Section 4 _Fluid Systems

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Hydraulic FracturingSection 4 Fluid Systems

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4. Fluid Systems

The fracturing fluid is a vital part of the fracturing process. It is used to create the fracture, tocarry the proppant into the fracture, and to suspend the proppant until the fracture closes. On

a more basic level, the fluid system is the vehicle that allows us to transfer mechanical energy(in the frac pumps) into work performed on the formation.

In order to carry out these tasks efficiently, the ideal fluid must have a combination of thefollowing properties.

i) Low cost.ii) Ease of use.iii) Low tubing friction pressure.iv) High viscosity in the fracture, to suspend the proppant.v) Low viscosity after the treatment, to allow easy recovery.vi) Compatibility with the formation, the reservoir fluids and the proppant.vii) Safe to use.

viii) Environmentally friendly.

Some of these properties are not easy to combine in the same fluid. Usually, the process ofselecting a fracturing fluid is a trade off. It is up to the Engineers to decide which propertiesare most important and which properties can be sacrificed. In order to make this choiceeasier, there is a number of fluid systems available for fracturing.

4.1 Water-Based Lin ear System s

The first fracturing fluid, used in Kansas in 1947, was gasoline gelled with war surplusnapalm. Obviously this was a highly dangerous fluid, and it wasnt long before water basedsystems were available. The first of these systems used starch as the gelling agent, but by

the early 1960s guar was introduced and soon became the most common polymer forfracturing.

Before the dry polymer is added to the water, the individual molecules are tightly curled up onthemselves. As the polymer molecule hydrates in water, it straightens out which is whythese fluids are referred to as linear gels as illustrated in Figure 4.1a:-

Fig 4.1a Hydration of polymer gels in water. A shows a polymer molecule before hydration inwater, whilst B shows a polymer molecule after hydration in water.

It is these long, linear molecules that produce the increase in viscosity. However, it should be

remembered that this hydration will only occur at a specific pH range. Outside this range, thehydration rate can be very slow and almost non-existent. Different polymers have different pH

A B


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ranges, and buffers may have to be used to make the polymer hydrate. If a polymer thathydrates at a neutral pH is added to water, it may start to hydrate very rapidly. This leads tothe formation of clumps of non-hydrated polymer, surrounded by partially hydrated polymer,surrounded in turn by hydrated polymer. These are known as fish eyes and are a sign thatthe gel has been poorly mixed.

Several techniques can be employed to prevent the formation of fish eyes:-

i) Buffer the water so that the pH will prevent hydration. Once the polymer powder isthoroughly dispersed in the water, a different buffer is used to change the pH to apoint where the polymer will hydrate.

ii) Add the polymer through a high shear device (such as a jet mixer) to ensure that thepolymer does not form clumps.

iii) Circulate the hydrating gel through a high shear device, such as a choke, to break upany fish eyes.

iv) Slurry the polymer into a hydrocarbon-based fluid (such as diesel, kerosene or evenmethanol). The slurry is then added to the water, allowing the polymer to dispersebefore it hydrates.

Common polymers used for linear gels include:-

StarchGuarHydroxypropyl Guar (HPG)Carboxymethyl Hydroxypropyl Guar (CMHPG)CelluloseHydroxyethyl Cellulose (HEC)Carboxymethyl Hydroxyethyl Cellulose (CMHEC)XanthanXanthan derivatives (e.g. Bioxan

, Xanvis

, XC Polymer

etc)

The most commonly used polymers for fracturing are Guar, HPG and CMHPG, mostly as the

basis for crosslinked systems (see below). HEC is probably the most widely used polymer forlinear gel fracturing, due to its popularity for fracturing low temperature, high permeabilityformations.

BJs range of water-based linear gel frac fluids includes the Aqua Frac system, which isbased on guar and its derivatives. Gelling agents are GW-27 (guar), GW-32 (HPG) and GW-38 (CMHPG). Also in BJs product range is the Terra Pack system, which is primarilydesigned for gravel packing, but can also be used for fracturing. Gelling agent forTerra PackII is GW-21 (HEC) and forTerra Pack III is GW-22 (Xanthan).

4.2 Water-Based Crossl ink ed Systems

The vast majority of hydraulic fracturing treatments are carried out using water basedcrosslinked gels. These systems offer the best combination of low cost, ease of use, highviscosity and ease of fluid recovery. Generally, water based crosslinked gels will be usedunless there is a reason not use them they are the default option.

Crosslinked systems are produced by initially starting out with a linear gel, as describedabove. When used for crosslinked systems, linear gels are often referred to as base gels. Themost commonly used linear gels are guar and its derivatives, HPG and CMHPG.

A crosslinked gel, as illustrated in Figure 4.2a, consists of a number of hydrated polymermolecules, which have been joined together by the crosslinking chemical. This series ofchemical bonds between the polymer molecules greatly increases the viscosity of the system,

sometimes by as much as 100 times.


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In order for an efficient crosslink to occur, two separate things need to happen. First, the basegel needs to be buffered to a pH which will allow the crosslinking chemical work. Usually, thisis at a different pH to that required for polymer hydration, so a different pH buffer has to beused. Secondly, the crosslinking chemical needs to be present at sufficient concentration. Ifboth these conditions occur, the gel will experience a dramatic increase in viscosity.

Fig 4.2a A crosslinked polymer. A shows the hydrated polymer prior to addition of thecrosslinker. B shows the crosslink chemical bonds between the polymer molecules.

Obviously, a fully crosslinked polymer is extremely viscous, and can result in a high level offluid friction as it is pumped downhole. To counter this, it is quite common to used a delayedcrosslinker. A delayed crosslinker can take anything up to 10 minutes before the gel is fullyhydrated, depending upon the temperature, initial pH and shear that the fluid experiences.The ideal delay system, would delay the onset of crosslink as long as possible, but would stillhave the fluid fully crosslinked by the time it reaches the perforations.

The most commonly used crosslinking systems are as follows:-

BoratesExotic BoratesZirconatesAluminatesTitanates

Of these, the borates and exotic borates are by far the most commonly used, followed bythe zirconates. Figure 4.2b illustrates the pH ranges of these crosslinkers, whilst Figure 4.2cshows their temperature ranges:-

Fig 4.2b pH ranges for crosslinkers (SPE 37359)

A B

Zirconates

Aluminates

Organic Titanates

Borates

0 1 2 3 4 5 6 7 8 9 10 11 12


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Fig 4.2c Temperature range for crosslinkers (SPE 37359)

All crosslinked gels tend to be shear thinning, which means that the apparent viscosity of thefluid decreases with shear rate. This is because the shear acts to break the crosslink bondsbetween the hydrated polymer molecules. Borate crosslink bonds will reconnect and producea good quality gel after the shearing has taken place. However, zirconate bonds are muchmore shear sensitive and will not reconnect. Therefore, it is essential to consider the level ofshear that a fluid will experience when selecting a crosslinker.

Like most fracturing companies, BJ Services tends to classify its crosslinked fluids systems bythe type of crosslinker used:-

Viking is a guar-based system that uses conventional borates for the crosslink. It is a cheap,easy to use fluid intended for low temperature applications. There is no crosslink delay.

Crosslinkers used are XLW-4, XLW-32 or XLW-33.

Viking D is the delayed crosslink version of Viking, and uses the crosslinkers XLW-30 orXLW-31.

SpectraFrac G HT is probably the most commonly used of all BJs frac fluid systems. It isguar based, and uses an organo-borate crosslinker for a much greater temperature rangethan the Viking systems. The crosslinker also employs a self breaking mechanism, whichhelps to reduce the viscosity over a period of time above +/- 230

oF. The crosslinker can be

delayed, and the length of time for the delay can be varied over a significant range. Thecrosslinker for the system is XLW-56.

Medallion Frac is a CMHPG based system that uses a zirconate crosslinker. Unlike the

borate systems, which operate at a pH above +/- 9.0, Medallion Frac operates at a pH belowneutral, usually around 4.5 to 5.5. Because of its low pH, it is the fluid of choice for CO 2 foamfracs, pads for acid fracs, and for formations which are sensitive to high pHs. Crosslinker forthe system is XLW-60.

Medallion Frac HT is a high pH version of Medallion Frac. It uses a different buffer to achievethe required pH (usually around 8.0 to 9.0), but otherwise is the same as Medallion Frac. Thehigh pH zirconate system is more temperature stable than the low pH.

Vistar is a high pH, zirconate crosslinked system, designed so that only very low polymerloadings are needed, as compared to other fluid systems. The base gel is a guar-derivative(GW-45). Crosslinkers for the system are XLW-63 (lower temperatures) and XLW-14 (hightemperatures).

100 150 200 250 300 350 400

Zirconates

Aluminates

Titanates

High Temperature Borates

Conventional Borates

Temperature, oF


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Crosslinked systems are also characterized by the quantity of polymer used in the base gel.For instance, a 35 lb system has the base gel mixed with 55 lbs of polymer in every 1000gals of water. If this base gel were to be used in SpectraFrac, the fluid system would beknown as SpectraFrac G HT 3500.

LFC, XLFC and VSP

LFC (which stands for Liquid Frac Concentrate) is a slurried polymer system, designed tocarry 4 lbs of polymer in every gallon of slurry. The liquid base for the slurry is usually dieselor Lo-Tox oil. However, LFC systems have been developed that use vegetable oil as a baseliquid, although these hold less polymer per gallon. In addition to the base oil and polymer,LFC also contains suspending agents to prevent settling during storage, dispersants to helpmix the slurry and wetting agents to help the polymer hydrate quickly once the LFC is addedto water. A pH buffer can also be incorporated to help the polymer hydrate even quicker,especially at low temperatures.

LFC-1 contains guarLFC-2 contains HPGLFC-3 contains CMHPG

XLFC is the recently updated version of LFC. VSP (or Vistar Slurried Polymer) is a version ofLFC developed for the Vistarsystem.

4.3 Oil-Based System s

As stated previously, the very first hydraulic fracture treatment was carried out using gasolinegelled with war surplus napalm. The operation was performed on Pan American PetroleumsKlepper No 1 well, Grant county, Kansas, (part of the Hugoton gas field) in 1947. Thetreatment was aimed at 4 gas bearing limestone formations, at about 2500 ft. The gasoline-based fluid was selected, as it was perceived to be more compatible with the formation. This

continues to be the primary reason for selecting an oil-based fluid.

For the record, the treatment on Klepper No 1 failed to produce a significant productionincrease, and it was decided that the "Hydrafrac process would never compete successfullywith acidizing in this type of formation.

The first widely-used, oil-based fluid system, was based on the reaction of an acidic material(tallow fatty acid) and basic material (caustic) to form a polymeric salt, in a process similar tothe manufacture of soap. These fluids provided viscosity, but where very unstable at elevatedtemperatures. As time progressed, this system was replaced by others based on the use ofaluminium phosphates, which were able to provide significantly increased viscosity and morestability at elevated temperatures.

In the early 70s, the aluminium phosphate systems were replaced by the aluminium estersystems. The association of aluminium and phosphate esters is illustrated in Figure 4.3a:-

Fig 4.3a Aluminium phosphate association polymer

OO

H H

OO

R R

OO

R R

OO

H R

OO

H R

O

Al

P P

O O O

AlAl

OOOO

P P


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These systems used a combination of two products to produce the required viscosity. Therelative ratio of these two products was extremely critical so critical that it was difficult to mixthese systems on the fly. Consequently, a great deal of time and effort was spent in pre-gelling tanks full of hydrocarbons, resulting in considerable spillage and waste of chemicals.

More recently, BJ Services has developed a much more user-friendly system known as

Super Rheo Gel. The ratios of the various components of the system are nearly as critical, sothat the gel can now be mixed on the fly. The following products are used in Super RheoGel:-

GO-63 (gelling agent) and XLO-5 (activator) are the main components of the system. Theyare added in equal quantities, at different stages of the blending procedure, to produce therequired viscosity and stability.

NE-110 is a critical surfactant blend used in the continuous mix gelled oil system. Thismaterial aids in fluid recovery by acting as a hydrotropic material in the system. It helps toreduce emulsion tendencies of oils and also acts as a long-term breaker for the system.

GBO-5L and GBO-6 are the breakers for the system.

Most gelled oil systems can be prepared with a wide variety of hydrocarbon based fluids,including diesel, kerosene, frac oil, condensate and many lease crudes. Because the fluidused to fracture the well is itself hydrocarbon based, the well can be put straight on toproduction after the treatment is over. This makes the fluid recovery phase of the operationsmuch easier.

When mixing with lease crude or condensate, obtain fresh samples of the hydrocarbon andtest to make sure that the system performs as required. Be aware that BJ Services has strictSafety and Operations standards for the use of hydrocarbon based fluids, and for thehandling of low-flashpoint liquids. These standards can be found in BJs Standard PracticesManualand BJs Corporate Safety Standards and Procedures Manual.

4.4 Emulsions

In general, emulsions are only rarely used in fracturing operations, but in some parts of theworld they have been found to have an ideal combination of fluid loss characteristics,formation compatibility and downhole viscosity. As a result, in these areas their use iscommon.

Most of these systems are oil-in-water emulsions and operate in a similar fashion. Water isgelled with a standard gelling agent and held in a tank(s). During the job, water and oil aremixed together at the ratio of 2 parts oil to one part gel. An emulsifier is either pre-blended inthe water phase (the gel) or added on the fly. The fluids very quickly form a brown emulsion,

the viscosity of which is largely proportional to the initial viscosity of the water phase.

Some systems require an external breaker in order to destroy the emulsion and allow thefluids to be recovered. However, in most systems, the emulsion quickly falls apart afterexposure to the formation.

BJ Services emulsion-based fluid system is known as Polyemulsion, for which theemulsifying agent is E-2.

4.5 Energized Fractur ing Fluids

Energized fluids consist of a liquid phase usually a water-based linear or crosslinked gel

and a gaseous phase, which is typically N2, CO2 or a combination of these. Such treatmentsinvolve large amounts of equipment and personnel. Consequently, they are relatively


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expensive. These treatments are also referred to a foam fracs, as foam is generally what isarriving at the formation. Because of the safety implications of working with both cryogenicfluids and energized fluids, the procedures detailed in BJs Standard Practices Manual andBJs Corporate Safety Standards and Procedures Manual, should be closely followed at alltimes.

Foamed fluids have several unique properties which make them advantageous under certaincircumstances:-

i) Viscosity and proppant transport. Stable foams have a comparatively high viscosityand make excellent fluids for carrying and suspending proppant.

ii) Foams have very good leakoff properties.iii) Because foams are typically only 30 to 40% liquid, they are more compatible with

water sensitive formations than frac systems which are 100% liquid.iv) The extra energy stored in the fluid, coupled with the low hydrostatic head of the

foam, makes fluid recovery relatively easy.

Foam Quality

The foam quality, often expressed as a percentage or just simply as a quality (i.e. 70 qualityor even 70Q) is the percentage of foam or energized fluid that is gas, at the anticipatedbottom hole conditions. In order to design a foam treatment, an Engineer must have areasonable idea of the expected bottom hole treating pressure and temperature, as thevolume occupied by the gas phase will vary depending on both of these (although thetemperature is much less significant than the pressure). As illustrated by Figure 4.5a, foamviscosity (and hence its ability to transport proppant) is heavily influenced by the quality. If thebottom hole pressure is significantly less than anticipated, the foam quality will be too high,and the gas phase will expand to make a mist, rather than a foam.

Fig 4.5a Proppant Transport as a function of foam quality. This graph is a combination of thework performed by several individuals and organisations. It is intended as a qualitative

illustration of the effect foam quality has on the ability of the fracturing foam to transport andsuspend proppant.

Proppant Concentration

Because proppant is added to the liquid phase of the foamed frac fluid, there is a limit to theoverall proppant concentration that can be achieved downhole. Because it is not possible to

blend and pump proppant at more than 18 or 19 ppg in the liquid phase, by the time the liquidphase has been mixed with the gaseous phase, the overall proppant concentration has beenreduced to 7 or 8 ppg. For this reason, it is not possible to place the very high proppant

0 20 40 60 80 100

STABLE

FOAM

Foam Quality

ProppantTransport


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concentrations required for fracturing high permeability formations. This means that foamfracturing is limited to medium and low permeability reservoirs, for skin bypass fracturing(although the extra cost can defeat the low cost objectives of this type of treatment) and forcoal bed methane fracturing.

Constant Internal Phase vs Constant External Phase

Foams can be thought of as being a multi-phase fluid, with a gas-internal phase, and a liquidexternal phase. The difficulty comes in deciding whether or not the proppant is part of internalphase or the external phase.

The traditional method of modelling foams and designing treatment schedules uses theconstant external phase method. This assumes that the proppant is part of the externalphase. It is easier to operate on location, as both the slurry rate and the gas rate remainconstant. However, under constant external phase, the actual fraction of the foam that isliquid can be severely reduced as higher proppant concentrations are reached. Obviously, theproppant has no properties that act to hold the foam together, so foams can become veryunstable as the proppant concentration increases.

The modern way of modelling foam is to use the constant internal phase method. This modelsthe proppant as being part of the gas phase. Therefore, in order to keep foam qualityconstant, the gas rate has to go down as the proppant concentration rises, and then increaserapidly as the treatment goes to flush. This method is harder operationally, but provides amuch more stable foam.

Foam Stability

The stability of a foam, is its ability to remain as a foam, rather than separating out into two oreven three phases. Ideally, the fluid should remain as a foam long enough for the fluid to berecovered as a foam after the treatment. Obviously, temperature and fluid contamination willact to reduce foam stability. There are three main methods for maximising foam stability:-

i) Mixing the liquid and gas phases at high shear, such as with a foam generator, or bypassing the mixed phases through a high shear device, such as a choke. The greaterthe shear that the foam experiences, the more stable it becomes. High shear acts toreduce the average size of the gas bubbles, which in turn makes it harder for then toseparate out.

ii) Crosslinking the fracturing fluid after the foam has been formed. By using a delayedcrosslinker, the onset of crosslink can be timed to take place after the foam has beengenerated, so that the gas bubbles are literally crosslinked into position.

iii) Foaming agents. These surfactants act to increase the surface tension of a material,so that the gas bubbles are much more stable.

Often a combination of these methods is used.

Foam Viscosity

The viscosity, proppant transport characteristics, fluid leakoff and stability of the foam are allinfluenced by the same foam characteristics:- the liquid phase viscosity, the average gasbubble size, the foam quality and the surface tension properties of the liquid phase. All ofthese are affected by temperature and two of these are significantly affected by pressure.This means that calculating the viscosity and hence the friction pressure and fluid leakoff of the foam is very difficult.

Consequently, calculated bottom hole treating pressures for foam fracs are extremelyunreliable and should not be used for analysis unless there is absolutely no alternative

whatsoever. The results from such an analysis should be considered as educated guessworkonly.


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N2 Foam Fracs

N2 foamed fracs are the most straightforward of all the types of energized fluid fracsperformed. Nitrogen is stored as a cryogenic liquid, in specialised, highly insulated, tanks onlocation. Prior to the treatments, each tank uses a heat exchanger to vapourise a smallamount of the liquid into gas. This has the effect of pressuring up the tank, so that liquid

nitrogen is forced from the tank to the N2 pumpers.

Before liquid N2 can be pumped, the pump itself has to be cooled down. This is done byflowing liquid N2 though the pump and out of a vent. Initially gas will bleed out if the vent.Eventually, as the unit cools down, liquid will be seen coming out of then vent, and this showsthe operator that the unit is now ready to pump. Therefore, when designing N2 foam fracs,sufficient liquid nitrogen should be on location for cooling the N2 pumpers down at least 3times (once for the minifrac, once for the main treatment and one spare).

It is much easier to convert a liquid from low to high pressure, than it is to convert a gas fromlow to high pressure. Consequently, the specialised N2 pumpers will be working on a fluidwhich is stored and pumped at around 320

oF. This means that specialised equipment is

required for pumping this cryogenic liquid. These pumpers also include a vapouriser, whichwill heat the high pressure liquid and convert it into a gas (for this reason, N 2 pumpers areoften referred to as converters). These vapourisers can be diesel fired or run from theengine coolant.

As N2 is chemically inert, there are no limitations on the fluid systems it can be used with.

CO2 Foam Fracs

CO2 has a number of properties that make its use significantly different from N2. To start with,liquid CO2 is stored at 20

oF. This much higher temperature means that the liquid can be

pumped with a standard frac pumper (provided they have been specially prepared see BJsStandard Practices Manual). It also means that the liquid CO2 does not have to be converted

into a gas before it is mixed with the liquid phase this will happen automatically as the CO 2heats up.

The second major property difference of CO2, is its tendency to form a solid (dry ice) ifstored or pumped under the wrong conditions. Obviously, this must be avoided. Dry ice willonly form at pressures below +/- 80 psi. So at every stage, the liquid CO 2 is kept well abovethis pressure. Typically, CO2 is stared at between 150 to 300 psi. There are several differentmethods for pumping the liquid CO2 from the tanks to the pumpers. One method involvesforcing it out with N2 pressure applied above the fluid level in the CO2 tank. Another methodemploys specialised boost pumps. Yet another methods employs a combination of these twosystems. Once again, BJs Standard Practices Manualshould be consulted before designingany treatments.

The third major difference is that unlike N2, CO2 is not chemically inert. Specifically, oncontact with water based fluids, some of the CO2 will dissolve into the water to form an acid.This has the effect of lowering the pH of the system. This means that CO 2 is not compatiblewith high pH fracturing fluids, such as borate crosslinked gels.

Binary Fracs

Binary Fracs involve the use of a mixture of both CO 2 and N2 to provide the foam. They wereoriginally developed as a method of getting around one service companys patent on CO 2foam fracturing. Since then, the method has been extensively developed and is now thepreferred method of foam fracturing for many operating companies.

Binary fracs are the most complicated stimulation operations performed, requiring the use ofno less than three service supervisors (one for the CO2, one for the N2 and one for the liquidphase, who is in overall control). Consequently, these are relatively uncommon.


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Poly CO2

Poly CO2 is a highly specialised fluid developed by Nowsco in Canada. In this fluid, aspecialised additive is mixed into the water-based liquid phase, which causes the water-based gel and the liquid CO2 to form an emulsion, rather than foam. The emulsion is notparticularly stable, and will break down after the fluid contacts the formation.

This fluid system has only ever been used in low temperature applications, and it is unclearas to whether the stimulation benefits come from the placing of proppant, or from the thermalshock experienced by the formation. However, in certain formations it has proved to be highlysuccessful.

4.6 Addit ives

There are an enormous number of additives used in the preparation of the various types offracturing fluids, and an exhaustive list is beyond the scope of this manual. However, below isa description of the general types of additive, together with the most commonly used

examples from BJs product range.

Gelling Agents

Water-based gelling agents are designed to increase the viscosity of water. This water canbe fresh (rarely), 2% KCl, 3% NH4Cl, sea water or any of a myriad of different kinds of brines.Nearly all gelling agents are some kind of polymer. A wide range is available, depending uponhydration pH, temperature stability and polymer residue:-

Guar GW-4, -27Hydroxypropyl Guar (HPG) GW-32Carboxymethyl Hydroxypropyl Guar (CMHPG) GW-38Guar derivative forVistar GW-45Hydroxyethyl Cellulose (HEC) GW-21, -24L, AG-21RCarboxymethyl Hydroxyethyl Cellulose (CMHEC) GW-28Xanthan GW-22, -22L, -37Polysaccharide GW-23

Oil-based gelling agents are designed to increase the viscosity of oil-based fluids. Thesegelling agents work on a wide variety of hydrocarbons, but are primarily designed for dieseland kerosene. Any other hydrocarbon fluid should be tested prior to application.

GO-63, -63 HTGO-64 Gelling agent forSuper Rheo GelGM-55 Gelling agent forMetho Frac XL (methanol-based frac fluid)

Crosslinkers and Complexers

Crosslinkers and complexers are designed to dramatically increase the viscosity of an alreadygelled fluid, so that high viscosity can be maintained for extended periods of time at higtemperatures. For many fluid systems, the crosslinker is the chemical that really defines itscharacteristics.

XLW-4, -32, -33 Crosslinkers forVikingXLW-30, -31 Crosslinkers forViking DXLW-14, -63 Crosslinkers forVistarXLW-56 Crosslinker forSpectraFrac HTXLW-60 Crosslinker forMedallion Frac and Medallion Frac HT

XLW-41B Crosslinker forMetho Frac XLXLO-5 Complexer forSuper Rheo Gel


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Breakers

Breakers are designed to reduce the viscosity of the fracturing fluid to a minimum, so that thefluid can be easily recovered after the treatment. They are also designed to minimise polymerresidues, so that damage to the proppant pack is minimised.

GBW-5, -7, Oxidizing breakersGBW-23, -24 Delayed oxidizersGBW-10, -12CD, -13 Enzyme breakers for cellulose + derivatives

-26DGBW-12 Enzyme breaker for guar + derivativesGBW-14C Enzyme breaker for xanthan + derivativesUltraperm CRB Encapsulated oxidizing breakerHigh Perm CRB Encapsulated oxidizing breakerGBO-5L, -6 Breakers forSuper Rheo Gel

Buffers

Buffers are designed to either raise the pH or lower the pH, as required.

Low pH buffers BF-1, -10LEHigh pH buffers BF-7, 7L, -8, -9L, caustic soda

Surfactants

The word Surfactant comes from the phrase SURFace ACTive AgeNT, and includes anychemical that affects the interface properties between materials. Because this covers such awide range of materials, it is necessary to discuss this group of products in more detail,below. Surfactants can also be grouped according to the type of charge they possess, so thatsome surfactants are anionic, some are cationic, some are amphoteric and some are non-ionic. Generally speaking, it is best not to mix anionic and cationic products together, as theymight form in viscous deposits. Details of this can be found in BJs Mixing Manual.

Most of BJs surfactant products are designed to leave the formation water wet. This meansthat the relative permeability of the formation to water has been lowered, and the relativepermeability of the formation to oil has been raised.

Non-emulsifying surfactants are designed to prevent the formation of emulsions betweenthe crude oil in the formation and the treatment fluid. All water-based treatments should havea non-emulsifying surfactant added to them, unless they are being pumped into a waterinjection well or dry gas reservoir with no trace of condensate.

Inflo 100 Blend of cationic and nonionic

NE-13 Blend of cationic and nonionicNE-110 AnionicNE-118 NonionicNE-940 Nonionic

Note that some non-emulsifiers will also act to break existing emulsions.

Foaming agents work by increasing the surface tension of the fluid. This helps increase foamstability. Most foaming agents also acts as detergents and dispersants

FAW-18W AnionicFAW-20 AnionicFAW-21 Amphoteric

FAO-25 Nonionic foaming agent for oil-based fluids

Note that both FAW-18W and FAW-20 will leave carbonate formations oil wet.


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Low surface tension modifiers act to reduce the surface tension of the fluid. This helps thefluid penetrate into very small places, such as the pore spaces in low permeability reservoirs.These products also help the treatment fluid flow back out of the well after the treatment isfinished.

Flo-Back-20, -30 NonionicInflo-100 Blend of cationic and nonionicInflo-150 Nonionic

Mutual solvents will dissolve hydrocarbon based deposits and allow them to disperse waterbased fluids.

US-2, -40 Nonionic

Emulsifiers are used to deliberately create emulsions. They only should be used as part ofan emulsion-based fluid system

AE-7 Cationic

E-2 Cationic

Biocides

Biocides, also known as Bactericides, are designed to kill bacteria. Any bacteria especiallysulphate reducing bacteria will eat the polymer used in frac fluids. A colony of bacteria canreduce a tank of good quality gel into foul-smelling slick water in less than an hour. Biocidesare used to prevent this. Initially, all tanks used for frac fluids should be as clean as possible.This will help reduce the risk of bacterial contamination. However, the water used to mix thegel can still contain these bacteria, especially if the climate is hot or sea water is being used.The biocide should be added either directly to the tank before the water is added, or it shouldbe thoroughly mixed into the water prior to the addition of any polymer. Once the biocide hasbeen added, it will quickly kill any bacteria that are present in the water.

It is recommended that a biocide is used on any treatment with involves pre-gelling the fluid.

It should be remembered that biocides are designed to prevent a colony of bacteria fromdeveloping in the first place, rather than for killing an existing colony - any gel that issuspected of being contaminated should be discarded, and its tank thoroughly cleaned. Itshould also be noted that in their concentrated form, biocides are very dangerous materials(after all, they are designed for killing living things) and should be handled with extreme care.

XCide 102, 207

Gel Stabilisers

Gel stabilisers are used to prolong the viscosity of crosslinked gels at high temperatures. theywork by one of two methods:- the scavenge the oxygen in the fluid; or they chelate cationswhich can contribute to the degridation of the gel.

GS-1, -1L, -2, -6, -9

Clay Control Additives

Clay control additives are used to prevent the swelling, migration and disintegration of clayminerals such as illite, smectite, chlorite and montmorillonite. Fresh water by itself will causethese problems. The addition of chloride ions to fresh water will prevent these problems in

most formations, so that most treatments carried out with sea water do not need anyadditional clay stabilisers. However, exceptionally water sensitive formations may needadditional protection, which is where BJs range of synthetic clay control additives is applied.


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KCl, NH4Cl, NaCl etc standard salts for brinesCaBr2, ZnBr2, etc specialised salts for high density completion

brines (some of these may be incompatiblewith BJs crosslinked fluids).

Clay Treat 3C KCl substitute, recommended forVistar.

ClatrolClaymaster 5C, FSP

Note that any salts containing calcium or magnesium should not be mixed with frac fluids, asthese are incompatible with some crosslinkers.

Fluid Loss Control

Fluid loss control additives can be used for two main reasons:- first, to lower a very highmatrix leak off rate; and secondly, to prevent fluid loss down natural fractures. The use of fluidloss additives is becoming less and less common, as the understanding of fluid leakoffincreases. Most Engineers also believe that pumping more fluid is preferable to usingadditives that can potentially produce permanent damage.

Silica flour, 100 mesh sand Used for blocking natural fractures5% dieselFLC-42Adomite Aqua

Adomite Regain

References

BJ Services Mixing Manual

BJ Services Stimulation Engineering Support Manual

BJ Services Products and Services Manual

BJ Services Product Bulletins

BJ Services Standard Practices Manual

BJ Services Corporate Safety Standards and Procedures Manual

Rae, P., and Di Lullo, G.: Fracturing Fluids and Breaker Systems A Review of State-of-the-Art, paper SPE 37359, presented at the SPE Eastern Regional Meeting, Colombus OH, Oct1996.

Brannon, H.D., and Ault, M.C.: New, Delayed Borate-Crosslinked Fluid Provides ImprovedConductivity in High Temperature Applications, paper SPE 22838, presented at the SPEAnnual Technical Conference and Exhibition, Dallas TX, Oct 1991.

Cramer, D.D., Dawson, J., and Ouabdesselam, M.: An Improved Gelled Oil System for HighTemperature Fracturing Applications, paper SPE 21859, presented at the Rocky MountainRegional Meeting and Low-Permeability Reservoirs Symposium, Denver CO, Apr 1991.

Blauer, R.E., and Kohlhaas, C.A.: Formation Fracturing with Foam, paper SPE 5003,presented at the 49

thAnnual Fall Meeting of the SPE, Houston TX, Oct 1974.


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Grundman, S.R., and Lord, D.L.: Foam Stimulation, paper SPE 9754, JPTpp 597 602,Mar 1983

Valk, P., and Economides, M.J.: Foam Proppant Transport, paper SPE 27897, presentedat the SPE Western Regional Meeting, Long Beach CA, Mar 1994.

Tjon-Joe-Pin, R, DeVine, C.S., and Carr, M.: Cost Effective Method for ImprovingPermeability in Damaged Wells, paper SPE 39784, presented at the SPE Permian Basin Oiland Gas Recovery Conference, Mar 1998.

Section 4 _Fluid Systems

Documents

Transcript of Section 4 _Fluid Systems