorideSodium formateSodium chlorideCesium formate

Sodium bromideCalcium chlorideZinc bromideCalcium bromideWater

METRIC

FIELD

Figure 4 Transition temperature of xanthan in oilfield brines as a function of brine density.


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Figure 5 16-hour stability temperature for xanthan in concentrated commonly used oilfield brines compared to the transition temperature for xanthan in the same brines.

Stability of xanthan as a function of brine type

160 180 200 220 240 260 280 300 320 340 360 380 400 420

KFo [13.26 ppg]

NaFo [11.01 ppg]

KCl [9.67 ppg]

NaBr [12.76 ppg]

CaCl2 [11.59 ppg]

Freshwater [8.34 ppg]

Temperature [°F]

Transition temperature16-hour stability temperature

Stability of xanthan as a function of brine type

80 90 100 110 120 130 140 150 160 170 180 190 200 210

KFo [1.59 s.g.]

NaFo [1.32 s.g.]

KCl [1.16 s.g.]

NaBr [1.53 s.g.]

CaCl2 [1.39 s.g.]

Freshwater [1.0 s.g.]

Temperature [°C]

Transition temperature16-hour stability temperature

METRIC

FIELD


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Figure 6 16-hour stability temperature for xanthan, PAC, and starch in concentrated oilfield brines.

Stability of biopolymers as a function of brine type

0 50 100 150 200 250 300 350 400

KFo [13.26 ppg]

NaFo [11.01 ppg]

KCl [9.67 ppg]

NaCl [9.92 ppg]

NaBr [12.76 ppg]

CaCl2 [11.59 ppg]

Freshwater [8.34 ppg]

Temperature [°F]

XanthanPACStarch

Stability of biopolymers as a function of brine type

0 20 40 60 80 100 120 140 160 180 200

KFo [1.59 s.g.]

NaFo [1.32 s.g.]

KCl [1.16 s.g.]

NaCl [1.19 s.g.]

NaBr [1.53 s.g.]

CaCl2 [1.39 s.g.]

Freshwater [1.0 s.g.]

Temperature [°C]

XanthanPACStarch

METRIC

FIELD


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S E C T I O N B 5

4mate-vis-HML4mate-vis-HML is a second generation version of 4mate-vis-HT. It is a hydrophobically modified AMPS-based polymer used for rheology control. The hydrophobic effect of this polymer is strong enough to impart pseudoplasticity to a temperature of about 200°C / 400°F. This polymer is suited as a HT drilling fluid viscosifier. 4mate-vis-XHT-HML4mate-vis-XHT-HML is a third generation version of 4mate-vis-HT.

4mate-vis-XHT-HML is similar to 4mate-vis-HT-HML in that it incorporates about 0.2% C16 hydro-phobic side groups, which associate in solution and provide good low-end rheology. However the polymer backbone is acrylate based. This provides further thermal stability to an expected level of

around 260°C / 500°F. This polymer is suited as a XHT formate drilling fluid viscosifier. Rheological properties of 4mate-vis-XHT-HML are shown in Table 3. 4mate-visfielduse4mate-vis-HT and 4mate-vis-HML are available in 25 lb sacks. 4mate-vis-HT has been used in several applications in the North Sea and the Gulf of Mexico. 4mate-vis-XHT-HML is currently being commercialized.

4mate-vis-HT and 4mate-vis-HT-HML are both registered under the OSPAR HOCNF scheme. They have both passed the OSPAR HOCNF North Sea biodegradation and bioaccumulation tests, which makes them acceptable for discharge into the North Sea.

Table 1 Fann 35 and Fann 70 readings on a 2.2 s.g. / 18.3 ppg cesium formate brine containing 28.53 kg/m3 / 10 ppb 4mate-vis-HT.

Temperature Pressure 600 rpm

300 rpm

200 rpm

100 rpm 6 rpm 3 rpm PV

[cP] YP

[#/100 ft2]Gels

[10"/10'][°C] [°F] [MPa] [psi]

24 751) 0 0 300+ 233 183 114 18 12 - - 12/12

24 75 0 0 >295 231 174 112 16 11 - - 10/-

49 1201) 0 0 223 142 108 69 11 7 81 61 7/8

49 120 0 0 248 149 116 73 7 7 99 50 4/-

66 1501) 0 0 177 113 87 55 9 5 64 49 6/7

66 150 0 0 203 126 100 62 6 5 77 49 4/-

66 150 6.9 1,000 202 131 102 64 6 6 71 60 5/5

80 175 6.9 1,000 - 118 88 - - - - - -

93 200 6.9 1,000 159 102 81 49 5 5 57 45 5/-

93 200 20.7 3,000 164 105 82 50 5 5 59 46 5/5

93 200 44.8 6,500 169 108 85 52 5 5 61 47 4/4

107 225 44.8 6,500 - 100 74 - - - - - -

121 250 55.2 8,000 140 89 68 41 4 4 51 38 4/-

121 250 68.9 10,000 143 91 72 42 4 4 52 39 3/3

135 275 68.9 10,000 - 81 62 - - - - - -

149 300 68.9 10,000 113 72 55 31 3 2 41 31 3/-

149 300 89.6 13,000 121 74 56 33 3 2 47 27 3/3

177 350 68.9 10,000 101 60 45 26 3 2 41 19 2/2

177 350 82.7 12,000 101 60 45 26 3 2 41 19 2/2

191 375 82.7 12,000 94 55 41 24 2 2 39 16 -

191 375 110.3 16,000 95 57 43 24 2 2 38 19 -

1) Fann 35 readings


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Table 2 Fann 35 and Fann 70 readings on a 2.2 s.g. / 18.3 ppg cesium formate brine containing 34.24 kg/m3 / 12 ppb 4mate-vis-HT.

Temperature Pressure Fann readings [#/100 ft2] PV YP [°C] [°F] [MPa] [psi] 600 rpm 300 rpm 200 rpm 100 rpm 6 rpm 3 rpm [cP] [#/100 ft2]

24 751) 0 0 300+ 210 162 105 16 10 - -

24 75 0 0 >293 >293 252 161 25 15 - -

49 1201) 0 0 224 144 111 71 10 6 80 64

49 120 0 0 >293 199 153 100 13 8 - -

66 1501) 0 0 190 123 94 60 8 5 67 56

66 150 0 0 265 161 128 83 10 6 104 57

66 150 6.9 1,000 272 166 131 85 10 6 106 60

80 175 6.9 1,000 - 144 116 - - - - -

93 200 20.7 3,000 205 132 103 64 7 5 73 59

93 200 44.8 6,500 212 136 105 67 9 5 76 60

107 225 44.8 6,500 - 124 92 - - - - -

121 250 55.2 8,000 170 109 86 52 6 3 61 48

121 250 68.9 10,000 174 112 87 53 6 3 66 46

135 275 68.9 10,000 - 103 80 - - - - -

149 300 68.9 10,000 144 91 70 43 3 2 53 38

149 300 89.6 13,000 152 97 75 45 6 3 55 42

163 325 89.6 13,000 - 89 67 - - - - -

177 350 68.9 10,000 129 80 60 36 3 2 49 31

177 350 82.7 12,000 127 79 59 36 3 2 48 31

191 375 82.7 12,000 117 71 53 31 2 1 46 25

191 375 110.3 16,000 120 73 56 33 3 2 47 26

204 400 103.4 15,000 106 64 48 28 1 1 42 24

204 400 110.3 16,000 110 67 49 29 1 1 43 24

1) Fann 35 readings

Table 3 Rheological properties of 5.71 kg/m3 / 2 ppb 4mate-vis-XHT-HML in cesium formate brine. Readings are taken on an OFITE Model 800 viscometer at 49°C / 120°F.

Rpm [cP]Unaged 16 hours at 232°C / 450°F 16 days at 232°C / 450°F

Reading Viscosity [cP] Reading Viscosity [cP] Reading Viscosity [cP]

600 29 14.5 31 15.5 22 11

300 14 14 17 17 12 12

200 9 13.5 12 18 8 12

100 5 15 8 24 5 15

60 4 20 4 20 3 15

30 2 20 3 30 2 20

6 2 100 2 100 2 100

3 1.5 150 2 200 1.5 150

PV 15 14 10

YP -1 3 2


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S E C T I O N B 5

B5.3.2 Acrylamide copolymer

An acrylamide copolymer known as Kemseal from BHI has successfully been used as an HT fluid-loss polymer in formate fluids. This polymer, with its exceptional temperature stability, is suited for all HT well conditions. In the laboratory, Kemseal can easily be sheared into the drilling fluid formulation with a high-shear mixer. In the field, however, Kemseal can be a problem to get into solution because it requires significant shearing and heating to get it to hydrate. Any Kemseal that does not hydrate properly in a drilling fluid will be quickly stripped out on the shale shaker screens.

B5.3.3 DrisTemp

DrisTemp, a low-viscosity fluid-loss polymer from Drilling Specialties, is very compatible with formate brines.

B5.4 Compatibility with clays

B5.4.1 Sepiolite

Sepiolite is a clay mineral – a complex magnesium silicate with a typical formula Mg4Si6O15(OH)2·6H2O. It occurs as fine fibrous particles and can be used as a viscosifier in formate brines. Cesium formate brines viscosified with Sepiolite can exhibit good, stable rheology up to 200°C / 392°F.

B5.5 Compatibility with lubricants

High-concentration formate brines are very lubricious (See Table 4 and Section A8 Lubricity) and in most applications there is no need to add lubricants. Even when solids are added to formate brines, the lubricity is still significantly lower than that of pure water.

Table 4 Lubricity of various types of fluids as measured by use of the HLT lubricity tester.

Fluid Metal-to-metal

Metal-to-sandstone

Water-based, 15.0 lb/gal1) 0.264 0.338

Diesel-based, various weights1) 0.180 0.223

Mineral-based, various weights1) 0.223 0.231

Synthetic-based, various weights1) 0.181 0.253

Potassium / cesium formate2) 0.162 0.144

1) Average COFs over several years measured with same instrument

2) Average COFs over all temperatures

A number of lubricants have been laboratory tested in formate fluids, both with and without solids present. From these tests, it is clear that the best method of maintaining the natural lubricity of formate-based fluids is to keep the solids content to the absolute

Effect of hot rolling (190°C / 375°F) on rheological properties of 4mate-vis-HT viscosifier in 2.3 s.g. cesium formate

0

10

20

30

40

50

60

70

0 100 200 300 400 500 600 700 800

Time hot rolled [hours]

Flui

d P

rop

ertie

s

Apparent viscosity [cP]Plastic viscosity [cP]Yield point [lbs/100 sq. ft.]

Figure 7 Rheological properties of 17.12 kg/m3 / 6 ppb 4mate-vis-HT in a 2.3 s.g. cesium formate brine. Hot rolling temperature is 190°C / 375°F.


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P A G E 1 1S E C T I O N B 5

minimum. Keeping the bridging material levels as low as possible and optimizing the solids removal equipment should give the best lubricity. Solids-free drilling fluids based on monovalent brines (KCl, NaCl, NaFo, and KFo) are successfully used by BP in Alaska [3]. Low fluid loss in the absence of filter-cake bridging solids is enabled by the viscoelastic properties of the xanthan polymer used in these fluids.

Laboratory testing has also indicated that some lubricants could potentially further reduce metal-to-metal friction in formate drilling fluids, but it seems that high-dose levels of lubricant are required to achieve any effect. Field testing would definitely be needed to confirm the laboratory results before any specific lubricant could be recommended.

As the presence of solids influence the performance of a lubricant, any laboratory tests should be conducted in both clear brine and full drilling fluid formulations containing drilled solids. Care should also be taken to screen out any lubricants that could cause foaming or formation damage.

Cabot Specialty Fluids has very limited field experience with using lubricants in formate brines. The data contained in this section are therefore mainly the results of laboratory testing.

B5.5.1 Laboratory testing

Lubricant testing at WestportWestport Technology Center International has conducted an extensive study on compatibility of lubricants with formate brine and drilling fluid [4]. A total of 24 lubricants were included in the study. A preliminary screening test with 3 %v/v lubricant added to formate brine showed that some of these lubricants were incompatible with the brine. The lubricants that appeared to be compatible with the brine were added to a cesium / potassium formate drilling fluid with and without 10 ppb HMP clay added and tested on a Baroid Lubricity Meter (BLT). The composition of the base mud is shown in Table 5. A solids-free drilling fluid was also tested (i.e. no calcium carbonate bridging material added). Liquid lubricants were added at 3 %v/v. Solid lubricants were added at 5ppb. Readings were taken after one minute, three minutes and five minutes. The average coefficient of friction values derived from these readings are shown in Table 6.

Three of the lubricants that looked promising in the BLT test (RX 72SXE, Bio-Add 628, and Radiagreen 7857EBL) were then tested in the Westport / M-I HLT Lubricity Tester along with the liquid lubricants Ultralube II and Kemlix 7501X, and one solid lubricant (SAB 854P). Both metal-to-metal and metal-to-sandstone tests were conducted. All tests

were run at room temperature (24°C / 75°F), at a bob speed of 150 rpm and with a fluid flow rate of 2.0 gallons per minute. Contact force with metal-to-metal was 125 lbf. Contact force with metal-to-sandstone was 100 lbf. The base carrier fluid used in this testing was a cesium / potassium formate drilling fluid with 10 ppb HMP clay added. The results of this round of testing are shown in Table 7 (under Test Program I). This table also lists the test results for the lubricants FO5 from Lamberti and PA 4002 from Precision Additives that were tested in the same mud formulation as part of a separate project [5] (Test Program II). Figure 8 and Figure 9 show the metal-to-metal and metal-to-sandstone coefficient of friction for all lubricants as a function of dosage level for the fluids with liquid lubricants.

By comparing the results from the BLT tester and the Westport / M-I HLT Lubricity Tester, the following conclusions can be made:

• Theformatebrineonitsownisextremely lubricious (COF = 1/10 of that of water). (See also Section A8 Lubricity).

• TheCOFofformatedrillingfluidincreaseswiththe amount of solids present, i.e. bridging material (CaCO3) and drilled solids (HMP clay).

• Evenwithahighloadingofsolids(30ppbCaCO3 and 10 ppb HMP clay) the COF of the formate drilling fluid is still significantly lower than in pure water.

• SomelubricantswereabletolowertheCOFinthe solids-laden drilling fluid, but not enough to overcome the adverse effect of the solids.

• Althoughthelubricantsappearedtohaveamoreprofound effect in the BLT instrument, there was fairly good consistency between the COF reductions that were obtained in the two testers (i.e. the lubricants that lowered COF did so in both testers and the ones that increased COF did so in both testers). The levels of reduction that were seen with 3 %v/v lubricant addition in the BLT tester were very similar to the levels seen with 5 %v/v lubricant addition in the HLT tester.

Table 5 Composition of base mud for lubricity study. 10 ppb HMP clay was added to the formulation in certain tests.

Component Concentration

2.2 s.g. CsFo 589.19 g

1.57 s.g. KFo 105.77 g

N-vis HB 1 ppb

Kemseal 2 ppb

XanVis 1.5 ppb

Chemstar Xstar HT 4 ppb

Potassium carbonate 4 ppb

Potassium bicarbonate 2 ppb

KOH 2 ppb

Fordacal 100 30 ppb


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Table 6 Coefficient of friction in a buffered potassium / cesium formate mud measured with a Baroid Lubricity tester (BLT). The listed coefficient of friction is the average of three readings (1 min, 3 min, 5 min). All lubricants are added at 3 %v/v (except as noted in the table). Lubricants that gave an improvement of more than 20% are shown in green. Lubricants that increased the coefficient of friction are shown in red.

Fluid

Base mud Base mud with HMP clay added

Base mud without calcium carbonate (i.e. solids free)

Avg. COF

Reduction with lubricant

added [%]

Avg. COF


added [%]

Avg. COF


added [%]

Water 0.330 - 0.343 0.330

CsKFo mud 0.105 - 0.145 0.030

RX 72SXE (Roemex) 0.087 17 0.103 29 0.035 -17

RX72SX (Roemex) 0.095 10 0.127 12 0.040 -33

RX 72TL (Roemex) 0.127 -21 0.140 3 0.030 0

Drill N Slide (Baroid) 0.120 -14 0.132 9 0.033 -10

G-Seal (solid 3 ppb) (M-I) 0.103 2 0.120 17 0.027 10

Monosurf (Integrity Chemical Co.) 0.098 7 0.112 23 0.023 23

Teqlube (BHI) 0.117 -11 0.102 30 0.020 33

Bio-Add 628 (Shrieve) 0.088 16 0.102 30 0.020 33

SAB 854P (solid 5 ppb) (Shrieve) 0.147 -40 0.147 -1 0.030 0

SAB 444L (solid 5 ppb) (Shrieve) 0.150 -3 0.083 -177

DTS 2002 0.100 31 0.023 23

Triple SSS (Prime ECO Fluids) 0.088 39 0.025 17

Radiagreen 733E (Oleon) 0.097 33 0.020 33

Radiagreen 7857EBL (Oleon) 0.095 34 0.023 23

Thuslick – HF (solid 5ppb) (Prime ECO Fluids) 0.095 34 0.060 -100

EMI-742 (M-I) 0.103 29 0.030 0

ID Lube XL (M-I) 0.115 21 0.010 67

DT Triple SSS (Tech Oil) 0.152 -5


V E R S I O N 2 – 1 2 / 0 9



Table 7 Coefficient of friction in a buffered potassium / cesium formate mud with 10 ppb HMP clay added as measured with the Westport / M-I HLT Lubricity tester. Lubricants that gave an improvement of more than 20 % are shown in green. Lubricants that increased the coefficient of friction are shown in red.

Fluid Lubricant conc.

Metal-to-metal Metal-to-sandstone

Average COFReduction with lubricant added

[%]Average COF

Reduction with lubricant added

[%]

TEST PROGRAM I

Water 0.326 0.513

Base mud +10 ppb HMP clay

0.268

Radiagreen 7857EBL (Oleon)

3 %v/v5 %v/v

0.2260.195

16 0.2290.205

253327

Ultralube II (Integrity Chemical Co.)

3 %v/v5 %v/v

0.2570.197

4 0.2520.224

1726 27

RX 72SXE (Roemex)

3 %v/v5 %v/v

0.2300.205

14 0.2410.204

213323

Bio-Add 628 (Shrieve)

3 %v/v5 %v/v

0.2650.210

1 0.2470.270

191122

Kemlix 7501X 3 %v/v 0.275 -3 0.263 14

SAB 854P (solid) (Shrieve) 6 ppb 0.283 -6 0.298 2

TEST PROGRAM II

Water 0.318 0.576

Base mud +10 ppb HMP clay

0.245 0.305

FO5 (Lamberti)

3 %v/v5 %v/v

0.2080.170

15 0.2380.241

222131

PA 4002 (Precision Additives)

3 %v/v5 %v/v

0.2140.248

13 0.2090.232

3124-1

NB: The measured value of metal-to-sandstone COF for Test I appears to be erratic. It is therefore not possible to use this value to calculate the reduction in COF with lubricant added. As the exact same mud formulation was used for both of these tests programs, the base fluid metal-to-sandstone COF for Test II was used for the Test I calculations.

• UsingtheHLTtester,asignificantreductioninthecoefficient of friction was seen with many of the lubricants when increasing the dosing level from 3 %v/v to 5 %v/v.

LubricitytestingofM-ISwaco’sStarglide lubricantM-I Swaco has run lubricity tests on a typical formate-based drilling fluid with and without lubricant [6]. The lubricant, EMI-742 (Starglide), was tested at 1, 2, and 3 %v/v. The testing was completed with a LEM III lubricity tester.

As shown in Table 8, the addition of 3 %v/v Starglide lubricant gave the lowest metal-to-metal coefficient of friction (COF). A reduction of 28% was achieved, which is identical with the COF reduction measured with the same lubricant in the BLT tester (see Westport test results on previous page).

Table 8 COF in a formate drilling fluid as a function of the amount of Starglide lubricant added. The measurements were performed by M-I Swaco with a LEM III lubricity tester.

Volume of lubricant

Average COF

Reduction in COF%

0 0.121 -

1 %v/v 0.112 8

2 %v/v 0.118 3

3 %v/v 0.087 28

LubricitytestingofFinagreenSLandFinagreenEBL lubricantsLubricity testing was undertaken by Fina using a 1.85 s.g. potassium / cesium formate drilling fluid [7]. The base fluid formulation is shown in Table 9. The torque levels were measured with a load of 150 inch/lbs, and are shown in Table 16 for various concentrations of lubricant.


P A G E 1 4 V E R S I O N 2 – 1 2 / 0 9


S E C T I O N B 5

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

Coe

ffici

ent

of fr

ictio

n

Metal-to-metal lubricity

PA 4002 (5 %v/v)

PA 4002 (3 %v/v)

FO5 (5 %v/v)

FO5 (3 %v/v)

Kemlix 7501X (3 %vol)

Bio-Add 628 (5 %vol)


RX72SXE (5 %vol)

RX72SXE (3 %vol)

Ultralube II (5 %vol)


Radiagreen 7857 (5 %vol)


Base mud + 10 ppb HMP clay

CsKFo brine

Water

Coe

ffici

ent

of fr

ictio

n

Metal-to-sandstone lubricity

PA 4002 (5 %v/v)

PA 4002 (3 %v/v)

FO5 (5 %v/v)

FO5 (3 %v/v)

Kemlix 7501X (3 %vol)



RX72SXE (5 %vol)

RX72SXE (3 %vol)





Base mud + 10 ppb HMP clay

CsKFo brine

Water

0.0

0.1

0.2

0.3

0.4

0.5

0.6

Figure 9 Metal-to-sandstone lubricity of water, a cesium / potassium formate brine, a cesium / potassium formate drilling fluid with 10 ppb HMP clay added, and the same drilling fluid with 10 ppb HMP clay and various lubricants added. The COF for water is the average of the values measured in Test Program I and Test Program II. The COF for the drilling fluid with 10 ppb HMP clay is taken from Test II, as the value measured in Test program I is thought to be erratic. The COF for the cesium / potassium formate brine is taken from Table 4. The measurements are performed with the Westport / M-I HLT Lubricity Tester with a contact force of 100 lbf.

Figure 8 Metal-to-metal lubricity of water, a cesium / potassium formate brine, a cesium / potassium formate drilling fluid with 10 ppb HMP clay added, and the same drilling fluid with 10 ppb HMP clay and various lubricants added. The coefficient of friction (COF) for water and the drilling fluid with 10 ppb HMP clay are the average of the values measured in Test Program I and Test Program II. The COF for the cesium / potassium formate brine is taken from Table 4. The measurements are performed with the Westport / M-I HLT Lubricity Tester with a contact force of 125 lbf.


V E R S I O N 2 – 1 2 / 0 9



The results again show that the formate-based drilling fluid itself is already very lubricious and that the Finagreen SL and Finagreen EBL lubricants were both capable of further reducing torque.

Table 9 Drilling fluid formulation used in the lubricity testing of two Finagreen lubricants.

Component Quantity (g)

K formate 270.7

Fresh water 16.3

XCD polymer 0.4

PAC UL 4

Cs formate 313.6

CaCO3 50

NaOH pH = 10

Table 10 Lubricity test before ageing. Loading = 150 inch/lbs

Added lubricant [%v/v]

Torque readingFinagreen SL Finagreen EBL

0 4 5

0.5 1 5

1 0.5 5

2 0.5 4

3 0.5 1

4 0.5 1

Figure 10 shows coefficient of friction readings as a function of load for unaged and aged drilling fluid containing either 1 %v/v Finagreen SL or 2 %v/v Finagreen EBL. B5.5.2 Field experience

Even though considerable effort has been expended in searching for environmentally-benign, non-damaging lubricants that are compatible with high-density formate fluids, there have been very few recorded requests for lubricants in the field. On one occasion in the North Sea a Roemex lubricant was added to a high-density, formate-based drilling fluid formulation, but no significant benefit was detected.

For lower-density formate brines, there is one recorded instance where the addition of a lubricant had a dramatic effect on drilling performance by reducing torque and drag [8]. When drilling an underbalanced 6" well in the North Sea, an operator added BHI’s Teq-Lube lubricant to a sodium formate mud. Drilling torque in this section was reduced by up to 40% compared with historic or offset wells. Weight stacking and overpulls were reduced and sliding ability was improved significantly. These parameters were all measured in a two-phase flow environment: Nitrogen at around 1,000 scf/min and 450 pptf formate mud at 180 gpm.

Higher-density formate brines are already naturally lubricious and one instance of good field experience

Lubricity testing of Finagreen SL and Finagreen EBL

0

5

10

15

20

25

30

100 150 200 250 300 350 400 450

Loading [inch/lbs]

Coe

ffici

ent

of fr

ictio

nWithout lubricant – before ageing

Without lubricant – after ageing

1% Finagreen SL – before ageing

1% Finagreen SL – after ageing

2% Finagreen EBL – before ageing

2% Finagreen EBL – after ageing

Figure 10 Metal-to-metal COF readings in unaged and aged potassium / cesium formate drilling fluid as a function of loading with and without Finagreen lubricants added.


P A G E 1 6 V E R S I O N 2 – 1 2 / 0 9


S E C T I O N B 5

with adding a lubricant to a low-density formate brine does not necessarily mean that this same lubricant would be beneficial for a higher-density formate brine.

B5.6 Compatibility with weighting material

The formate brine family (sodium, potassium, and cesium formate) covers the whole density range required for drilling and completion fluids. The absence of any solid weighting material gives formate fluids some of their very unique properties, such as:

• Nosag• Compatiblewithreservoirs(resultinginlowskins)• Excellentwellcontrol• EfficienthydraulictransmissionandlowECDs• Lowswabandsurgepressures• Easyandefficientreclamation

Adding solid weighting material to formate fluids should therefore be avoided wherever possible, except in real emergencies.

All commonly used weighting materials are fully compatible with formate brines, but users should be aware that formate brines – like all concentrated brines – can solubilize low levels of barium from barite under hydrothermal (HPHT) conditions (see Section B12 Solubility of minerals in formate brines).

Barium is a toxic heavy metal, but its limited solubilization from barite in concentrated formate brines does not pose a health and safety hazard for oilfield workers [9].

Soluble barium is extremely toxic to aquatic organisms, but fortunately any barium in formate brines discharged into the sea will immediately recombine with sulfate that is present in the sea water and form non-toxic barite.

Barite solids discharged into the environment from drilling operations can be solubilized by sulfate- reducing bacteria under anaerobic conditions (e.g. in cuttings piles, or landfill sites), but the presence of formate brine in such discharges is unlikely to make the situation worse.

The main problem with barium contaminated formate fluids is related to onshore discharge and reclamation. Barium is very toxic, and any waste containing soluble barium should be treated (e.g. with hydroxide) to make the barium insoluble before disposal.

B5.7 Compatibility with corrosion inhibitors

High-density formate brines create a non-corrosive environment by virtue of their high pH, antioxididant properties, and compatibility with carbonate / bicarbonate buffers (see Section A6 pH and Buffering and Section B6 Compatibility with metals). No localized corrosion damage (e.g. pitting or SCC) has ever been reported in ferrous metals exposed to formate brines. The general corrosion rates are negligible, and corrosion inhibitors are not required. In fact, in the case of a massive influx of CO2 into the brine large enough to overwhelm the buffer, corrosion inhibitors could actually interfere with corrosion-inhibiting properties of buffered formate brine, and cause pitting corrosion. Adding any type of corrosion inhibitor to high- density formate-based fluids is therefore strongly discouraged.

Formate fluids of lower-density (i.e. consisting of less formate and more water) do not have as strong corrosion-inhibiting properties as the higher-density formate brines. Such low-density formate fluids might benefit from the addition of corrosion inhibitors.

B5.8 Compatibility with biocides

The sub-surface environment is rich in exotic micro- organisms, such as Archaea, that have adapted over billions of years to the extreme local conditions (e.g. no oxygen, high salinity, high temperatures, low nutrient levels). Any injection of new nutrients, such as sulfates, into this environment from well construction and reservoir pressure maintenance operations can have unfortunate consequences, e.g. increased growth of SRB populations leading to production of H2S and reservoir souring.

Drilling and completion fluids are generally excellent sources of new nutrients with the potential to encourage reservoir souring in the near wellbore area. They can also act as growth media for culturing exotic micro-organisms, and create effective vehicles for transferring troublesome micro- organisms, such as SRBs, from one well to another. It is important therefore that drilling and completion fluids are sufficiently biocidal or biostatic to inhibit the growth of these very tough and adaptable organisms when they are presented with a feast of new nutrients.

High-density formate brines in their concentrated state contain sufficient essential nutrients (C, N, P, K, S, etc.) to support a small microbial population, providing that a) the micro-organisms can survive and remain viable in such a low water activity environment and b) they are not killed by circulation


V E R S I O N 2 – 1 2 / 0 9



downhole under HPHT conditions. Laboratory tests have shown that pure cesium formate at concentrations of > 1 %v/v will not allow the survival or growth of aerobic general heterotrophic bacteria (GHB) or anaerobic SRBs isolated from platform seawater injection systems. More typical blends of potassium / cesium formate brine are less inhibitory, and appear to need to contain > 25 %v/v formate salt to prevent the survival of these organisms. These tests are useful but tell us little about the inhibitory effect of formate brines on extremophiles like Archaea, which are adapted to tough sub- surface conditions.

For the past nine years potassium / cesium formate brines have been used without biocides as completion, workover and suspension fluids in over 150 HPHT well operations. These brines seem to have remained sterile and free of viable micro-organisms, as adjudged by conventional micro-biological tests. Potassium / cesium formate brines have also been used without biocides as HPHT drilling fluids for the past nine years, again without any apparent problems. Recently, however, labora-tory tests with advanced FISH (fluorescent in situ hybridization) probes on some samples of potassium / cesium drilling muds returned from the field have shown the presence of viable Archaea and SRB in these fluids. It could be that they have merely been incorporated into the fluids during circulation around the mud pits and wellbore before back-loading, but their continued viability during fluid storage is currently being investigated.

Once this investigation is complete, Cabot Specialty Fluids should be in a position to advise on the best biocide(s) to use in formate-based drilling muds.

B5.9 Compatibility with H2S scavengers

The carbonate / bicarbonate buffer that is normally added to formate brines when they are used as well construction fluids provides useful protection against corrosion by H2S. The alkaline pH helps to push the chemical equilibrium towards the formation of bisulfide (HS–) from H2S (aq) (see Section A6 pH and Buffering):

1+−+ HHSSH apK

1

2

0.71=apK

→← (1)

The buffer capacity of carbonate / bicarbonate is enormous and large amounts of acid gas can be converted to HCO3

- and HS– before the pH starts dropping. The likelihood that the formate brine would ever receive a CO2 and / or H2S gas influx large enough to overwhelm the buffer during field

use is low, but as the consequences of this could be a certain loss of ductility in CRAs (see Section B6 Compatibility with Metals), the addition of an H2S scavenger could be beneficial.

The addition of H2S scavengers has additional benefits over the use of the buffer alone as the scavengers tie up the sulfide rather than changing the equilibrium. Additionally, the use of an additional H2S scavenger will help to remove any bisulfide from the formate brine. The pKa for H2S (7.0) is significantly lower than that for bicarbonate (10.2). Despite this, it has been found (see test results underneath) that at the pH formate brines are normally buffered to, the buffer is not capable of converting all of the H2S to HS–. In order to rely on the carbonate buffer to give a 100% conversion of harmful / corrosive H2S to HS–, the fluid would need to be buffered to a higher pH (i.e. buffered with a higher carbonate to bicarbonate ratio).

Some of the H2S scavengers that have been tested and found to work with formate brines are listed here. Cabot Specialty Fluids has no experience with the use of any of these H2S scavengers in the field.

B5.9.1 H2S scavengers that work in formates

IroniteSpongeA well-known H2S scavenger, Ironite Sponge®, has been found to be effective in formate fluids. Ironite Sponge reacts on contact with H2S or HS– to form mainly FeS2 (pyrite), which is safe and stable.

This scavenger is in a solid form, which makes it ideal for use in drilling fluids or in the process of removing residual HS– from formate brines during reclamation. After scavenging the HS– it can be removed completely from the brine by simple filtration, and does not leave any residues in the reclaimed brine. The fact that Ironite Sponge is a solid limits its application in clear completion fluids in the field. Irongluconate(SOURSCAV)Iron gluconate is a Fe(II) complex that is water soluble at high pH. This solids-free product reacts very rapidly on a stoichiometric basis with H2S and HS–. Iron gluconate formulations designed for H2S scavenging are supplied by Halliburton under the trade name SOURSCAV. SOURSCAV has been tested in the laboratory in buffered and unbuffered formate brines (see Section B5.9.2 underneath), and was found to be very effective. One of the few disadvantages of SOURSCAV is that it gives the brine a deep dark-black color (see Figure 11). Electrophilic organic compoundsSome water-soluble electrophilic organic compounds


P A G E 1 8 V E R S I O N 2 – 1 2 / 0 9


S E C T I O N B 5

are capable of scavenging H2S by binding up the sulfur in an organic form. Like the gluconate, these do not form any solids when reacting with H2S. Two of these products that are commonly used in the downstream business have been tested in buffered and unbuffered formate brines (see Section B5.9.2 underneath) and one of them was found to be very effective. Iron oxalateIron oxalate is another water-soluble H2S scavenger that is expected to be compatible with formate brine. Cabot Specialty Fluids is unaware of any testing undertaken on the compatibility between this scavenger and formate brine.

B5.9.2 OCT – comparison study

A study was carried out by Cabot Specialty Fluids and Oilfield Chemical Technology Limited, Aberdeen to determine the formate compatibility and the H2S scavenging capacity of three selected H2S scavengers [10][11]. The scavengers tested were:• GastreatK144–anelectrophilicorganic

compound from Champion Technologies• GastreatK155–anelectrophilicorganic

compound from Champion Technologies• SOURSCAV–irongluconatefromHalliburton• IroniteSponge FluidcompatibilityThe three H2S scavengers Gastreat K144, Gastreat K155, and SOURSCAV were added at 3 ppb to a standard formate drilling fluid to check if they had any adverse effect on the drilling fluid properties. The drilling fluid formulation was 2.05 s.g. cesium /potassium formate brine, containing potassium carbonate, xanthan, starch, PAC, and calcium carbonate. The fluid properties were measured before and after hot rolling for 16 hours at 121°C / 250°F and 150°C / 302°F. None of the scavengers had any significant or adverse effect on the drilling fluid properties. It is worth noting that at 3 ppb concentration the SOURSCAV lowers the brine density slightly (through dilution) and creates a slight drop in pH. SOURSCAV also turned the fluid black, both before and after hot rolling (see Figure 11). H2S scavenger performance testingSamples of formate brines with and without buffer and with and without added H2S scavengers were sent to OCT in Aberdeen for testing.

Exposure IInitial work was completed with a gas mixture of 4% CO2 and 120 ppm H2S. It was thought to be important to test H2S in combination with CO2 as CO2 consumes some of the carbonate buffer and thereby limits some of the natural inhibiting effect of

the buffered brine. The results are shown in Table 11. A couple of additional fluids were included. In one the amount of carbonate buffer was doubled (addition of an extra 5 ppb K2CO3), and in the other the bicarbonate buffer was converted to carbonate buffer by adding an excess amount of KOH. As can be seen from the results in Table 11 the buffered formate brine was capable of converting most of the 120 mg/L H2S to the more favorable HS–. The three fluids that contained H2S scavengers were able to scavenge all of the 120 mg/L H2S that was added. The addition of extra buffer to the brine left only trace amounts of unscavenged H2S / HS– and by adding KOH all of the H2S / HS– was scavenged. Fluid pH was not measured after this testing, so it is difficult to tell how much of the buffer had been overwhelmed. Both the addition of K2CO3 and KOH contributed to increasing buffer capacity of the brine (KOH somewhat more), which gave the brine the ability to scavenge just about all of the added H2S.

The results of this test program show that buffered formate brines are capable of scavenging a significant amount of H2S even when H2S is combined with an even larger amount of CO2. The fluid pH was not measured in this test, so it is not possible to conclude if the buffer was overwhelmed or not. All three scavengers that were tested did a good job in scavenging the remaining H2S. However, this test is not suitable for comparing the performance of the three H2S scavengers.

Exposure IIIn order to more closely compare the performance of the three H2S scavengers, testing had to be completed with a much higher H2S level. Similar testing was therefore carried out with pure H2S gas. In this test program the scavenging capacity of an unbuffered formate brine was used as a standard for comparing the performance of the scavengers. A potassium formate brine was selected as cesium formate contains a small amount of buffer from the production process. Although such an unbuffered brine is never used in the field, it does to some extent represent a brine where the buffer is totally overwhelmed by CO2. The results of this testing are listed in Table 12. The results show that SOURSCAV, K155, and Ironite Sponge are all capable of scavenging large amounts of H2S. As opposed to the previous test, K144 did not seem to have any scavenging capability. Whether this is related to the presence of potassium ions instead of cesium ions or the fact that the brine contains no buffer (lower pH) would need to be investigated. The buffer itself is also capable of scavenging a large amount of H2S. As the fluid pH is still rather high after the testing, buffer is not overwhelmed. Therefore, if one would wish to rely on only the buffer for protection against H2S, it is recommended to keep


V E R S I O N 2 – 1 2 / 0 9



a high pH (i.e. only carbonate, no bicarbonate). In spite of the pKa of H2S being as low as 7.0, a pH level of around 10.5 does not seem to be enough to push the H2S / HS– equilibrium reaction all the way over to HS–.

B5.9.3 Ironite Sponge testing at Westport

Westport Technology Center International carried out some testing on the capability of Ironite Sponge to scavenge H2S in a buffered cesium formate brine [13]. ExperimentalA series of tests was conducted on a 1.65 s.g. buffered potassium / cesium formate brine charged

with 100% H2S gas. The contaminated fluid was hot rolled for 24 hours at 66°C / 150°F before it was tested for H2S. The brine was tested with and without the addition of 40 ppb Ironite Sponge.

Between 2,700 and 3,200 ppm H2S was introduced into the test fluids. After hot rolling for 24 hours at 66°C / 150°F, the base potassium / cesium formate fluid contained 690 ppm H2S (74.74% H2S removed) and the formate brine with 40 ppb Ironite Sponge contained only 6 ppm H2S (99.82% H2S removed). See Table 13.

Table 11 Results from exposure of a buffered cesium formate brine to a H2S / CO2 gas mixture (4% CO2, 120 ppm H2S). The cesium formate brine is buffered with 10 ppb K2CO3 and KHCO3 (ratio 5:3). 8.2 mL test solution was tested in a 115 mL bottle pressurized to 15 psi with the gas mixture. The solution was exposed to the gas for one hour at 90°C / 194°F.

Test solution Total amount of H2S purged (mg/l)

Amount H2S not scavenged (mg/l)

Amount H2S scavenged in test

solution (mg/l)

Additional H2S scavenged (mg/l)

Buffered CsFo 120 35 85 N/A

Buffered CsFo + 3 ppb SOURSCAV® 120 0 120 35

Buffered CsFo + 3ppb K144 120 0 120 35

Buffered CsFo + m3 ppb K115 120 0 120 35

Buffered CsFo + 5 ppb K2CO3

120 Trace Trace

Buffered CsFo + 5 ppb KOH 120 0 120 35

Table 12 Results from exposure of an unbuffered KFo brine to H2S with and without H2S scavengers added. Tests of the KFo brine with a standard buffer (10 ppb K2CO3 and KHCO3 (ratio 5:3)) are also included. 8.2 mL test solution was tested in a 115 mL bottle pressurized to 15 psi with H2S. The solution was exposed to the gas for one hour at 90°C / 194°F.

Test solutionTotal amount of H2S purged

(mg/l)

Amount H2S not

scavenged (mg/l)

Amount H2S scavenged in test solution

(mg/l)

Additional H2S scavenged

compared to unbuffered

KFo brine (mg/l)

pH before pH after

De-ionized water 39,756 26,463 13,290 N/A 7.05 4.80

Unbuffered KFo 39,756 29,512 10,365 0 8.80 8.54

Buffered KFo – run 1 39,756 14,756 25,000 14,635 11.71 10.47

Buffered KFo – run 2 39,756 16,829 22,930 12,565 - -

Unbuffered KFo + 3ppb SOURSCAV® 39,756 7,683 32,075 21,710 8.4 7.86

Unbuffered KFo + 3ppb K144 – run 1 39,756 29,634 10,120 8.92 8.39

Unbuffered KFo + 3ppb K144 – run 2 39,756 32,195 7,560 - -

Unbuffered KFo + 3ppb K155 39,756 12,805 26,950 16,585 10.45 9.69

Unbuffered KFo + 40 pb Ironite Sponge 39,756 16,829 22,925 12,560 - 7.73


P A G E 2 0 V E R S I O N 2 – 1 2 / 0 9


S E C T I O N B 5

Figure 11 Black coloration of cesium formate brine as a consequence of adding SOURSCAV. The brine darkened immediately after the addition of the scavenger. Hot rolling was not required.

Table 13 H2S test results using 100% H2S gas in a 1.65 s.g. buffered KCsFo with and without Ironite Sponge.

KCsFo KCsFo + 40 ppb Ironite Sponge®

Initial pH 11.79

Initial pH (1:10 dil) 9.22

H2S in KCsFo [ppm] 2,731.85 3,322.65

H2S scavenged, [ppm] 2,041.85 3,316.65

Percent H2S removed 74.74% 99.82%

Final pH 8.86 9.11

Final pH (1:10 dil) 7.15 7.20

B5.10 Compatibility with antioxidants

Oxidants, such as O2, are known to cause problems in drilling and completion fluids. The formate ion is a well-known antioxidant or free radical scavenger, used in many industrial and medical applications. Some of the most important drivers for using formate brines for drilling and completion (for example their ability to stabilize polymers at high

temperature and their ability to inhibit corrosion) are direct consequences of this property. For most applications, the addition of antioxidants is therefore not required.

There are, however, some indications that the addition of an antioxidant can enhance polymer stabilization by formate brines at high temperatures. An example of this is stabilization of xanthan polymers to 204°C / 400°F in a milling job in a Tuscaloosa well [14]. The antioxidant was found to be an important component in the formulation of this fluid.

The well-known antioxidant magnesium oxide (MgO) has been a useful component in many high-temperature drilling fluid formulations. Many high-temperature formate mud formulations have shown improved performance when MgO has been added. Another antioxidant that has been found to be very compatible with formate-based fluids is sodium ascorbate.

B5.11 Compatibility with oxygen scavengers

The presence of oxygen in drilling and completion fluids is problematic. Oxygen is a strong oxidizing agent that can cause rapid degradation of polymers and it is one of the main causes of corrosion. Addition of oxygen scavengers is therefore critical in conventional drilling and completion fluids to scavenge this damaging gas.

As formates are strong antioxidants and the solubility of oxygen is very low in concentrated formate brines, the need to scavenge oxygen is much reduced, and addition of oxygen scavengers is not normal practice. There are, however, some indications that the addition of an oxygen scavenger can enhance polymer stabilization in formate brines at high temperatures [14]. In the Tuscaloosa milling fluid where xanthan was stabilized to 204°C / 400°F, the oxygen scavenger was found to be a critical component to obtain this performance.

For diluted formate brines, the use of oxygen scavengers is recommended.

The well-known oxygen scavenger, sodium erythorbate (sodium isoascorbate), is thought to be compatible with formate-based fluids.


V E R S I O N 2 – 1 2 / 0 9



B5.12 Compatibility with defoamers

Formate brines themselves are not surface active, and should not cause any foaming problems. Formate brines that have been contaminated during field use can occasionally show some foaming tendencies.

Cabot Specialty Fluids has occasionally experienced foaming in the boilers during the reclamation process. The defoamer LD-8V from Baker Hughes Inteq has successfully been used. This is a blend of vegetable oil and surfactants.

Foaming is normally not a problem in formate drilling fluids. Cabot Specialty Fluids has only had a couple of instances where foaming occurred when running a pump on the trip tank. When this occurred, the defoamer NF6 from Halliburton was used with good results.

References

[1] Clarke-Sturman, A.J., Pedley, J.B., and Sturla, P.L.: “Influence of anions on the properties of microbial polysaccharides in solution”, Int. J. Biol. Macromol., (December 1986) 8, 355.

[2] Howard, S.K., Houben, R.J.H., Oort, E. van, Francis, P.A.: “Report # SIEP 96-5091 Formate drilling and completion fluids – technical manual”, Shell International Exploration and Production, August 1996.

[3] Powell, J.W., Stephens, M.P, Seheult, J.M., Sifferman, T., and Swazey, J.: “Minimization Of Formation Damage, Filter Cake Deposition, & Stuck Pipe Potential In Horizontal Wells Through The Use of Time-Independent Viscoelastic Yield Stress Fluids and Filtrates”, IADC/SPE 29408, February-March 1995.

[4] Toups, J.A., Goldenberg, I., Vasquez, W.: “Progress Report on Cabot/Statoil/BP/TFE Kvitebjorn K72 Lubricity Testing”, Westport Technology Center International, Report # R-04-105, January 2004.

[5] Westport spreadsheet “HLT Testing, FO5 and PA 4002.xls”.

[6] M-I Norge Report: “LEM III test on Dipro and FormPro with Starglide”, Report No. LR-066-06, March 2006.

[7] Word document “Fina Results.doc”.

[8] “Santa Fe Britania. Teq-Lube Experience”,Shell – Barque PL-04, 17/07/00.

[9] “Soluble barium in potassium formate brines used for drilling and well completion fluids – possible impact on the working environment”, Report # ANBR 961/F72505.700, Hydro Corporate Research Center, 2003.

[10] “H2S Scavenger Compatibility Testing” and “Compatibility of Halliburton Sourscav with Formate Brine”, Cabot Operational & Technical Support Laboratory Short Report # LR-210, 2007.

[11] “H2S scavenger efficacy”, OCT report # 1181 OS, 2007.

[12] Toups, J.A.: ”H2S Scavenging Capability of a 1.65 sg Potassium / Cesium Formate Fluid with and without Ironite Sponge® For Cabot Specialty Fluids”, Westport Technology Center International, Report # DT-01-030, 2001.

[13] Messler, D., Kippie, D., Broach, M.: “A Potassium Formate Milling Fluid Breaks the 400° Fahrenheit Barrier in Deep Tuscaloosa Coiled Tubing Clean-out”, SPE 86503, Lafayette 2004.

[14] “LEM III test on DiPro and FormPro with Starglide”, Report M-I Norge AS, 2006.

Documents

Section B5 Compatibility with Additives