TubeCLEAN fluidsThe TubeCLEAN* completion preflush treatment fluid is designed to clean tubulars, limiting theamount of dissolved iron, rust, mill scale and silt transported into the formation. The recom-mended treatment volume should be calculated based on 100 gal/1000 ft [378 L/305 m] of tubing.If small-diameter tubing or coiled tubing is used, the treatment should be based on a volume of50 gal/1000 ft [189 L/305 m].

Applications■ Cleaning tubulars■ Temperatures to 300°F [149°C]

Benefits and features ■ Water-wet the tubulars so that dissolution of iron scale or rust can easily take place■ Suspend silt or other particulates■ Limit metal corrosion

CLEAN SWEEP fluidsThe CLEAN SWEEP* solvent systems are designed to remove damage common to oil and gas wells.Such damage includes

■ emulsions,■ mixed deposits,■ paraffin and asphaltene deposits,■ saturation changes,■ scale,■ water blocks and■ wettability changes

The minimum treatment fluid volume is 150 gal [568 L]/perforated ft.

Applications■ Remove common oil and gas well damage■ Temperatures to more than 400°F [204°C]

Benefits and features■ Xylene-, toluene-, alcohol- or alkene-based■ Can be formulated for summer or winter use■ Decreases viscosity of in-place oil and enhances cleanup

Sand Control Pumping ■ Systems 37

Systems

38 Sand Control Pumping

CleanFLOW systemsThe CleanFLOW* fracture conductivity enhancement systems are fluids based on the EB-Clean*encapsulated breaker family and are designed to function at the desired temperature range longenough to facilitate adequate polymer degradation. XEB-Clean breaker can be used in most fluids,with the exception of borate-crosslinked fluid, YF* 100.1HTD.

In temperatures ranging from 180 to 235°F [82 to 113°C], CleanFLOW additive can be usedwith J218 or J475 breakers, or both. CleanFLOW additive can be used with J496 breaker in all flu-ids except YF 100.1HTD, with J218 and J475 breakers (lower end of the temperature range) orwith J481 and/or EB-Clean J490 HT (high temperature) encapsulated breaker (high end of thetemperature range).

In temperatures ranging from 235 to 350°F [113 to 177°C], the CleanFLOW additive can be usedwith J481 and/or J490 breaker. The damage difference classically seen between zirconium andborate crosslinkers is eliminated when the CleanFLOW additive is applied in this temperature range.

Applications■ Enhance fracture conductivity■ Temperatures from 180 to 350°F [82 to 177°C]

Benefits and features■ As much as 50% more conductivity compared with use of breaker-only systems ■ Minimum damage from zirconium crosslinkers in high-temperature operations

Alcoholic acid formulationsAlcoholic acid formulations are a mixture of acid and alcohol. The acids are usually eitherhydrochloric acid (HCl) or mud acid (HCl + hydrofluoric acid (HF)), but can be organic, such asformic or acetic acids. The alcohol is either methyl or isopropyl. Alcohol is not intended to replacemutual solvents in most applications.

Suggested concentrations are 20% by volume of isopropyl alcohol and 30% by volume of methylalcohol. The ratio terminology for alcoholic acid always lists the percent by volume of acid first.For example, a 70:30 mixture of acid and methanol contains 70% acid and 30% methanol by volume.

Applications■ Enhances treatments in low-permeability oil and dry gas zones by lowering interfacial

surface tension■ Water-block removal

Benefits and features■ Reduced surface tension

● allows deeper penetration of acid into the rock matrix ● improves gas permeability by reducing water saturation● aids in removal of water blocks● reduces tendency for spent acid to form sludge and emulsions with formation fluids.

■ Lower acid-mineral reaction rate creates a retarding effect. In the presence of water, alcohollowers the ionization rate of acids.

Systems 39

ClayAcid fines-control acidClayAcid* fines-control retarded acid is designed specifically for acidizing sensitive sandstoneformations. It not only provides good stimulation but also provides permanent stabilization of claysand other fines, eliminating water sensitivity and preventing the mobilization of migratory fines.ClayAcid treatments slowly release hydrofluoric acid from the hydrolysis of fluoboric acid (HBF4)and can penetrate to a much greater distance from the wellbore before spending than can mudacid.

ClayAcid service may be inhibited at temperatures to 400°F [204°C] using the appropriatecorrosion inhibitors and corrosion inhibitor aids.

ClayAcid formulationsThere are four formulations of clay acid:

■ Full strength ClayAcid (regular formulation): recommended for a treating temperature rangeof 130 to 300°F [54 to 149°C]

■ Half-strength ClayAcid: recommended for sands with high-quartz (>80%), low-clay (<10%)content.

■ Full strength ClayAcid LT (low-temperature formulation) contains more HCl than full strengthClayAcid, which aids in the hydrolysis of HBF4, releasing HF at a faster rate. This formulationallows much shorter shut-in times and is recommended in the treating temperature range of100 to 130°F [38 to 54°C].

■ Half-strength ClayAcid LT (low-temperature formulation) contains more HCl than half strengthClayAcid and half the concentration of HBF4 that is used in half strength ClayAcid. It is recom-mended for treatments in formations with low clay content (< 10%) and high quartz (>80%).

Applications■ Overflush fluid behind a conventional matrix acidizing treatment■ Preflush fluid ahead of a matrix acid treatment■ As the sole stimulation fluid

Benefits and features■ Permanent stabilization of clays and other fines■ Elimination of water sensitivity■ Elimination of migratory fines mobility■ Increased penetration distance when compared with mud acid

Figure 3-1. Production vs time for two wells located in the Gulf of Mexico. Note the positive response to the HF acid treatment and thesubsequent rapid production decline. This is characteristic of a large number of wells producing from formations with 20 to 50% silt and clay.Following ClayACID treatments, excellent production is obtained and the rapid production decline is completely eliminated.

12

10

8

6

4

2

0

Production(MMCFPD)

-6 0 10 20 30 40 50

Time (months)

Well B

Well A

AfterHF acidtreatment

After ClayAcid treatment

Gas well acidGas well acid is 15% HCl prepared by diluting concentrated HCl with methanol K46. It containsapproximately 67% by volume of methanol, and its principal advantages are its slow reaction rateand improved cleanup properties. The low surface and interfacial tensions of spent acid and itsincreased volatility ensure rapid cleanup.

The high alcohol content gives the spent acid a lower boiling point and causes it to readilyvaporize. This reduces water saturation, resulting in higher relative permeability to gas. When alco-hol replaces part of the water in an acid solution, the degree to which HCl can effectively ionize isreduced. The rate of reaction of gas well acid is approximately one-half that of regular 15% HCl.

Corrosion Inhibitor A260 is the inhibitor of choice with gas well acid.

Applications■ Matrix acidizing of dry gas and gas storage wells■ Temperatures to 225°F [107°C]

Benefits and features■ Improved cleanup■ Improved flow of spent acid as a result of lower surface tension from reduction in capillary forces ■ Higher relative permeability to gas resulting from reduced water saturation due to increased

volatility of spent acid■ Deeper penetration as a result of lower rate of reaction when compared to regular 15% HCl

Gas well mud acidGas well mud acid contains 8% HCl and 3% HF by weight plus methanol K46. Its principal advantagesare its slow reaction rate and improved cleanup properties. The surface and interfacial tensionsof spent acid in addition to high volatility ensure rapid cleanup. The presence of alcohol slowsthe ionization rate of the acid, reducing the reaction rate and enabling deeper penetration of liveacid into the formation. Lower interfacial tension, which reduces the capillary forces restrainingfluid movement, results in improved cleanup of the spent acid.

The high methanol content gives the spent acid a lower boiling point and causes it to evaporatemore readily than conventional acid systems. This reduces water saturation, resulting in a higherrelative permeability to gas.

The concentration of K46 can vary from 53 to 80% by volume depending on the compositionof bulk acids used in the preparation of this solvent. Gas well super mud acid, a mixture of 8% HCl,6% HF and K46 methyl alcohol, can be used in formations where clay content is very high (>20%).Gas well acid must be used as a preflush ahead of gas well super mud acid.

Corrosion Inhibitor A260 is the inhibitor of choice with gas well mud acid.

Applications■ Treatment in gas wells■ Temperatures to 225°F [107°C]

40 Sand Control Pumping

Benefits and features■ Improved cleanup■ Improved flow of spent acid as a result of lower surface tension from reduction in capillary forces ■ Higher relative permeability to gas as a result of lower reduced water saturation from increased

volatility of spent acid■ Deeper penetration as a result of lower rate of reaction when compared with regular mud acid

BDA breakdown acid service MSR mud and silt remover service The BDA breakdown acid* service is designed primarily to open or "break down" the target intervalprior to a fracturing treatment. The most commonly used breakdown acid formulations incorporatea combination of F78 surfactant and U42 chelant, which enhance the suspension of fines in thespend acid:

■ The MSR* mud silt remover service is an acid solution containing a clay dispersant-suspendingagent and an iron chelating agent. This combination of additives provides good dispersion ofdrilling muds and formation silt, and unusually effective suspension properties. There are threedistinct formulations of MSR fluids.

■ MSR100 fluid is the most commonly used formulation in which 100 refers to the amount of ironchelating agent. The carrier fluid is commonly 7.5 to 15% HCl, but it can be ammonium orpotassium chloride brine.

■ MSR150 fluid was developed specifically for formations containing relatively large amounts ofiron-bearing minerals where chelants are required to prevent reprecipitation of iron fromspent acid.

■ MSR123 fluid is a special mud acid version. It contains a mutual solvent and the carrier fluidis a regular mud acid. A preflush is used ahead of MSR123 (as in most mud acid treatments)to minimize formation damage caused by fluorosilicates.

Applications■ Removal of drilling mud damage in carbonate and sandstone formations■ Restoring fracture conductivity in workover operations■ Opening clogged perforations and restoring permeability■ Removing damage from the critical matrix in matrix acidizing■ Restoring natural permeability in fissured or fractured reservoirs following mud losses■ Temperatures to 350°F [177°C]

Benefits and features■ Excellent dispersion properties■ Effective suspension properties■ Prevents reprecipitation of iron from spent acid

Systems 41

DAD Dynamic Acid Dispersion service The primary use of the DAD* dynamic acid dispersion service is removal of commingled hydro-carbon and scale deposits. It is an acid outside phase emulsion including a dispersing-stabilizingagent often used as a preflush ahead of matrix acidizing treatments.

The dynamic acid dispersion service is applicable to 300°F [149°C] dependent on solvent toacid ratio.

Applications■ Removal of common oil and gas well damage (mixed deposits, paraffin and calcite scale)■ Tubulars■ Perforations or critical matrix■ Ahead of mud or clay acid treatments

Benefits and features■ Low-viscosity dispersion for one-stage cleanup and acidizing of hydrocarbon-coated formations,

gravel packs, wellbores and tubulars■ Hydrocarbon solvents such as A121 and A26 for removal of oil, asphaltenes and paraffin from

scale or formation

42 Sand Control Pumping

Table 3-1. Recommendations for Nonacid Fluids

Damage Mechanism Recommendation

Asphaltenes or paraffin Xylene

Bacteria Formation Cleaning Solution (M91) followed by acid treatment

Emulsion block or injection carryover of emulsion CLEAN SWEEP*†

Injection carryover of oil CLEAN SWEEP†

Mixed organic and inorganic scale deposits DAD†

Water block CLEAN SWEEP†

Wettability alteration CLEAN SWEEP†

† Consult Matrix Materials Manual for CLEAN SWEEP or DAD recommendation for specific well conditions.

Mud acid formulationsMud acid is a mixture of inhibited HCl and HF. Mud acid will dissolve all minerals that are solu-ble in 15% HCl. In addition, it will dissolve siliceous minerals such as bentonite, naturally occur-ring formation clays and other siliceous minerals (all of which are only partially soluble in HCl).Calcium and magnesium chlorides plus sodium and potassium brines will react with HF to forminsoluble precipitates. Thus, pretreatment with HCl ahead of mud acid and as an overflushbehind is a technically sound and common practice.

Mud acid and super mud acid may be inhibited at temperatures to 400oF [204oC] using appro-priate corrosion inhibitors and corrosion inhibitor aids.

Main mud acid formulationsFollowing are common mud acid formulations.

■ MSR123 Acid (12-3): This acid with a mutual solvent to enhance its reactivity is used to restorepermeability in oily, dirty, carbonate-cemented sandstones.]

■ Dilute mud acid: Any solution containing up to and including 7.5% HCl and 1.5% HF. Dilutemud acid is used to restore permeability to sandstone formations.

■ Regular mud acid: Any solution containing 7.6 to 12.0% HCl and 1.6 to 3.0% HF. Regular mudacid is used to restore permeability to carbonate- cemented sandstone formations.

■ Super mud acid: Any solution containing 12.1 to 16% HCl and 3.1 to 6.0% HF. Super mud acidis used to restore permeability to carbonate-cemented sandstone formations that are exten-sively damaged or have high clay content. Special care must be taken to assure the separationof fluoride ions and ions of sodium, potassium, calcium and magnesium

■ Gas well ud acid: Solution of mud acid prepared by diluting concentrated HCl with methanolK46. It contains approximately 67% by volume of methanol and is used to restore permeabilityto dry gas sandstone formations.

■ Super gas well mud acid: Solution of super mud acid prepared by diluting concentrated HClwith methanol K46. It contains approximately 67% by volume of methanol and is used torestore permeability to dry gas sandstone formations that are extensively damaged or havehigh clay content.

Mud acid selectionThe criteria for selecting the mud acid formulation (basically the HCl:HF ratio) to use are

■ rock mineralogy: chemical composition and surface area■ mechanisms for formation damage and its removal■ petrophysics and well conditions.

Treating fluid compatibility with the rock is a key factor. This concept of compatibility appliesespecially to sandstones, where many damaging reactions may occur. Using available data oninteractions of HF-HCl acids and sandstones and field experience, guidelines have been estab-lished for using mud acids in sandstone matrix treatments. These guidelines, designed to avoidor retard by-products precipitation, include a wide range of permeability, formation mineralogyand temperature.

X-ray diffraction (XRD)analysis is the most common test used to determine formation mineralogy.However, this data is not always available. Formation solubility in both HCl and HCl:HF can be usedto approximate the total silt and clay content. The difference in these solubilities correlates well tosilt and clay content by XRD analysis as seen in Table 3-2. Solubility information, however, does notindicate the type of clay present.

Systems 43

Applications■ Operations in which average formation solubility in HCl acid is less than 20%■ Operations in which formation solubility in mud acid is at least 15% and is preferred at least 10%

greater than solubility in HCl■ Wellbore cleanup when clays or other siliceous materials have damaged the formation

Benefits and features■ MSR123 (12:3 mud acid) incorporates silt suspending surfactants and restores permeability in

oily, dirty, carbonate, cemented sandstones.■ Dilute mud acid restores permeability to sandstone formations.■ Regular mud acid restores permeability to carbonate-cemented sandstone formations.■ Super mud acid restores permeability to extensively damaged carbonate-cemented sandstone

formations or formations with high clay content.■ Gas well mud acid restores permeability to dry gas sandstone formations.■ Super gas well mud acid restores permeability to extensively damaged dry gas sandstone forma-

tions or formations with high clay content.

NARS 200, 201 Nonacid Reactive Solutions NARS* 200 and NARS* 201 Nonacid Reactive Solutions are used as formation cleanup and break-down fluids in formations that may be damaged by acid. These solutions do not contain low pHacids, but instead are alkaline in nature and contain strong chelating and clay-control additives.Additionally, they contain mutual solvents that enhance water-wetting operations. The chelantbehaves as a solvent, dissolving or partially dissolving some of the minerals in sandstones. Affectedminerals include those that contain iron, calcium, magnesium and aluminum. Containing noacid in the conventional sense, NARS fluids are slightly alkaline, having a pH between 10 and 11.Corrosion inhibitors are not required.

44 Sand Control Pumping

Table 3-2. XRD Versus Solubility Analysis

Formation Silt and Clay from XRD (%) Difference in Solubility between HCl and HCl:HF (%)

Muddy sand 7.0 5.2

Brazos sand 13.6 13.0

Miocene A 25.0 20.7

Miocene B 26.0 22.1

Miocene C 34.0 33.6

Systems 45

NARS 200 formation solventNARS 200 formation solvent is a clay-dispersing and suspending fluid that contains F100 surfactant.When a strong clay dispersing agent is needed as a perforating or cleanup fluid, NARS 200 fluidis preferred.

NARS 201 formation solventNARS 201 clay flocculating and stabilizing fluid containing F103 surfactant and L55 clay stabi-lizer is used to stabilize clay particles in place. Because of its clay-flocculating and permanentstabilizing properties, NARS 201 may be preferred when a breakdown or spearhead fluid is used ina zone where produced fines may later become a problem. For example, NARS 201 fluid is advan-tageous in treating injection wells where the formation may later be exposed to fresh water.

Applications■ Formation cleanup and breakdown in acid-sensitive formations■ High-temperature, harsh-environment wells where corrosion inhibition might be a problem■ In formations with bottomhole static temperatures between 150 and 300°F [65 to 149°C]

Benefits and features■ Mutual solvents enhance water-wettability.■ Dual functionality additive acts as a chelant as well as a solvent■ No corrosion inhibitors are required because of the fluid’s acid-free, alkaline composition.

OB mud removal systemThe OB mud removal system is a water-based system designed to remove oil-based drilling muddamage from a producing formation. It can be used as a separate treatment or as a pretreatmentprior to a matrix acidizing or an acid breakdown operation. This system removes the oil-basedmud by reducing viscosity, dispersing fines and returning the formation to a water-wet state.Recommended volumes are 100 to 300 gal [378 to 1136 L] of total treating fluid per foot of per-forated interval. In remedial treatments where damage extends farther into the formation, thevolumes should be at least 150 to 600 gal/ft [568 to 10,004 L/m] of perforated interval.

Applications■ Oil-based mud removal■ Breakdown fluid■ Pretreatment for stimulation operations■ Perforation cleanup treatment■ Temperature to more than 400°F [204°C]

OilSEEKER acid diverterThe OilSEEKER* acid diverter is a VES-based agent that forms a temporary gel plug that isdestroyed by oil production. It is used as a diverting agent during acid treatments of sandstoneand carbonate formations.

Applications■ Matrix stimulation of high-water-cut carbonate or sandstone formations■ Internal chemical diverter where large permeability contrasts exist in producing zones■ Temperatures ranging from 80 to 220°F [27 to 104°C]

Benefits and features■ Reduces water cut and increases hydrocarbon production■ Provides good zonal coverage in vertical and horizontal wells■ Extremely easy to mix and apply in the field

46 Sand Control Pumping

Figure 3-2. OilSEEKER fluid diverts acid from water-bearing zones to oil-bearing formations.

Figure 3-3. Core tests demonstrate OilSEEKER fluid diverts the acid treatment from the water zone to the oil zone.

0 20 40 60 80 100

Time (min)

120 140 160 180 200

Fractionalflow (%)

100

90

80

70

60

50

40

30

20

10

0

390 mD, 77% oil saturation (oil zone)410 mD, 20% oil saturation (water zone)

Oil zone

DiverterBrineBrine Mutualsolvent

HCl

Water zone

Organic acidsOrganic acid L36 (formic acid) can be used at concentrations as high as 9% to stimulate oil andgas wells. It reacts slowly with carbonate formations and with many minerals common to sand-stone formations. The reaction rate and dissolving power of L36 fluid are between 15% HCl and 10%aqueous acetic acid.

Applications■ Matrix stimulation of oil and gas wells■ Cleanup of water-based RDF filter cakes■ Minimum temperature of 400°F [204°C]

Benefits and features■ More uniform filter-cake cleanup as a result of lower reaction rate when compared to HCl■ Lower corrosion to tubulars and sand control screens as compared to HCl■ Reduced tendency to form asphaltic sludge when in contact with crude oils

OCA organic clay acid systemThe OCA* organic clay acid matrix stimulation system is designed for acidizing sandstone for-mations with high silt and clay content and HCl-sensitive minerals, such as zeolite and chlorite.All clays undergo degradation in the presence of HCl. Zeolites and chlorites are the most sus-ceptible, but even commonly occurring clays such as illite, kaolinite and smectite will undergosignificant degradation if exposed to acid at temperatures from 190 to 250°F [88 to 121°C]. Use ofthe OCA service can mitigate the risk of damaging precipitates being formed when HCl degradesthese clays.

Applications■ Matrix stimulation in high-temperature sandstone formations with high silt and clay content

and HCl-sensitive minerals■ Temperatures from 80 to 350°F [27 to 177°C]

Benefits and features■ Removes formation damage caused by clay and other aluminosilicate minerals■ Minimizes hydrated silica precipitation (known as the secondary reaction)■ Prevents migration of undissolved fines after acidizing treatments

Systems 47

48 Sand Control Pumping

Figure 3-5. OCA fluid cleans up the formation, resulting in reduced injection pressure.

Job time (min)

Pressure(psi)

Injectionrate

(bbl/min)

5000

4000

3000

2000

1000

0

10

8

6

4

2

0220 245 270 295 320 345 370

Treating pressure (psi)Injection rate (bbl/min)

Primepumps End of

treatment

Start postflush

Startdisplacement

PumpOCAfluid

Acid atperforations

Increaserate

Figure 3-4. The plot shows sequential acid spending test results for various acids reacting with minerals containing 10%zeolite and 90% silica at 200°F [93°C].

9876543210

1 2 3 4

Silicon toaluminum

ratio

Acid 3

OCA

Acid 2

Acid 1

Sequential action

Organic mud acidsOrganic mud acid is a mixture containing 9% organic acid L36 (formic acid) and 1 to 3% HF. It isless corrosive than comparable HCl + HF mixtures and is easily inhibited to protect tubulars fromacid corrosion. As a result, low corrosion rates can be maintained at high treating temperatures.In addition, it provides a reduced relative reaction and has a reduced tendency to form asphalticsludge when in contact with crude oils. L400 (acetic acid) can also be used as an alternativeorganic acid.

Applications■ High-temperature matrix acid treatment and wellbore damage removal in sandstone

or limestone reservoirs where extended pipe-contact time is anticipated■ Reservoirs where asphaltic sludges form when contacted by HCl■ High-temperature acid breakdown■ Minimum temperature of 300°F [149°C] with 6-hr tubular protection time

Benefits and features■ Less corrosive compared with HCl + HF systems■ Lower tendency to form asphaltic sludges■ Easily inhibited to protect tubulars from corrosion

SuperX acidsSolutions of HCl which have a concentration of 20% or more, by weight, are called SuperX* acids.The normal concentration is 28%, although other concentrations are used. Use of SuperX acid hasresulted in successful treatments in carbonate reservoirs where other formulations have failed.Because of its high initial acid strength, it will not only dissolve more rock than less concentratedsystems but it will also penetrate a greater distance into the reservoir before it becomes spent.These properties provide deeper etch patterns in carbonate reservoirs, providing better conduc-tivity for producing well fluids.

SuperX acid can be inhibited to 300°F [149°C] using appropriate corrosion inhibitors andcorrosion inhibitor aids.

Applications■ Fracturing and matrix treatments in HT limestone formations

Benefits and features■ Deep penetration of more concentrated acids as a result of longer spending time (not to be

confused with reaction rate) ■ Better conductivity of etched patterns■ Improved well cleanup resulting from greater conductivity created by SuperX acid in addition

to the large amount of carbon dioxide that is produced■ More efficient transport of insoluble fines and reduced leakoff as a result of higher viscosity

Systems 49

XE acid systemXE acid is a matrix stimulation system designed for acidizing sandstone formations with high siltand clay content and HCl-sensitive minerals, such as zeolite and chlorite.

Applications■ Matrix stimulation in HT sandstone formations with high silt and clay content and HCl-

sensitive minerals ■ Temperatures from 80 to 350°F [27 to 177°C]

Benefits and features■ Removes formation damage caused by clay and other aluminosilicate minerals■ Minimizes hydrated silica precipitation (known as the secondary reaction)■ Prevents migration of undissolved fines after acidizing treatments

50 Sand Control Pumping

Figure 3-6. StimCADE* acid placement simulations incorporating 15% HCl and SuperX emulsion at 250°F show that when SuperX fluid is usedthe wormhole length is approximately five times longer. The SuperX treatment results in a negative skin; the 15% HCl treatment does not.

1.2

1.0

0.8

0.6

0.4

0.2

0

Wormholelength (ft)

Pump time

SuperX treatment result15% HCI treatment result

Figure 3-7. These wormholes were created in the laboratory on limestone cores and filled with Woods metal to retain their shape.

Chelating agent solutions (CAS)Chelants are organic acids or salt derivatives that dissolve calcium carbonate and complex withCa++ ions to form soluble byproducts. They can provide a dissolution capacity similar to 7.5% HClor 9% formic acid, without the high corrosiveness. As such, they are ideal for removal of thecalcium carbonate from filter cakes of water-based RDF in sand control (stand-alone screenor gravel-pack) environments. Use of CAS fluids allows placement of CAS in long open holeswithout inducing thief zones and provides for uniform cake cleanup. Although the reaction ofCAS with calcium carbonate alone is very fast, its reaction with the calcium carbonate in the filtercake (coated with starch and other polymers) is much slower when compared with conventionalacids such as HCl or formic acid.

Efficiency of water-based RDF cake removal can further be enhanced through combinationof J503 enzyme with CAS for single-step removal of starch and calcium carbonate from the fil-ter cake. Rate of cake removal can be controlled through adjustments of pH as well as the chelantand/or enzyme concentration. CAS formulations compatible with various VES fluids are availablefor simultaneous gravel-packing and cake cleanup.

The formulations are stable and can be inhibited to further minimize corrosion of sand controlscreens to 400°F [204°C]. They must not be mixed with divalent brines for removal of calciumcarbonate from RDF filter cakes, because the chelant will be consumed on the divalent (e.g., Ca++)ions in the brine.

While laboratory test results indicate that CAS formulations do not have an adverse effect onscreen openings, HCl increased the openings from 150 to 250 µm. This is enough to adversely affectsand control and completion integrity when soaking for extended time periods at high temperaturesafter gravel-packing.

U105 formulation U105 formulation is an optimized CAS based on EDTA chelating agent with a pH of 4.7. Neat U105has a dissolving capacity approximately equivalent to 6% HCl or 9% formic acid. Primary reactionof U105 fluid with calcium carbonate yields water, carbon dioxide gas and a soluble salt of calciumEDTA. Once solubilized, there is no reprecipitation of dissolved products or secondary reactions,making the use of U105 fluid a nondamaging treatment option. The low corrosion and low toxicityof U105 formulation allows it to be handled with standard pumps and equipment and standardnonacid personal protective equipment, in addition to eliminating concerns for loss of sand controlcaused by screen corrosion. U105 formulation is nonfuming and has a clay stabilizing effect asa result of its high potassium content. U105 formulation is compatible with enzyme J503 andClearFRAC fluid; but incompatible with ClearPAC systems.

Systems 51

Table 3-3. Corrosion Rates of Sand Control Screens

Screen Material Corrosion Rate, lbm/ft2

7.5% HCl with 1% Inhibitor CAS with 0.2% Inhibitor

J-55 carbon steel 0.0110 0.0037

13-Chrome steel 0.0130 0.0001

316-L steel 0.0580 0.0007

Screen openings, µm

Before exposure 150 150

After exposure 250 150

U106 formulationU106 formulation is an optimized chelating agent solution based on an EDTA analog, with a pHbetween 11 and 12. Dissolution capacity of neat U106 formulation at a pH of 11 is approximatelythe same as that of neat U105 fluid. Because it is highly soluble in acids, U106 can be combinedwith acids to yield any pH value between 2.5 and 11, allowing a large degree of flexibility forpH-sensitive formations. This flexibility in pH allows more controllable filter-cake removal, partic-ularly when enzyme-CAS combinations are utilized for simultaneous removal of starch and calciumcarbonate from the filter cake.

U820 formulationU820 formulation is a field mix of U106 formulation with HCl, with a pH of 4.0. Dissolution capacityof U820 formulation with 50% by weight U106 fluid is approximately the same as that of neat U105formulation. U820 fluid has the same low-corrosion characteristics as U105 formulation. U820 fluidis compatible with enzyme J503 and ClearPAC systems, but incompatible with ClearFRAC fluids.

U821 formulationU821 formulation is a field mix of U106 formulation with HCl, with a pH of 2.5. Dissolution capacityof U821 formulation with 50% by weight U106 fluid is slightly higher than that of neat U105 fluid.U821 formulation has the same low-corrosion characteristics as U105 fluid.U821 formulation iscompatible with ClearPAC systems, but incompatible with ClearFRAC fluids.

Applications ■ Slow, uniform and complete removal of calcium carbonate from the filter cakes of

● water-based drilling fluids such as biopolymer, starch or calcium carbonate systems● reversible synthetic or oil-based RDF, such as FAZEPRO systems● conventional synthetic or oil-based RDF (including esters) following a high-rate viscous

displacement stage with a CAS-surfactant-monovalent brine mixture

Benefits and features■ Lower corrosion system for calcium carbonate removal from drilling fluid filter cakes compared

with common inorganic and organic acids■ Uniform filter-cake cleanup as a result of lower reaction rates■ Compatible with enzymes, allowing single-step carbonate and starch removal■ Compatible with VES fluids, allowing simultaneous gravel-packing and cake cleanup

52 Sand Control Pumping

Enzyme breaker J503 Breaker J503 is a water-based dispersion of enzyme that catalyzes the breakdown of starch andstarch-based derivatives that are commonly used in water-based RDF, either as a fluid-loss con-trol additive and a secondary viscosifier or as a primary viscosifier. The starch-to-biopolymer(scleroglucan or xanthan) mass ratio in most widely used water-based RDFs is from 4 to 6, makingstarch, if not removed, the most dominant source of potential completion damage from polymericcomponents.

In fact, such high concentrations of starch with respect to other polymeric components isdesirable from a well productivity standpoint, particularly when the well conditions allow the useof starch-removing enzymes. Such enzyme treatments are the single most effective means of min-imizing drawdown requirements to initiate production and provide a uniform flow profile withminimal skin. Enzyme J503 can be incorporated into VES carrier fluids for simultaneous gravel-packing and cake cleanup in openhole completions.

Ezyme J503 can also be mixed with CAS (e.g., U105, U820 formulations) to attack both calciumcarbonate and starch components of the filter cake in a single step. Enzyme J503 is effective to225°F [107°C] when mixed in monovalent brines. Starch enzymes are ineffective when mixed indivalent brines such as calcium chloride and calcium bromide.

Applications■ Slow, uniform and complete removal of starch from the filter cakes of water-based RDF, such

as biopolymer, starch and calcium carbonate or biopolymer, starch and sized-salt systems

Benefits and features■ More uniform filter-cake cleanup as result of lower reaction rates■ Compatible with chelating agent solutions, allowing single-step carbonate and starch removal■ Compatible with VES fluids, allowing simultaneous gravel-packing and cake cleanup■ Corrosion-free starch removal

Systems 53

Figure 3-8. Sudden increases in fluid leakoff during overbalanced laboratory soaks indicate that filter-cake removal with CAS are anorder of magnitude slower than with HCl. Reaction rates are measured in hours, allowing these systems to be placed across long hori-zontal, openhole sections without creating thief zones and high fluid loss. Reaction rates are controlled by adding CAS, enzyme or VES.Additional VES for higher viscosity or more CAS slows reaction rates; additional enzyme increases reaction rates.

Leakoffvolume(cm3)

60

50

40

30

20

10

00 5 10 15 20 25 30

Time (hr)

CAS/enzyme

CAS/enzyme/VES

CAS

HCI

Oxidizers for filter-cake cleanup in openhole completionsOxidizers can be used to degrade the polymers in common water-based RDF filter cakes. The oxi-dizers work by generating free radicals that attack the links between the polysaccharide components(sugar units) of the polymer. Attack can occur on the polymer backbone or a side chain. Typicalpolymeric components of water-based RDF filter cakes that can be degraded by oxidizers are xan-than gum and scleroglucan used for drilling fluid viscosity and starches used for fluid-loss control.

The effectiveness of oxidizers is limited by pH (practical pH range is 4 to 10). Oxidizer efficiencyis also dependent on temperature (practical range of most is between 120 and 250°F [49 to 121°C].Below 130°F [54°C] oxidizer effectiveness drops dramatically below pH 8. The compatibilitiesof the most common oxidizers with carrier brines are shown in the accompanying table.Schlumberger Heath Safety and Environment policy specifies that oxidizers can not be used incombination with acids; dangerous by-products can be produced, such as chlorine gas when HClis present. However, 2-stage filter-cake cleanup treatments can be performed using a first-stageoxidizer soak to remove polymers, followed by acid or chelant as a second stage to remove calciumcarbonate bridging agents.

Oxidizers can be formulated in polymeric viscous carrier fluids as internal breakers, as in frac-pack or gravel-pack applications. When used in openhole gravel packs with polymeric carrierfluids, the oxidizer will also be spent on the polymers and therefore less will be available to attackthe filter cake. Oxidizers are not compatible with VES gelling agents. The recommended oxidizersfor filter-cake cleanup applications are listed below.

J218 formulationJ218 formulation is effective between 125 and 200°F [52 to 93°C]. Typical concentrations arebetween 20 and 100 lbm/1000 gal [9 and 45 kgm/3785 L]. Below 150°F [65°C], J318 formulationshould be incorporated at 0.1 to 0.2% as an activator. Brine compatibilities are shown in theaccompanying table. J218 oxidizer can not be combined with chelating agents such as U42, U105,U106, U821 or U820, but these can be spotted like acids after the oxidizer soak.

J481 formulationJ481 formulation is effective between 160 and 225°F [71 to 107°C]. Typical concentrations arebetween 20 and 100 lbm/1000 gal [9 and 45 kgm/3785 L]. Below 175°F [79°C], J318 formulationshould be incorporated at 0.1 to 0.2% as an activator. J481 oxidizer is applicable at higher temper-atures than J218 because it takes more energy to begin free-radical generation and attack polymers.

Calcium HypochloriteAlthough not coded, this product is available through M-I Drilling Fluids. With an applicabletemperature range between 80 and 300°F [27 to 149°C], calcium hypochlorite has been testedsuccessfully in divalent brines such as calcium chloride-bromide at 50 lbm/1000 gal [23 kgm/3785 L]and is effective in attacking polymers in water-based RDF filter cakes. Calcium hypochlorite issupplied as a dry product.

SAFE-BREAK S Sodium Hypochlorite and SAFE-BREAK L Lithium Hypochlorite These are alternatives to calcium hypochlorite. They are applicable in temperatures from 80 to 300°F[27 to 149°C]. There are several differences between these oxidizers and calcium hypochloritewith respect to brine compatibility. These products are available through M-I Drilling Fluids.SAFE-BREAK S oxidizer is supplied as a liquid product, whereas SAFE-BREAK L oxidizer is a dryproduct.

54 Sand Control Pumping

PeroxidesPeroxides have a practical temperature range of 80 to 250°F [27 to 121°C]. They can be formulatedin ammonium chloride brine unlike sodium and lithium hypochlorites.

Application■ Removal of polymeric components of water-based RDF filter cakes in openhole completions

(barefoot, screen and slotted liner or gravel-pack applications)

Benefits and features■ Degrade polymers used in RDFs

Systems 55

Table 3-4.

Brine carrier fluid Density range Oxidizers

Name Formula lbm/gal Persulfate Bromate Peroxides Sodium Calcium Lithium

Low High J218 J481 Hypochlorite Hypochlorite J349 Hypochlorite

Water H2O 8.34 8.34 Yes Yes Yes Yes Yes Yes

Seawater Blend 8.4 8.6 Yes Yes Yes Yes Yes Yes

Ammonium chloride NH4Cl 8.4 8.9 Yes Yes Yes No No No

Potassium chloride KCl 8.4 9.7 Yes Yes Yes Yes Yes Yes

Sodium chloride NaCl 8.4 10.0 Yes Yes Yes Yes Yes Yes

Potassium carbonate K2CO3 8.34 10.5 No No No Yes No Yes

Potassium bromide KBr 8.4 10.9 Yes Yes Yes Yes Yes Yes

Sodium formate NaCHO2 9 11.1 No No No LTR1 No LTR1

Calcium chloride CaCl2 8.4 11.6 No No Yes Yes Yes Yes

Cesium formate CsCHO2 8.34 19.2 No No No LTR1 No LTR1

Sodium bromide NaBr 8.4 12.7 Yes Yes Yes Yes Yes Yes

Potassium formate KCHO2 8.8 13.0 No No No LTR1 No LTR1

Calcium bromide CaBr2 8.4 14.2 No No Yes Yes Yes Yes

CaBr2/CaCl2 Blend 11.7 15.1 No No Yes Yes Yes Yes

CaCl2/CaBr2/ZnBr2 Blend 15 19.2 No No No No No No

Zinc bromide ZnBr2 19.2 20.2 No No No No No No

Magnesium chloride MgCl2 No No Yes Yes Yes Yes

Sodium carbonate Na2CO3 No No No Yes No Yes† LTR: laboratory testing recommended

CleanSEAL systemThe CleanSEAL* perforation fluid-loss-control system incorporates a crosslinked hydroxyethyl-cellulose (HEC) that has been grated to individual particles, which are easily dispersed andsuspended in most completion brines. The crosslinked HEC particles are semirigid, and deformto form a highly effective, low-permeability filter cake. They fill perforations, minimizing lossesinto the formation. The CleanSEAL system is directly added to completion brine in a paddlemixer on location, and it takes 3 to 5 min to mix. Low friction pressures make the CleanSEALsystem easy to pump through coiled tubing during workover operations. The system is easy tobreak with mild acids, which linearize the crosslinked HEC particles. CleanSEAL systems arecompatible with most brines to 15.2 lbm/gal (potassium chloride, sodium chloride, sodium bromide,calcium chloride, calcium chloride-calcium bromide or calcium bromide) and can be used attemperatures to 300°F [149°C]. It is stable for 10 to 12 hr at 300°F [149°C], with longer stabilityat lower temperatures.

ApplicationsFor use as fluid-loss-control

■ after perforating and before sand control■ during workover operations

Benefits and features■ Simple mixing on location■ Easy to pump through coiled tubing as a result of low friction pressure■ Easy to break with mild acids■ Temperature stability to 300°F [149°C]

nLess damage from HEC polymer

PROTECTOZONE VP fluid The PROTECTOZONE* VP fluid is a delayed, crosslinked gel system used for temporary pluggingof zones. It contains low-residue HEC polymer at 80 to 120 lbm/1000 gal [36 to 54 kgm/3785 L]and internal breakers for controlled fluid loss and cleanup. The PROTECTOZONE VP system isparticularly useful in high-permeability formations where excessive losses of heavy brines or lineargels are not acceptable. It can be used in formations ranging from 0.1 to 2 darcies. The system iscompatible with most brines to 15.2 lbm/gal [6.9 kgm/L] (potassium chloride, sodium chloride,sodium bromide, calcium chloride, calcium chloride-calcium bromide or calcium bromide) andcan be used at temperatures from 80 to 290°F [27 to 143°C].

Applications■ Workover operations requiring fluid-loss-control ■ As a temporary blocking gel ■ Temperatures to 290°F [143°C]

Benefits and features■ Delayed crosslinking for simplified pumping■ Compatible with most brines

56 Sand Control Pumping

SEAL-N-PEEL pillThe SEAL-N-PEEL biopolymer-starch-calcium carbonate pill is designed specifically to stop lossesafter sand control treatments, where a mechanical fluid-loss-control device either was not usedor failed. Because the calcium carbonate particle size distribution is customized for each sandcontrol screen, the SEAL-N-PEEL pill rapidly deposits a very low permeability and thin filter cakeon the inside surface of the screen assembly, with minimal invasion of the gravel pack. This prop-erty, along with the use of a newly developed, modified glycol additive to reduce the adhesiveforces that bind the seal to the screen, allows it to be completely removed with little differentialpressure during production, typically without breakers.

This product is available through M-I Drilling Fluids. SEAL-N-PEEL technology is compatiblewith most brines to 19.2 lbm/gal [8.7 kgm/L] (potassium chloride, sodium chloride, sodium bromide,potassium formate, sodium formate, calcium chloride, calcium chloride-calcium bromide, calciumbromide, zinc bromide and cesium formate) and can be used at temperatures to 320°F [160°C],depending on brine type and density. Higher temperature applications can be achieved withformate brines.

Applications■ For use as a fluid-loss-control pill after gravel-packing or fracture-packing treatments, where

a mechanical fluid-loss-control device either was not used or failed■ Temperatures to 320°F [160°C]

Benefits and features■ Customized calcium carbonate particle size distribution for each sand control screen■ Minimal invasion of gravel pack■ Easy to flow back without breakers

Completion brines Completion brine products are available through M-I Drilling Fluids and can be divided intotwo categories: monovalent brines and divalent brines.

Monovalent brinesAmmonium chlorideAmmonium chloride powder is a high-purity 1.53-sg dry crystalline inorganic salt used to form clearbrine fluids with densities from 8.4 to 8.9 lbm/gal [3.8 to 4 kgm/L], 1.01 to 1.07 sg. At concentra-tions of 2 to 7% it is used as a clay and shale stabilizer. Ammonium chloride brines are used toprevent the formation of insoluble fluorosilicates when HF acid (mud acid or clay acid) is used.An endothermic reaction occurs when mixing dry ammonium chloride and water, resulting in adecrease in fluid temperature. It is packaged in 50- and 55-lbm [23- and 25-kgm] sacks. Crystallizationtemperature of ammonium chloride brines varies between 5 and 31°F [-15 and -0.5°C], dependingon density. Ammonium chloride brines may liberate ammonia gas at pH above 9.0.

Potassium chloridePotassium chloride powder is a high-purity 1.98-sg dry crystalline inorganic salt used to form clearbrine fluids with densities from 8.4 to 9.7 lbm/gal [3.8 to 4 kgm/L], 1.01 to 1.16 sg. Because of theirexcellent shale inhibition characteristics, potassium chloride brines are commonly used in shalyformations. Potassium chloride is often added to other brine systems to enhance their inhibitionproperties. It is packaged in 50- and 100-lbm [23- and 45-kg] sacks. Crystallization temperatureof potassium chloride brine varies between 10 and 59°F [-12 and 15°C], depending on density.Potassium chloride can also be supplied in bulk liquid quantities.

Systems 57

Sodium chlorideSodium chloride powder, a dry crystalline salt with 2.16 sg, is an economical product for formu-lating clear brine fluids with densities from 8.4 to 10.0 lbm/gal [3.8 to -12.2 kgm/L], 1.01 to 1.20 sg.As workover and completion fluids, sodium chloride brines are used in wells that do not requirethe higher density or the special inhibitive properties of calcium or potassium systems. Sodiumchloride brines are used to increase density, reduce salt dissolution when drilling halite salt sec-tions, and reduce freezing point and gas hydrate potential in a wide variety of water- and oil-basedrilling fluids. Sodium chloride is also used to adjust the density of other nonsaturated brinessuch as seawater, potassium chloride and ammonium chloride. It is packaged in 100-lbm [45-kgm],80-kg [176-lbm] and 50-kg [110-lbm] sacks. Crystallization temperature of sodium chloride brinevaries between –5 and 31 degF, depending on density. Sodium chloride is also supplied in liquidform as a saturated solution with a density of 10.0 lbm/gal [4.5 kgm/L], 1.2 sg and a pH of 6.5 to 7.0.

Sodium formateSodium formate powder is a high-purity, crystalline organic salt with 1.92 sg used to form clearbrine used in workover and completion operations that require densities from 8.4 to 11.0 lbm/gal[3.8 to 5 kgm/L], 1.01 to 1.33 sg. Sodium formate brines eliminate the potential of formationdamage that can result from the precipitation of carbonate, bicarbonate or sulfate compoundsassociated with use of calcium-based brines where formation waters contain high concentrationsof bicarbonate and sulfate ions. They are excellent shale stabilizers for water-sensitive formationsthat contain clay and/or shale and are environmentally friendly. Sodium formate brines alsoextend temperature limits of some polymers used in drilling fluids, gravel-pack carrier fluids andfluid-loss-control pills. For this reason they are often used in high-temperature wells. Potassiumformate brines can be blended with sodium formate to achieve densities from 11.0 to 13.1 lbm/gal[5 to 6 kgm/L], 1.33 to 1.57 sg. They can be formulated with various crystallization temperaturesand for summer or winter blends. They are packaged in 55-lbm [25-kgm] sacks or in 1000-kg[2205-lb] bags. Sodium formate can also be supplied in liquid form with a density of 11.0 lbm/gal[5 kg/L], 1.33 sg, a pH of 8.6 and a viscosity of 29 cp.

Sodium bromide-sodium chlorideSodium bromide-sodium chloride brine systems are salt blends used to form clear brines usedin workover and completion fluids with densities from 10.0 to 12.7 lbm/gal [4.5 to 5.8 kgm/L],1.20 to 1.52 sg. These systems eliminate the potential of formation damage that can result fromthe precipitation of carbonate, bicarbonate or sulfate compounds associated with use of calcium-based brines where formation waters contain high concentrations of bicarbonate and sulfate ions.Sodium bromide and sodium chloride brine systems are packaged in bulk liquid quantities.

Sodium bromideSodium bromide powder is a high-purity salt, with a 3.2 sg, used to form clear brine fluids withdensities from 8.4 to 12.7 lbm/gal [3.4 to 5.8 kgm/L], 1.01 to 1.52 sg. It is used where formationwaters contain high concentrations of bicarbonate or sulfate ions, which can result in precipitationof carbonate, bicarbonate or sulfate compounds when calcium-based brines are used. It is packagedin 55-lbm [25-kgm] sacks. Crystallization temperature of sodium bromide brine varies between-21 and 38°F [-29 and 3°C], depending on density. Sodium bromide is also supplied in liquid formas a nearly saturated solution with a density of 12.5 lbm/gal [5.6 kgm/L], 1.50 sg and a pH of 7.0,with a crystallization temperature of 33°F [0.5°C] and a viscosity of 3 cp. Unless a chlorides-freeenvironment is required, sodium bromide brines should be used as part of a sodium chloride andsodium bromide blend. Blends with higher density zinc bromides can also be used.

58 Sand Control Pumping

Potassium formatePotassium formate powder is a high-purity, dry crystalline organic salt with 1.91 sg used to formclear brine fluids with densities ranging from 8.4 to 13.1 lbm/gal [3.8 to 6 kgm/L], 1.01 to 1.57 sg.Potassium formate brines eliminate the potential of formation damage that can result from theprecipitation of carbonate, bicarbonate or sulfate compounds associated with use of calcium-based brines where formation waters contain high concentrations of bicarbonate and sulfateions. They are excellent shale stabilizers for water-sensitive formations that contain clay or shaleand are environmentally friendly. Potassium formate brines also extend temperature limits of somepolymers used in drilling fluids, gravel-pack carrier fluids and fluid-loss-control pills. For thisreason they are used in high-temperature wells. Potassium formate brines can be blended withsodium formate for densities from 11.0 to 13.1 lbm/gal [5 to 6 kgm/L] to give a more cost-effectivebrine system. They can be formulated with various crystallization temperatures and for summeror winter blends. They are packaged in 55-lbm [25-kgm] sacks or in 1000-kg [2205-lb] bags.Potassium formate can also be supplied in liquid form with a density of 13.1 lbm/gal [6 kgm/L],1.57 sg, a pH of 8.5 and a viscosity of 47 cp.

Cesium formateCesium formate (liquid) is a single organic-salt clear brine fluid. Pure cesium formate solutionscan be prepared with densities from 8.4 and 19.2 lbm/gal [3.8 and 8.71 kgm/L], 1.08 to 2.3 sg.However, these fluids are typically mixed with potassium formate solutions to yield a density from13.1 to 19.2 lbm/gal [6 to 8.71 kgm/L], 1.57 to 2.3 sg in a more cost-effective way. Like the otherformate brines, cesium formate shows excellent thermal stabilization effects on natural polymersand is environmentally friendly. It is packaged in bulk liquid quantities.

Divalent brinesCalcium chlorideCalcium chloride powder is a high-purity salt, with a 2.26 sg, used to form clear brine fluids withdensities from 8.4 and 11.8 lbm/gal [3.8 and 5.4 kgm/L], 1.01 and 1.42 sg. They may be blendedwith heavier brines (e.g., calcium bromide, zinc bromide) for higher density applications.Calcium chloride brines help prevent the hydration and migration of clays. Crystallization tem-perature of calcium chloride brine varies between -61 and 44°F [-52°C], depending on density.As a powder, this product is packaged in 80-lbm [36-kgm] sacks. It is also supplied in liquid formas a nearly saturated solution with a density of 11.6 lbm/gal [5.3 kgm/L], 1.39 sg, a pH of 6.5 to 7.0,a crystallization temperature of 44°F [7°C] and a viscosity of 7 cp.

Calcium bromide-calcium chlorideCalcium bromide-calcium chloride brine systems are two-salt solutions used during workoverand completion operations, which require densities 11.7 to 15.1 lbm/gal [5.3 to 6.8 kgm/L],1.40 to 1.81 sg. The desired density is obtained either by blending 11.6 lbm/gal [5.3 kgm/L], 1.40 sgcalcium chloride with 14.2 lbm/gal [6.4 kgm/L], 1.70 sg calcium bromide brine and dry calciumchloride or calcium bromide, or by mixing dry calcium chloride and dry calcium bromide in water.They can be formulated with various crystallization points and are available for special applicationsand winter use.

Systems 59

Calcium bromideCalcium bromide powder is a high-purity salt used to form clear brine fluids. Pure single-saltsolutions of calcium bromide are used to form fluids with densities from 8.4 and 15.6 lbm/gal[3.8 and 7.1 kgm/L], 1.01 and 1.87 sg. Calcium bromide brines inhibit hydration and migration ofswelling clays. They can be formulated with various crystallization temperatures and for summeror winter blends. As a powder, this product is packaged in 55-lbm [25-kgm] sacks. It is also suppliedin liquid form with a density of 14.2 lbm/gal [6.4 kgm/L], 1.70 sg, a pH of 7.0, a crystallizationtemperature of 0°F [-18°C] and a viscosity of 6 cp.

Zinc bromide-calcium bromideZinc bromide-calcium bromide (liquid), often referred to as zinc bromide, is available in densitiesfrom 19.2 lbm/gal [8.7 kgm/L], 2.30 sg and is 54.5% zinc bromide and 19.5% calcium bromide. It isused for clear-brine workover and completion operations, which require high-density fluids. Zincbromide-calcium bromide brines are generally blended with calcium chloride powder or liquidto form fluids with various crystallization temperatures and for summer or winter blends. Zincbromide-calcium bromide liquid at 19.2 lbm/gal [8.7 kgm/L] has a pH of 1 to 2 and a crystallizationtemperature of 10°F [-12°C]. It is packaged in bulk liquid quantities.

Zinc bromide-calcium bromide-calcium chlorideZinc bromide-calcium bromide-calcium chloride brine systems are three-salt solutions used forclear-brine workover and completion operations, which require high-density fluids ranging from15.2 to 19.2 lbm/gal [6.89 to 8.71 kgm/L], 1.82 to 2.30 sg. The desired density and crystallizationpoint is obtained by blending 15.1 lbm/gal [6.8 kgm/L], 1.81 sg calcium chloride-calcium bromidebrine with 19.2 lbm/gal [8.7 kgm/L], 2.30 sg calcium bromide-zinc bromide brine. The pH of zincbromide-calcium bromide-calcium choride brines typically varies from 1.8 to 6.0.

60 Sand Control Pumping

Figure 3-9. Maximum densities attainable with various brine systems.

8.4 9.4 10.4 11.4 12.4 13.4 14.4 15.4 16.4 17.4 18.4 19.4

Maximum density (ppg)

Ammonium Chloride

Potassium Chloride

Sodium Chloride

Sodium Formate

Calcium Chloride

Sodium Bromide

Potassium Formate

Calcium Bromide

Cesium Formate

Zinc Bromide

VES fluidsIncreased awareness of formation and completion damage caused by polymer-based fluids has ledto the development of VES-based carrier fluids. Because these fluids break upon contact with mostcrude oils, they typically do not require breaker treatments for producing wells, and addition of lowconcentrations of a mutual solvent in injection water is sufficient to break the fluid to water-likeconsistency, maximizing injectivity. VES fluids consistently yield higher retained permeabilitiesthan polymer-based carrier fluids because they leave no polymeric residue. In relatively lowpressure dry gas wells, a mutual solvent can be spotted into the basepipe immediately aftergravel-packing, using the MudSOLV circulation tool. VES fluids can be mixed continuously usingeither a WASP* Water and Sand Proportioner or POD* Programmable Optimal Density Blenderor in batch mode using any of the blending tanks.

VES fluids are compatible with certain MudSOLV chemicals, allowing simultaneous gravel-packing and cake cleanup in openhole completions. Because VES fluids exhibit very low frictionpressures, they are ideal for use with Alternate Path technology for gravel-packing long horizon-tal intervals. VES formulations are available with varying levels of brine tolerance, temperaturelimitations and compatibility with MudSOLV chemicals.

J483 PERMPAC AV fluidsPERMPAC AV fluids are compatible with most common brines including calcium chloride, sodiumchloride, ammonium chloride, calcium chloride and calcium bromide. They are incompatiblewith sodium bromide, zinc bromide, sodium formate, potassium formate and cesium formate.Temperature limit of PERMPAC AV fluids depends on the brine type and density, but is typically lessthan 150°F [65°C]. PERMPAC AV fluids are compatible with enzyme J503 for use in simultaneousgravel-packing and cake cleanup processes in openhole completions.

J508 ClearFRAC fluids ClearFRAC fluids are compatible with most common brines including KCl, sodium chloride, NH4Cl,calcium chloride, sodium formate, potassium formate and cesium formate in certain density ranges,with less salt tolerance than PERMPAC AV. They are incompatible with sodium bromide, calciumbromide and zinc bromide. Temperature limit of J508W ClearFRAC fluids depends on the brinetype and density, but is typically 200 degF for densities lower than 8.6 lbm/gal [3.9 kgm/L] and150 to 175°F [65 to 79°C] for higher densities. J508W ClearFRAC fluid is compatible with enzymeJ503 and U105 CAS for use in simultaneous gravel-packing and cake cleanup processes in openholecompletions, subject to compatibility of the enzyme and CAS with the base brine. J508W ClearFRACfluid is incompatible with U106, U820 and U821 CAS.

Systems 61

Figure 3-10. ClearFRAC fluid is a viscoelastic surfactant, not a long-chain polymer that can leaveresidue in the gravel pack or fracture proppant pack.

J533 ClearFRAC-EF An environmentally improved ClearFRAC has been developed for land and offshore fracturingapplications. This fluid has a temperature limit of 180°F [82°C] and is compatible with sodiumchloride and potassium chloride to 9.5 lbm/gal [4.3 kgm/L], making it suitable for frac packing andfor gravel-packing either in squeeze position or in wells that do not require high-density brines.The fluid is compatible with fresh mix waters and brines having divalent ion concentrations lessthan 1000 ppm through addition of U042 chelating agents.

ClearPAC fluids ClearPAC fluids have been developed to overcome the density limitations of ClearFRAC fluidsand the temperature limitations of the PERMPAC AV fluids. ClearPAC fluids are compatible withpotassium chloride, sodium chloride, sodium bromide, calcium chloride, calcium bromide, sodiumformate and potassium formate; they are incompatible with zinc bromide. The temperature limitof ClearPAC fluids depends on the brine type and density. ClearPAC fluids can be formulated atdensities greater than 13 lbm/gal [5.9 kgm/L] with a temperature stability approaching 300°F[149°C], although the density and temperature limits with formate brines are considerably lower.ClearPAC fluids are compatible with U106, U820 and U821 CAS but are incompatible with U105 CAS.

62 Sand Control Pumping

Figure 3-11. Comparisons of temperature limit (left) and maximum applicable density (right) of existing VES fluids and ClearPAC fluids.

Existing VES fluids

ClearPAC fluids

12.0

1.5

11.0

10.5

10.0

9.5

9.0

8.5

ppg

300

250

200

150

100

50

0

°F

Figure 3-12. Rheological profile of an 11.7 ppg, sodium bromide/U280 chelating agent solution-based VES fluid at varous temperatures.

1000

100

1010 100 1000

Shear rate (1/s)

Apparentviscosity

(cp)

200°F

220°F

240°F

250°F

Applications■ Gravel-packing or frac packing wells in circulating or squeeze position■ Simultaneous gravel-packing and cake cleanup with the Alternate Path technique ■ Fracturing with coiled tubing

Benefits and features ■ High retained permeability in both formation and gravel pack■ Breaks with exposure to produced liquid hydrocarbons■ Low friction pressure losses■ Compatible with chelating agent solutions and enzymes for simultaneous gravel-packing

and cake cleanup■ Compatible with most brines

Polymeric gravel-packing fluidsVarious polymeric gravel-packing fluids are available, including hydroxyethylcellulose (HEC),xanthan and scleroglucan. Because polymers leave insoluble residue, they typically yield lowerretained permeabilities than VES systems. Polymeric carrier fluids can be broken with internal orexternal breakers such as enzymes, oxidizers or acids. Polymeric fluids generally require shearingand filtration to eliminate microgels ("fish-eyes"), particularly if the powder form is used. In addi-tion, they must typically be batch mixed because they require hydration. They are recommendedfor jobs where VES systems cannot be used because of incompatibilities or other limitations, suchas density and/or temperature. Completion damage caused by polymers can be minimized throughproper mixing, shearing and filtering as well as use of internal or external breakers.

J164 Powder Hydroxyethylcellulose and J512 Liquid HydroxyethylcelluloseHaving lower insoluble residue content, HEC fluids yield higher retained permeability than otherpolymeric carrier fluids. Typical polymer concentration in HEC fluids is 70 to 120 lbm/1000 gal[32 to 54 kgm/3785 L], depending on bottomhole temperature. Liquid form of J512 HEC is preferredbecause it minimizes the risk of fish-eyes and thus potential formation and completion damage.In gravel-packing applications, HEC fluids are generally limited to temperatures lower than250°F [121°C]. They can be mixed with most brines, and densities to 19.0 lbm/gal.[8.6 kgm/L]are obtainable using zinc bromide.

ScleroglucanScleroglucan fluids have higher temperature stability than HEC fluids. Typical polymer concen-tration in scleroglucan fluids is 70 to 120 lbm/1000 gal [32 to 54 kgm/3785 L]. Scleroglucan fluidscan be formulated with temperature stability approaching 350°F [177°C], using formate brines.Scleroglucan can be mixed with most brines, and densities to 19.0 lbm/gal [8.6 kgm/L] areobtainable using cesium formate.

Systems 63

Table 3-5. Comparison of Formation and Gravel-Pack Damage Induced by ClearPAC and HEC Surfactants

System Formation Retained Permeability (%) 20/40 Gravel-Pack Retained Permeability (%)

HEC fluid 54 63

ClearPAC fluid 99 100

XanthanXanthan fluids have higher low-shear viscosities and higher temperature stability than HEC fluids.Typical polymer concentration in xanthan fluids is 70 to 120 lbm/1000 gal [32 to 54 kgm/3785 L].These fluids can be formulated with formate brines to achieve temperature stability to approx-imately 350°F [177°C]. Xanthan can be mixed with most brines, and densities to 19 lbm/gal[8.6 kgm/L] are obtainable using cesium formate.

Applications■ Gravel-packing with Alternate Path technology in wells where VES systems cannot be used■ Temperatures of approximately 350°F [177°C]

Benefits and features■ Compatible with most brines up to 19 lbm/gal [8.6 kgm/L]

CLAY ACID PACK fluidsThe CLAY ACID PACK* fluid system for gravel-packing is designed to reduce an otherwise two-step process into a single-stage gravel-packing and clay acid treatment. There are two types ofCLAY ACID PACK fluids. Selection depends on the carrier fluid:

■ CLAY ACID PACK fluid using regular clay acid as the base fluid, viscosified with gelling agentJ164, for temperatures to 250°F [121°C)]

■ CLAY ACID PACK fluid using clay acid LT as the base fluid, viscosified with gelling agent J164for temperatures to 130°F [54°C]

Applications■ Gravel-packing in formations requiring treatments for control of fines and/or stabilization

of clays

Benefits and features■ Saves rig time■ Provides simultaneous clay stabilization and gravel-packing■ Removes formation damage caused by clay fines■ Can be used at high-gravel loadings

OilPAC GO fluids The OilPAC* GO oil-based fluid system for gravel-packing and frac packing was developed foruse in water-sensitive formations. These fluids are water-free, single-phase solutions with goodleakoff and gravel transport properties. Components are designed for refined hydrocarbons, suchas kerosene or diesel, but are also suitable for some crudes and condensates.

Two formulations are available: OilPAC GO LT and OilPAC GO HT.

64 Sand Control Pumping

OilPAC GO LT formulationOilPAC GO LT for temperatures from 70 to 225°F [21 to 107°C]. OilPAC GO LT fluid uses oil gellingagent J518, activator C108 and breaker M3 or J465. The OilPAC GO LT formulation is designed fora continuous-mixed gelled oil system. The fluid can be energized with up to 50% carbon dioxidewhen using low sulfur No. 2 diesel. Nitrogen can also be used.

OilPAC GO HT formulationOilPACGO HT for temperatures from 150 to 300°F [65 to 149°C]. OilPAC GO HT fluid uses oil gellingagent J452, liquid activator J453 and soda ash M3 as a breaker. The OilPAC GO HT formulationcan be batch-mixed. The fluid quickly reaches and maintains a stable viscosity after it is mixed.This is an important operational feature that simplifies field mixing, pumping and quality control.

Applications■ Gravel-packing water-sensitive formations drilled with oil-based fluids in squeeze position or

frac packing ■ Gravel-packing low-pressure wells (less than 6.7 lbm/gal [3.0 kgm/L] equivalent) drilled with

oil-based fluids in circulating position

Benefits and features■ Water-free, single-phase fluid for efficient leakoff and gravel transport■ Compatible with refined hydrocarbons■ Can be continuously mixed

OilPAC EM systemThe OilPAC* EM oil-based fluid system for gravel-pack operations was developed for use in water-sensitive formations and those drilled with oil-based fluids. OilPAC-EM fluids are oil-external,water-internal emulsions much like most oil-based drilling fluids, except they do not contain anysolids. The OilPAC* EM system uses the same base oil as in oil-based drilling fluid (e.g., refinedmineral oil, kerosene, diesel), a brine and a proprietary emulsifier package. As such, its viscosity iscontrolled through the oil to water ratio, and its density is controlled through both the oil to waterratio and the type and density of the internal brine phase. The OilPAC EM system can be formu-lated with densities to 15.4 lbm/gal [6.9 kgm/L] for use at temperatures exceeding 250°F [121°C].With these features, the OilPAC-EM system is suitable for circulating gravel packs as well assqueeze packing with the Alternate Path technique. The OilPAC EM system eliminates displace-ment of openhole reservoir sections to water-based fluids, and thus minimizes the risk of wellboreinstability problems and formation and completion damage as well as reduces rig time.

The OilPAC EM fluid system can also be formulated with a pH-modifier-calcium carbonate-dissolver (e.g., a chelating agent solution or a mild organic acid) in the internal brine phase,allowing simultaneous gravel-packing and cake cleanup in wells drilled with FAZEPRO,reversible synthetic or oil-based RDF (available from M-I Drilling Fluids). The FAZEPRO-OilPACEM reservoir drilling and gravel-packing fluid package allows slow removal of calcium carbonatebridging and weighting agents from the filter cake without inducing losses during gravel-packingand dissolves calcium carbonate before the well is put on production.

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Applications■ Gravel-packing wells drilled with oil-based fluids in circulating or squeeze position, particularly

in water-sensitive formations and/or intervals containing reactive shales■ Suitable for openhole gravel-packing (vertical, deviated or horizontal) using the Alternate

Path technique

Benefits and features■ OilPAC EM fluid allows gravel-packing in an all-oil environment ■ Solids-free■ Can be formulated with densities to 15.4 lbm/gal [6.9 kgm/L] and temperatures exceeding

250°F [121°C] ■ Can be used for simultaneous gravel-packing and cake cleanup in conjunction with FAZEPRO

RDF fluid

Waterfrac fluidsWaterfrac fluids use linear (uncrosslinked) gels of fresh water, seawater or potassium chloridebrines as efficient and economical fracturing fluids. Guar and hydroxy-propylguar (HPG) gellingagents are the most common polymers used to prepare Waterfrac fluids. A cellulose-derivativegelling agent and xanthan gum are also available.

NomenclatureWaterfrac fluids are identified by the letters WF* followed by three digits to indicate the typeand concentration of gelling agent. The first digit indicates the type of gelling agent: "1" for guarand "2" for HPG. The last two digits indicate the concentration of thickener in lbm/1000 gal[kgm/3785 L] of fluid. Example: WF 140 contains a guar gelling agent at a concentration of40 lbm/1000 gal [18 kgm/3785 L].

Waterfrac fluid types The Waterfrac 100 (WF 100) fluids are water-based and viscosified with refined guar polymers.They are also the base gels that are crosslinked to form the Widefrac fluids (YF 100, YF 300 andYF 500). The Waterfrac 200 (WF 200) fluids are water-based and viscosified with refined HPGpolymers. They are also the base gels that are crosslinked to form the Widefrac fluids (YF 200, YF 400and YF 600).

Applications■ Operations using guar gelling agents in temperatures ranging from 50 to 200°F [10 to 93°C]

Benefits and features■ Uncrosslinked gels provide efficient, economical fracturing fluids

66 Sand Control Pumping

Widefrac fluidsThe Widefrac fluid system utilizes the very viscous solution formed by crosslinking Waterfrac fluids.Crosslinking agents are used to dramatically increase the effective molecular weight of the polymer,thereby increasing the viscosity of the solution.

NomenclatureWidefrac crosslinked fluids are identified by YF followed by three digits to indicate the type and con-centration of gelling agent used. The first digit indicates the gelling agent and crosslinker type;the second and third digits denote the gelling agent concentration in lbm per 1000 gal [3785 L].Example: YF 840HT is a carboxymethylhydroxypropyl guar (CMHPG) gelling agent, zirconatecrosslinked, at 40 lbm/1000 gal [18 kgm/3785 L] of fluid, designed for HT.

CrosslinkersVarious materials are used to crosslink water-soluble polymers.

■ Boric acid and borate salts produce crosslinked gels with guar and HPG that are stable to325°F [163°C].

■ Transition-metal crosslinkers titanate and zirconate are used in fracture treatments of deep,hot wells. The upper temperature limit for these gels is 400°F [204°C].

Widefrac fluidsWidefrac fluids are available in the formulations shown herein:

■ The Widefrac 100 (YF 100) system is water-based and is composed of a refined guar gellingagent crosslinked by a borate crosslinker. Fluids can be batch-mixed or continuously mixed.The temperature range for fresh water and fresh water containing potassium chloride-basedfluids is 80 to 200°F [27 to 93°C]. The temperature range for seawater-based fluids is 80 to 175°F[27 to 79°C].

■ The Widefrac 100HTD (YF 100HTD) system is water-based and is composed of a refined guargelling agent crosslinked by a borate-type crosslinker. Fluids can be batch-mixed or continuouslymixed. The temperature range is from 125 to 325°F [52 to 163°C].

■ The Widefrac 100.1HTD (YF 100.1HTD) system is water-based and contains a refined guargelling agent crosslinked with a borate crosslinker. Designed for continuous-mix operations.The temperature range is from 175 to 350°F [79 to 177°C].

■ The Widefrac 100LG (YF 100 LG) system is water-based and contains a refined guar gellingagent (15 to 20 lbm/1000 gal) [6.8 to 9.0 kgm/3785 L] crosslinked with a borate crosslinker.Fluids can be batch-mixed or continuously mixed. The temperature range is from 100 to 200°F[38 to 93°C] for fluids prepared with fresh water or fresh water containing potassium chloride.

■ The YF 100 LGD system is water-based and contains a refined guar gelling agent (20 to 50lbm/1000 gal) [9.0 to 22.6 kgm/3785 L] crosslinked with a borate crosslinker. Fluids can bebatch-mixed or continuously mixed. YF 100 LGD fluids are prepared using any of the Waterfrac100 fluids. The temperature range is from 175 to 325°F [79 to 163°C] for fluids prepared withfresh water.

■ The Widefrac 200 (YF 200) system are water-based fluids composed of a HPG gelling agentcrosslinked with a borate crosslinker. Fluids can be batch-mixed or continuously mixed.The temperature range for fresh water and fresh water containing potassium chloride-basedfluids is 80 to 200°F [27 to 93°C]. The temperature range for seawater-based fluids is 80 to 175°F[27 to 79°C].

■ The Widefrac 300LPH (YF 300LPH) system is water-based and is composed of a guar gellingagent crosslinked with a titanium crosslinker. Fluids are designed for either batch-mix orcontinuous-mix operations. The temperature range is from 75 to 225°F [24 to 107°C].

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■ The Widefrac 400LPH (YF 400LPH) system is water-based and is composed of a HPG gellingagent crosslinked with a titanium crosslinker. Fluids are designed for either batch-mix orcontinuous-mix operations. The temperature range is from 75 to 250°F [24 to 121°C].

■ The Widefrac 500HT (YF 500HT) system is water-based and is composed of a refined guar gellingagent crosslinked with a zirconate crosslinker. Fluids are designed for batch-mix or continuous-mix operations. The temperature range is from 175 to 325°F [79 to 163°C].

■ The Widefrac 600 (YF 600) system is water-based and is composed of a HPG gelling agentcrosslinked with a zirconate crosslinker. Fluids are designed for batch-mix or continuous-mixoperations. The temperature range for YF 600LT fluid is from 150 to 250°F [65 to 121°C] andfor YF 600HT fluid from 250 to 350°F [121 to 177°C].

■ The Widefrac 600UT (YF 600UT) system is water-based and is composed of a HPG gelling agentcrosslinked with a zirconate crosslinker. Fluids are designed for batch-mix or continuous-mixoperations. A YF 600UT fluid is prepared by adding HPG Polymer Slurry J856 to a fully hydratedWaterfrac 200 (WF 200) fluid. The temperature range is from 325 to 450°F [163 to 232°C].

■ The Widefrac 800 (YF 800LPH and YF 800HT) fluids are temperature activated, zirconatecrosslinked, water-based fluids composed of CMHPG. The YF 800 fluids consist of two fluiddesigns—YF 800LPH (pH 4.0 to 5.0) 100 to 250°F [38 to 121°C] and YF 800HT (pH 9 to 9.5)275 to 400°F [135 to 204°C].

■ PrimeFRAC water-based fluids are composed of CMHPG crosslinked with a zirconate crosslinkerto provide a low-polymer fluid. Fluids are designed for continuous-mix operations. Temperaturerange is from 200 to 350°F [93 to 177°C].

PropNET systemsThe PropNET system of proppant flowback control additives (PropNET I Additive J500, PropNET IIAdditive J501, PropNET Gold Additive J502 and PropNET HI K Additive J527) includes fibrousmaterials that are mixed with the proppant to hold it in the fracture during the production of oilor gas or both. PropNET additives work by a physical mechanism. A 3-dimensional fiber networkretains the proppant in place; no chemical curing reactions are necessary. Performance is not lim-ited by shut-in time, confining stress or bottomhole static temperature. This allows more flexibilityin flowback and production.

Applications■ Proppant flowback control in all reservoir conditions■ Oil or gas wells with proppant flowback problems■ Wells with reservoir temperatures from ambient to steamflood conditions

Benefits and features■ Eliminates proppant flowback while increasing production rates■ Allows postfracture flowback design changes, increasing operational flexibility■ Provides significantly increased pack strength when subjected to closure stress cycling as occurs

when wells are repeatedly shut in and returned to production■ Physical mechanism of proppant pack reinforcement for immediate flowback■ Increased permeability to base proppant at low closure stresses (<3000 psi)■ No chemical interactions with fluids or breakers■ Compatible with oil- and water-based fracturing fluids, including ClearFRAC polymer-free fluids■ Performance not limited by shut-in time, confining stress or bottomhole static temperature■ Compatible with common sand, ceramic and resin-coated proppants

68 Sand Control Pumping

SANDLOCK V systemsThe SANDLOCK* V system is based on a resin-coated-gravel-packing technique that utilizes apolymer, a resin system and gravel slurry. A strong and highly permeable consolidated gravel packis placed in the perforation tunnels and outside the casing to prevent the migration of formationsand into the wellbore. The following recommendations should be followed.

■ Interval lengths greater than 20 ft [6 m] are difficult to treat efficiently in a single-stage operation.■ Exposure to mud acid causes significant strength reduction.

Applications■ Formations initially completed without sand control, which began producing sand later in the

life of the well■ Consolidation of failed gravel packs or fracture packs (SANDLOCK V system without gravel)■ Single-stage treatments in layers less than 25 to 30 ft [7.6 to 9.1 m]■ Limited to less than 225°F [107°C]

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Figure 3-13. PropNET fibers are mixed with proppant which holds the proppant in place during production.

Figure 3-14. Engineered fiber technology, complemented by precise addition and job execution, helps provideconsistent control in all well conditions, improving your production and lowering your remedial costs.

Benefits and features■ Good compressive strength with high retained permeability■ Low resin content■ Short waiting-on-plastic (curing) times■ Ability to place SANDLOCK V materials using coiled tubing

Furan Resin Sand Consolidation systemThe Furan Resin Sand Consolidation system has been developed for in-situ consolidation of forma-tion sand. Treatment involves several stages including a Mud Acid treatment, a surfactant preflush,resin injection, displacement fluid and an acid catalyst overflush. Depending on bottomhole statictemperature, a shut-in time of 6 to 24 hr is required to allow the resin to cure. This bonded materialsubsequently helps prevent migration of other loose sand and fines from the formation into thewellbore. Because they penetrate into the formation, loose particles are immobilized away fromthe wellbore, beyond the point where fluid velocities cause particle movement.

Applications■ Formation sand consolidation in newly perforated wells■ In bottomhole static temperatures to more than 250°F [121°C]

Benefits and features■ Provides alternative screenless completion in unconsolidated formations ■ Imparts increased strength to the near-wellbore formation■ Reduces environmental hazards

70 Sand Control Pumping

Figure 3-15. As indicated in the graph above, the lower viscosity of the resin provides a good mobility ratio (>1) that maximizeszone coverage. A well treated with resin produces better than a well with conventional gravel pack because the perforationsremain open and the reservoir fluid does not have to flow through the gravel pack.

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