Brines and Other Workover Fluids

Brines and Other Workover Fluids Purposes Selection Filtration needs Placement Fluid Loss Control Cleanup and Displacement of Muds Limitations Alternatives 3/14/2009 1

Purposes of Brines 1. Mud displacement prior to cementing, 2. Debris removal, 3. Controlling formation pressures during completion and intervention operations, 4. Enabling repair operations as a circulating or kill fluid medium, 5. As packer fluids, 3/14/2009 2

Purposes of Brines (cont.) 6. In some stimulations as base fluids; 7. Enable cleanup of the zone prior to running screens; 8. Reduce friction while running screens & equipment; 9. Avoid damaging the well after completion, stimulation, or repair; 10. Allow other well operations to be conducted. 3/14/2009 3

Will Circulating a Well Really Clean It Out? Not necessarily. Clean-out efficiency depends on: Ability to remove the solids from returning fluids, Fluid hydraulics - the flow rates in every section, Ability to disperse, then lift solids out of the well, Ability to effectively remove the dope, mud cake, residues, etc., from the pipe walls. 3/14/2009 4

Returns from a cleanout scraper run dope, wireline grease, rust, mud, etc., are common components. 3/14/2009 5

Selection of the Brine Must Satisfy: 1. Well control at every phase of the operation. 2. Must be able to filter the brine to 5 to 10 microns with beta of 1000. 3. Compatibility with the formation, well equipment and all operations and fluids. 4. Corrosion and scale dropout must be controllable. 5. Cleanup requirements from the formation 6. Cleanup and disposal requirements at the surface 7. Cost and availability to fit the well. 3/14/2009 6

Brine Types and Respective Density Ranges Brine Type Brine Formula Density Range (ppg) Chloride Salt NaCl 8.4-10.0 Chloride Salt KCl 8.4-9.7 Chloride Salt NH4Cl 8.4-8.9 Bromide Salt NaBr 8.4-12.7 Mix NaCl/NaBr 8.4-12.5 Formate Salt NaHCO2 8.4-11.1 Formate Salt KHCO2 8.4-13.3 Formate Salt CsHCO2 13.0-20.0 Formate Salt KHCO2/CsHCO2 13.0-20.0 Formate Salt NaHCO2/KHCO2 8.4-13.1 Chloride Salt CaCl2 8.4-11.3 Bromide Salt CaBr2 8.4-15.3 Mix CaCl2/CaBr2 8.4-15.1 Bromide Salt ZnBr2 12.0-21.0 Mix ZnBr2/CaBr2 12.0-19.2 Mix ZnBr2/CaBr2/CaCl2 12.0-19.1 World Oil, Modern Sand Face Completion, 2003 3/14/2009 7

Lower Density Fluids Nitrogen gas 0.1 to 2.6 lb/gal water foam 3.5 to 8.3 lb/gal kerosene and diesel 6.7 to 7.1 lb/gal 20 o crude 7.8 lb/gal 30 o crude 7.3 lb/gal Most low density fluids are not be usable because of migration, flash point, or stability issues. 3/14/2009 8

Displacement and Pill Design The displacement must be designed to obtain effective mud removal (dispersement and lift) & water wetting of casing. Keys: disperse and thin the drilling fluid compatibility with the following fluids (brine, acid, cement, etc. lift out debris and junk water wet pipe remove pipe dope effectively displace the mud Source: Wellcert 3/14/2009 9

Brines for Displacement 1. A thinning base fluid flush. 2. An effective brine transition system must further thin and strip the mud and create wellbore displacement. 3. A carrier spacer must sweep out the solids and clean any coating from the pipe or rock that could cause damage problems. 4. A separation spacer must do the final cleaning and separate the residual mud from the brine. 5. The brine must sweep the spacer out. At this point the well should be clean. 3/14/2009 10

Cleaning and Transition Spacers Spacer Type Function Minimum Annulus Coverage Base Fluid Transition Thin & mud condition start dispersement Mud to spacer, cuttings removal WBM 250 to 500 ft Water, and some brines OBM Base oil (composition varies) 500 to 1000 Viscous pill Viscous Pill Wash Clean pipe 500 to 1500 Water+ WBM surfactant Oil + OBM surfactant Separation Completion Fluid Separate wash from completion brine 500 to 1000 Viscous pill Surfactant gel? Some water gels if compat. Completion fluid Fill Completion Fluid Completion Fluid 3/14/2009 11

Brine Flush Contact Times 9-5/8 casing in 12-1/4 hole, annular area = 0.3 ft 2 Pump Rate, bpm Annular Velocity, ft/min Barrels Pumped Column Length, ft Contact Time, minutes on one foot. 8 150 200 3743 25 10 187 400 7486 40 12 225 400 7486 33 3/14/2009 12

Flow profile in a well with decentralized pipe. Note That most of the flow comes along the top of the pipe. This affects cleanup and residence time of the fluid on the wellbore. The lower section of the wellbore may remain buried in cuttings and never have contact with any of the circulated fluids. Major flow area 3/14/2009 13

Displacement of the annulus to displace fluids and mud cake depends partly on velocity. The annulus changes as casing replaces the drill string. As the annular space decreases velocity for any rate increases in the smaller area and the back pressure on the bottom hole may also increase. Circulating down the casing and up the small annulus can produce very high friction pressure and raised BHP. 3/14/2009 14

Displacement Considerations Well control is key consideration in selection of the pill sequence. In many cases, it is only possible to get thin, light fluids into turbulence Pumping fluids to displace oil based fluids without suitable surfactant/solvent packages to disperse the mud can result in sludges that are insoluble except in aggressive solvents For deepwater wells, low temperatures can impact surfactant effectiveness 3/14/2009 15

Carrying Capacity Pills in turbulence lose carrying capacity if the annular velocity drops below that required for turbulence (e.g. entering larger diameter pipe such as a riser) In high mud weight, the risk of inducing barite sag needs to be considered if mud is thinned (displacement pills thin the mud to the point it can no longer support barite) 3/14/2009 16

LEARNING As depth and hole angle increase, the minimum pill volume (based on largest annular hole length) should increase to allow for contamination, e.g.: If MD < twice TVD, annular fill length > 80 m (260 ft), If MD > twice TVD, annular fill length > 125 m (410 ft), Contact time (the time that critical points in the well are exposed to the pill) depends on reaction of surfactant/solvent to mud. For surfactant pills, plan for contact times of greater than 4 minutes for best results. 3/14/2009 17

BEST PRACTICES AND DESIGN CRITERIA Good mud thinning fluid is continuous phase of the mud: for water based mud pumping 50 bbl (8m 3 ) of water as the first displacement pill will effectively thin mud, 50 bbl (8m 3 ) of the mud base fluid can be pumped in the case of oil based muds. (check oil compatibility) Before any displacement, the compatibly of the spacers with the mud and the ability to water wet steel surfaces should be checked at ambient and bottom hole temp to confirm compatibility. In deep water, tests at lower temperature will be needed 3/14/2009 18

BEST PRACTICES AND DESIGN CRITERIA All tests should be done on field mud samples to ensure mud is effectively sheared and has representative particles/cuttings Water wetting surfactants are generally effective >3% vol/vol concentration, little additional benefit is obtained above 10%. Solvents and mechanical or hydraulic agitation are required to remove sludges and pipe dope 3/14/2009 19

Displacement Displacement of mud from an annulus is complex. The main driving forces: time of contact flow rate and frictional forces density mechanical agitation pipe centralization 3/14/2009 20

RISKS AND ISSUES Fluid Interface area increases w/ hole angle In deviated wells the eccentricity of the displacement string may reduce displacement. Pipe rotation and/or reciprocation is needed. At low temperature (<40 o C/104 o F), OBM is very viscous ( synthetic based muds are worst), circulating to warm the annular contents reduces the problem. 3/14/2009 21

RISKS AND ISSUES High circulation rates may be better (even in laminar flow), they reduce the boundary layer thickness on the casing wall. (Watch wash-out potential of soft sands) Turbulence is best, flow rate must be calculated allowing for pipe eccentricity. A complete wellbore hydraulics check is necessary. High rates (300 ft/min?) may reduce the fluff (80% of the outer layer of the filter cake that does not contribute to fluid loss control); sharply reducing the amount of solids in the well without reducing fluid loss control. 3/14/2009 22

BEST PRACTICES AND DESIGN CRITERIA High flow rates will always be better even if turbulence cannot be achieved Pipe movement will improve displacement efficiency. Multi-function circulating subs should be used, currently the best tools open by setting weight down, incorporating a clutch mechanism to allow rotation. Do not stop displacement once pills enter the annulus Circulate to warm mud and fine up shakers (increase screen mesh number) to reduce particles in the fluid when possible, condition mud (reduce rheology). Use reverse circulation if possible when displacing with lighter fluids. 3/14/2009 23

Muds, Cakes, Breakers and Particles Drilling mud is the best known particulate based fluid loss control system. Particles are sized to bridge on the face of the formation. Carbonate and salt are most common. Breakers are acid, oxidizers and enzymes. Filter cakes very effective in preventing losses as long as over-balance pressure is maintained. Cakes are very sensitive to swabbing, but are never completely removed.. Tool systems sensitive to plugging by particulates. 3/14/2009 24

Particles Damage? Dirty particles, unsized particles, debris and pipe dope are severe formation damage problems. Protecting the perforations with the right particles during a workover improves chances of well improvement afterwards. The type of carrier fluid and the gels are v. important Clear (no particles) brines are not always best solution 3/14/2009 25

Particulate Pill Displacement A spacer or displacement pill for displacing a polymer system carring sized particulates should be 0.2 to 0.25 ppg heavier and about three times the low shear rate viscosity (at 0.06 sec -1 ) of the fluid being displaced. 3/14/2009 26

Data from a set of Alaska wells where the perforations were not protected during a workover. No protection shows significant long term damage. PI Change, Perfs Not Protected 40 20 PI of Wells 0.3 0.5 1.1 2.1 3.1 6 18.9 % Change in PI 0-20 -40-60 1 3 5 7 9 11 13 15 Short Term PI Change Long Term PI Change -80-100 SPE 26042 3/14/2009 27

When perfs were protected, that was little risk of long term damage. PI Change After Workover - Perfs Protected 50 40 30 PI of wells 0.3 1.2 3.1 4.6 8.4 % Change in PI 20 10 0-10 1 2 3 4 5 6 7 8 9 10 11 Short Term PI Change Long Term PI Change -20-30 -40 SPE 26042 3/14/2009 28

Sized particulates, particularly those that can be removed, are much less damaging than most polymers. Kill Pills: Summary of Overall Effectiveness in Non Fractured Wells 10 5 Sized Borate Salts (4) Cellulose Fibers (3) HEC Pills No Pills % Change in PI 0-5 -10-15 Sized Sodium Chloride (12) 1 2 3 4 5 6 7 No Near Perf Milling (6) No Near Perf Milling (8) -20-25 SPE 26042 Near Perf Milling or Scraping (3) Near Perf Milling or Scraping (10) 3/14/2009 29

Formation Damage by Gels Gels Linear gels not recommended for high overbalance or high permeability formations too much depth of damage. HEC is not always clean breaking. Breaker selection is critical to removing the damage from a linear gel. 3/14/2009 30

Linear HEC Pill needed per ft of zone, 80 lb/1000 gal or 3.36 ppb Pill Vol. Required, bbl per ft of zone 3 2.5 2 1.5 1 0.5 0 1000 750 500 250 Overbalance Pressure, psi 1 Darcy 500 md 250 md 100 md World Oil, Modern Sandface Completion Practices, 2003 3/14/2009 31

Fluid Loss Rate vs. Pressure Differential for Various Permeabilities Loss Rate, bbl / hr / ft of zone height 6 5 4 3 2 1 1 cp fluid, s = +5 500 md 250 md 100 md 50md 0 0 100 200 300 400 500 Overbalance Pressure, psi Modified from World Oil, Modern Sandface Completion Practices, 2003 3/14/2009 32

Breaker Breaker must stay with the part of the gel that causes the damage penetrate to the distance that gel penetrates, or stop at the wall with the gel wall cake. Breakers: Acid, internal breaker, or enzyme Many breakers adsorb or spend in the formation, before they work. 3/14/2009 33

Brine Stability The stability of the brines at high salt loadings can be very touchy with temperature drops causing salt precipitation. Increases in temperature decreases brine density and may leave the brine under-saturated to salt. Additions of gas, alcohol, some surfactants, shear and reduction in temperature can lead to salt precipitation. Salt may affect the way polymers hydrate or disperse. 3/14/2009 34

Brine Density (lb/gal) 17 16.8 16.6 16.4 16.2 16 15.8 15.6 15.4 15.2 NaCl Brine Density Variance with Temperature 20 o C 100 o C The reduction of brine density as it comes to equilibrium in the well may explain why a well can go from a no-flow condition to flow within a few hours after being killed. 15 60 110 160 210 260 310 360 Temperature (F) 3/14/2009 35 SPE 12490

Temperature Changes GOM Seafloor Temperature Water Depth, ft Sea Floor Temperature, F 35 40 45 50 55 60 0 2000 4000 6000 8000 10000 12000 14000 3/14/2009 Composite data from DTC 36

Temperatures in the Well? Circulating or High Rate Injection? 30 40 50 60 70 80 90 100 110 120 130 30 40 50 60 70 80 90 100 110 120 130 0 0 Tubing Undisturbed 2000 Tbg Fluid Casing 1 2000 Tbg Fluid Tubing 4000 Undisturbed 4000 Casing 1 6000 6000 8000 8000 10000 10000 12000 BHST= 122*F 12000 BHST= 125*F 14000 16000 18000 BHCT= 98*F BHTT= 86*F Circulation pump rate = 8-BPM 14000 16000 18000 Frac job pump rate = 35-BPM 3/14/2009 37

Salt-Out or Freezing Temperature of a Brine Crystallization Temp Adding salt lowers freezing point of water until the point at which additional salt precipitates Eutectic Point Salt Content 3/14/2009 38

Composition Determines TCT (true crystallization temperature) Density CaCl 2 CaBr 2 TCT (ppg)* (wt %) (wt %) ( O F / O C) 12.5 34.40 10.80 60/ 15.5 12.5 32.20 13.13 44/ 6.7 12.5 22.84 20.55 15/ - 2.8 12.5 00.00 41.55-33/ - 36 *1.50 SG 3/14/2009 39

Density Change with Temp Change D DH = D S (1 + 0.000252 (T S - T DH )) What is downhole density (D DH ) of a 16.4 lb/gal surface density (D s ) brine (60 o F) when downhole temperature increases to 230 o F? D DH = (16.4) (1 + 0.000252 (60-230) D DH = 15.7 lb/gal 3/14/2009 Formula from OSCA 40

There is a slight increase in density with applied pressure, usually about 0.1 ppg. Brine Density Change with Pressure Brine Density (g/cc) 2.4 2.2 2 1.8 1.6 1.4 1.2 ZnBr2/CaBr2 (19% /wt) ZnBr2/CaBr2/CaCl2 (37% /wt) CaBr2 (45% /wt) NaBr (54% /wt) CaCl2 (65% /wt) 1 0 1000 2000 3000 Pressure, psi NaCl (70% /wt) Typical change was 0.0015 g/cc 3/14/2009 SPE 12490 41

Temperature and Pressure Effects on Completion Fluids Temp Expansion of Fluids Expansion Coef. Pressure Effect on Fluids Compression Coef. Fluid System Density, ppg vol/vol/ o Fx10 4 lb/gal/100 o F vol/vol/ o Fx10 6 lb/gal/1000 psi Diesel 7 3.8 NaCl 9.49 2.54 0.24 1.98 0.019 CaCl2 11.45 2.39 0.27 1.5 0.017 NaBr 12.48 2.67 0.33 1.67 0.021 CaBr2 14.3 2.33 0.33 1.53 0.022 ZnBr2/CaBr2/CaCl2 16.01 2.27 0.36 1.39 0.022 ZnBr2/CaBr2 19.27 2.54 0.48 1.64 0.031 At 12,000 psi from 76F to 345F At 198F from 2,000 to 12,000 psi World Oil, Modern Sand Face Completion, 2003 3/14/2009 42

Brine Selection Circulating Density Match density needs on both static (ESD) needs, and circulating density (ECD) needs. Consider friction effects on BH press while circulating. Remember brine must exert pressures in a window between controlling pore pressure or shale heaving and fracturing the formation. Brine density changes with temperature (can drop by >1 lb/gal) and a small increase with pressure (0.1 lb/gal). Carried solids add density to the brine easily by 0.5 to 2+ lb/gal. 3/14/2009 43

Brines have small density changes due to temperature, pressure, and contamination; and larger density changes due to suspended solids. CaCl 2 Brine in a 14,000 ft Wellbore in 8,000 ft Water Hydrostatic Pressure at TVD Note: Fluid Density is Greater at the Mud line than at the Surface ESD - (lb/gal) 11.35 11.40 11.45 11.50 0 2000 4000 0 2000 4000 BH Pressure - (psi) 0 5000 10000 True Vertical Depth - (ft) 6000 8000 10000 True Vertical Depth - (ft) 6000 8000 10000 12000 12000 14000 14000 Courtesy of MI-LLC 16000 3/14/2009 44 ESD 16000 Pressure

Adding solids to any fluid, either at the surface or downhole increases it density. 0.5 to 2+ lb of solids are common in cleanout with circulated fluids. 3/14/2009 45

Completion Fluid - Checklist Is the formation liquid sensitive to liquid relative permeability effects? Compatibility with formation? (clay and minerals) Compatibility with formation fluid? (emulsion, sludge, foam, froth) Tanks and surface equipment clean?(pumps, lines, hoses, blenders) Are polymers breakable? How is breaker added? Polymers, hydrated, sheared and filtered? Filter level? Beta rating? Minimize the pipe dope? Corrosion reactions understood? Erosion potential understood? 3/14/2009 46

Special Case - Horizontal Wells Hole circulated to a large volume of fluid to stop losses. Minimum amount of solids can be used where internal tool sticking is a possibility Suspension of solids beyond 60 o deviation is difficult. Penetration to furthest reaches of the well is required buckling considerations? Very sensitive to swabbing. 3/14/2009 47

Filtration and Cleaning Brine and? (tanks, lines, pumps, etc.) Pickle the tubulars? NTU or particle count as a measure? How clean is clean? = Avg pore throat x 0.2? Beta rating and micron rating important Tank arrangement when filtering (from dirty tank to clean, not in a loop) Filter type DE or Cartridge (no resin coated cartridges) 3/14/2009 48

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Filtration Ratings NTU - a turbidity indicator - can be mislead by natural color of water. An NTU of 20 to 30 is generally clean. Nominal filter rating - estimate of the size of particle removed - don t trust it. Filtration efficiency improves with bed build-up Absolute filter rating - size of the holes in the filter. Filtration efficiency improves with bed build-up Beta rating - a ratio of particles before filtration to after. A good measure of filter efficiency. Suggestion use a 5 to 10 micron rating with a beta rating of 1000 for most clear brine applications. 3/14/2009 50

Beta Rating Beta = number of filter rating and larger size particles in dirty fluid divided by number of those particles in clean fluid. Beta = 1000/1 = 1000 or 99.99% clean 3/14/2009 51

Filtration Considerations Very clean fluids have high leakoff rates Fluids with properly blended fluid loss control materials added after filtration have a better chance of cleanup than with the initial particles in the fluid. Particles must be sized to stop at the face of the formation. All gelled fluids should be sheared and filtered even the liquid polymer fluids. 3/14/2009 52

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Solid Microgels polymer or fisheyes lumps or Fisheyes after straining and a microgels liquid HEC filtered dispersion from through liquid HEC a 200 polymer. mesh screen in a shear and filter operation for gravel pack fluid preparation. 3/14/2009 54

Scrapers and Brushes Physically Cleaning the Well Available tools Damage potential 3/14/2009 55

One very detrimental action was running a scraper prior to packer setting. The scraping and surging drives debris into unprotected perfs. Effect of Scraping or Milling Adjacent to Open Perforations % Change in PI 20 10 0-10 -20-30 -40-50 -60 Perfs not protected by LCM prior to scraping 1 Perfs protected 2 by LCM Short Term PI Change Long Term PI Change SPE 26042 3/14/2009 56

Casing Scraper Designed to knock off perforation burrs, lips in tubing pins, cement and mud sheaths, scale, etc. It cleans the pipe before setting a packer or plug. The debris it turns loose from the pipe may damage the formation unless the pay is protected by a LCM or plug. 3/14/2009 57

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Placement Methods Circulating preferred watch effective circulation density (friction pressures) Spotting watch density induced drift 0.05 lb/gal difference can start density migration. Bullheading - next to last resort. Lubricating - last resort. Consider coiled tubing for most accurate spotting and ability to circulate fluids into place with minimum contamination. Remember that fluid density differences of even 0.05 lb/gal will start density segregation. 3/14/2009 59

Fluid Loss Control Methods: viscosity, particulates, mechanical Best method? depends on application and options afterward. Viscosity based methods often leave polymer debris Particulates must be sized with small, medium and large particles to build a tight cake at the surface. Don t use them in cased and perforated completions??? Mechanical methods preferred, but not always practical. 3/14/2009 60

Fluid Loss Control Systems fluid (pumped) mechanical gels (linear and x-link) bridging particulates downhole valves plugs micron particles resin particles flappers (watch the throat size) ball checks larger mixed particles Removal methods? Removal methods? 3/14/2009 61

In the Formation / At the Formation Face (Not in Perf) Gels high vis. limits the fluid loss by pressure drop. May not work in high perm (>0.5 darcy). Temperature greatly affects performance. Cleanup is a problem. Particulates bridge at the formation face. Particulates are very effective in controlling fluid loss, but are also very sensitive to swabbing, dissolving in carrier fluids and must be sized for the formation pores and natural 3/14/2009 fractures. 62

Particulate Systems Sized carbonates and salts are most common. Penetration depth = 0.125 (3mm) Do not use in most perforated completions unless the perforations have been packed with gravel. Gravel pack tools and tools with close clearances should not be exposed to particulate laden fluids. Gel carriers for particulates still require breakers. 3/14/2009 63

BHT BHP Considerations for Fluid loss Overbalance or underbalance Vertical and horizontal permeability variations Formation sand size and pore throat size Control Selection Formation sensitivity to treatment fluids Treatment/completion fluid types Frequency and amount of surge/swab loads Formation sand strength Sand production and presence of cavity Onshore / Offshore / Deepwater Rig cost per day Rig equip available - pumps, tanks, lines, All tubular sizes in the flow path Mobilization time available Production rate Producer or injector Regulations on use and disposal Produced fluid types Wellbore deviation through the pay Natural or hydraulic fractures present 3/14/2009 64 SPE 54323

Areas for Fluid Loss Control In formation matrix At the formation face Inside the perf tunnel On the fracture pack Inside the casing (on the perforation) On a sand-back plug In the gravel Inside the screen Above the screen or in the BHA Inside the tubing At the surface Each location requires different plug construction methods and removal considerations. 3/14/2009 65

Cleanup Gel break and damage issues Fluid imbibition effects Other fluid unloading issues 3/14/2009 66

Cleanup How to remove from the reservoir (through the fractures or the matrix). Is a surface/interfacial reduction surfactant needed? Is gas needed? Is the formation initially undersaturated to water (yes, it can and does happen). From the wellbore effective unloading is plagued by well deviation and low flow rates from small coiled tubing and other non rotating strings. 3/14/2009 67

Problems - unwanted foams during backflow Foam is an emulsion where gas is the internal phase (mist is an emulsion with gas as external phase). Foams are used to unload brines BUT the forms may cause a problem at the surface. Foaming conditions some oils (ppm conc. of C6-C9organic acids and alcohols) diesel - (particularly bad and varies from lot to lot) some acid additives (emulsifiers, salts, inhibitors) XCD polymers (and others) Look for and destroy the stabilizer to break the foam. 3/14/2009 68

Brine Tankage Required 1. Volume of prod. Casing annulus & below packer? 2. Displacement volume of work string 3. Displacement volume of producing string including packers 4. Volume of manifolds, lines, hoses and pumps 5. Volume of transport tankage (usable) 6. Volume of filtering system (all tanks, lines and pods) 7. Volume of pill tank 8. Pickle flush volume 9. Spare volume for safe operation 3/14/2009 69

Special Topics Alternatives to a clear brine Gravel pack brines Brine handling and preparation Solids free gels Corrosion Hydrates Best Practice Learnings Toxicity 3/14/2009 70

Alternatives to a Clear Brine Emulsions, Foams, Muds Will it be stable? What will stop fluid loss? What will clean up or degrade? What will damage least? Can an oil be ever be used in a gas zone?? 3/14/2009 71

Is mud a viable kill fluid for high temp and high pressure wells? How much perm damage does it cause? Against the formation? In the perforations? In a naturally fractured formation? Against a gravel pack or screen? Is the damage reversible? If you have high wellbore pressures, some of the mud damage is reversible - SOME! 3/14/2009 72

Fluids for Gravel/Frac Pack Water - low viscosity brines, low molecular weight salts HEC - high molecular weight, water soluble polymer, straight chain Xanvis - high molecular wt bio polymer, water soluble. Branched chain, lower damage than HEC? 3/14/2009 73

Water Advantages - no mixing, no breakers, high leakoff, easier to get turbulence Disadvantages - low gravel carrying capacity (+/- 2 ppg), more fluid lost, compatibility problems? 3/14/2009 74

HEC Advantages: mixes easily??? (still must shear and filter), easy to break??? (we ve had problems here), commonly available Disadvantages: lower leakoff rates, lower sand carrying capacity than bio-polymers 3/14/2009 75

XC Advantages: shear thinning, higher leakoff, good carrying capacity Disadvantages: said to wet some formations (anionic), x-links with calcium and iron (water composition more critical), harder to mix, breaks rapidly above 125 o F? 3/14/2009 76

Brine Handling and Preparation Brines HEC XC Min Filter Req 5 to 10 mu 10 mu 10mu Beta rating B=1000 B=10-100 B=10-100 Shear Req? N/A 2 bpm/1200 psi 2 bpm/600 Gravel Conc. 1-5 ppg 1-15 ppg 1-15 ppg Breaker N/A acid, enz, ox oxidizers Brine Compat? N/A <15.5 ppg KCl & NH4Cl Leakoff excellent fair good 3/14/2009 77

Solids Free Gels Surfactant gel Requires clay control (early problems) Breaks with oil Not perfect, but generally better than gels. 3/14/2009 78

Breakers for HEC-Gelled Brines Breaker BHT HCl 130 to 200F Ammonium hypochlorite 130 to 200F Enzymes below 130 F No Breaker Required? Above 200 F? 3/14/2009 79

Corrosivity In oxygen free environment, CaCl 2 /CaBr brines exhibit very low corrosion rates if the ph is kept between 7 and 10. Lime and magnesium oxide are used to increase the ph of the brines. Use of sulfite oxygen scavengers in large concentrations can potentially cause CaSO 4 precip. Use other methods. Biocide may not be needed in more concentrated brines. 3/14/2009 80

Corrosion From Brines example from Materials, Corrosion and Inspection: http://upstream.bpweb.bp.com/mci/default.asp Material General Corrosion Pitting/Crevice Corrosion SSC CL SCC Relative Failure Risk Low Alloy Steel Y Y Low 13 Chrome Y Y Y Low/Med Super Cr 13, etc. Y Y Y Y High Alloy 450 Y Y Y Med 17-4PH Y Y Y High Duplex Stainless Y Y Y High Austenitic Y Y High Super Austenitic Y Y Low Ni Alloys Y Y Low 3/14/2009 HPHT Production Operations, March 16, 2005, EPTG, BP 81 11

Hydrates and Freezing Sea floor temperatures Gas expansion cooling Is the brine naturally hydrate formation resistant? Is it tolerant of antifreeze? 3/14/2009 82

Dense Brines Inhibit Hydrates Hydrate inhibition by CaCl2 Brine 120.0 Hydrate Formation Temp F 100.0 80.0 60.0 40.0 20.0 0.0 Solvent Needed Maybe Hydrate equilibrium pressure for pure water calculated using CSMHYD, VK 917 gas Safe 8.3 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 10.7 10.9 11.1 11.3 11.5 11.7 15 kpsi 10 kpsi 5 kpsi 2.5 kpsi -20.0-40.0 George Brine Density E. King Engineering lb/gal 3/14/2009 83

LEARNINGS Proper disposal required for all chemicals. Mixed displacement pills and mud have to be separated from the mud and packer fluid for disposal (zero discharge issues) Brine/Water/Acid pumped without surfactants/solvents to displace oil muds (e.g. for an inflow test) prior to clean up can form sludges, these will not be broken down by subsequent clean up pills Clean up pills containing surfactants can foam during mixing (particularly when put through a hopper) and during flowback. 3/14/2009 84

Viscosifier Learnings XCD/ biozan are preferred for mixing viscous pills but do not work in calcium brines, HEC will not support solids. Polymers should be checked for suitability at the anticipated temperature (thermal thinning an issue particularly >135 o C/275 o F). 3/14/2009 85

LEARNING The use of a circulating sub to allow high flow rates is recommended. As steel surfaces water wet, pipe rotation may not be possible due to friction and displacement of solids becomes much more difficult. Displacement must exceed solids settling rate and (e.g. 0.18 ft/sec for 40/60 mesh sand in water) not stop once pills are in the annulus. Displacement optimized for smallest production casing ID can leave bypassed mud in larger OD s for tapered casing strings. Reverse circulation is most effective if packer fluid is lighter than mud (watch bridging potential) 3/14/2009 86

Many Brines are Sensitive to Temperature When Viscosified Brine type sensitive NaCl to ZnCl Temperature sensitivity is also affected by concentration Liquid vs. dry polymer makes a difference. 3/14/2009 87

Stability of Dry HEC in Socium Chloride 260 Precipitation, Separation or Lost Viscosity Temperature, F 240 220 200 180 Transition Zone HEC Active and Soluble 160 140 8.6 8.8 9 9.2 9.4 9.6 9.8 10 10.2 Sodium Chloride Density, ppg SPE 58728 3/14/2009 88

Liquid HEC in Zinc Based Brines Temperature, F 260 240 220 200 180 160 140 120 Transition Zone HEC Active and Soluble 100 15 16 17 18 19 20 Zinc George Brine E. King Engineering Density, ppg 3/14/2009 SPE 58728 89

Brief toxicity data for standard test organisms. SPE 27143 Species Acute Toxic Threshold Concentration (mg/l) Zinc bromide Cesium formate Potassium formate Sodium formate Algae 0.32 1600 3700 2000 Invertibrates 1.6 340 300 3900 Fish? 260 1700 6100 3/14/2009 90