A composition containing PAC and a synthetic sulfonate polymer has been tested for fluid loss reduction and thermal stabilization of a water-based drilling fluid for extended periods at deep well drilling temperatures (Hen 1991).

Improved fluid loss is obtained when PAC and the sulfonate-containing polymer, which has a molecular weight of 300–10,000 kDalton, are combined in a (WBM), after prolonged aging at 300∘F (150∘C).

Certain admixtures of carboxymethyl hydroxyethyl cellulose or copolymers and copolymer salts of N,N -dimethylacrylamide and 2-acrylamido-2-methyl-1-propane sulfonic acid (AMPS), together with a copolymer of acrylic acid (AA), may provide fluid loss control to cement compositions under elevated temperature conditions.

Hydroxyethyl cellulose (HEC) with a degree of substitution of 1.1–1.6 has been tested for fluid loss control in water-based drilling fluids (Raines 1986). An apparent viscosity in water of at least 15 cP is needed to achieve an API fluid loss of less than 50 ml/30 min. Crosslinked HEC is suitable for high-permeability formations (Chang et al. 1998; Chang and Parlar 1999).

A derivatized HEC polymer gel exhibited excellent fluid loss control over a wide range of conditions in most common completion fluids. This particular grated gel was compatible with the formation material, and caused little or no damage to its original permeability (Nguyen et al. 1996).

Detailed measurements of fluid loss, injection, and regained permeability were taken to determine the polymer particulate's effectiveness in controlling fluid loss and to assess its ease of removal. HEC can be etherified or esterified with long chain alcohols or esters. An ether bond is more stable in aqueous solution than is an ester bond (Audibert et al. 1997).

A crosslinked starch was described as a fluid loss additive for drilling fluids (Francis et al. 1987; Sifferman et al. 1999). The additive resists degradation and functions satisfactorily after exposure to temperatures of 250∘F (120∘C) for periods of up to 32 hours. To obtain crosslinked starch, a crosslinking agent is reacted with granular starch in an aqueous slurry. The crosslinking reaction is controlled by a Brabender viscometer test. Typical crosslinked starches are obtained when the initial rise of the viscosity of the product is between 104∘C and 144∘C, and the viscosity of the product does not rise above 200 Brabender units at temperatures less than 130∘C.

The crosslinked starch slurry is then drum-dried and milled to obtain a dry product. The effectiveness of the product is checked by the API Fluid Loss Test or other standards after static aging of sample drilling fluids containing the starch at elevated temperatures. The milled dry product can then be incorporated into the oil well drilling fluid of the drill site (Recommended practice for laboratory testing of drilling fluids (API) 2009; Standard test method for fluid loss of clay component of geosynthetic clay liners 2009).

The properties of the filter cake formed by macroscopic particles can be significantly influenced by certain organic additives. The overall mechanism of water-soluble fluid loss additives has been studied by determining the electrophoretic mobility of filter cake fines. Water-soluble fluid loss additives are divided into four types according to their different effects on the negative electrical charge density of filter cake fines (Zhang et al. 1995):

The properties of filtrate reducers are governed by their different molecular structures. Non-ionic filtrate reducers work by completely blocking the filter cake pore, and anionic ones work by increasing the negative charge density of filter cakes and decreasing pore size. Anionic species cause further clay dispersion, but non-ionic species do not, and both of them are beneficial to colloid stability (Zhang et al. 1996).

The change of properties of the filter cake that occured as a result of salinity and polymeric additives has been studied by scanning electron microscope (SEM) photography (Plank and Gossen 1989). Fresh water muds with and without polymers such as starch, PAC, and a synthetic, high-temperature-stable polymer, were prepared, contaminated with electrolytes (NaCl, CaCl₂, MgCl₂), and aged at 200–350∘F (90–189∘C).

Static API filtrates before and after contamination and aging were measured. The freeze-dried API filter cakes were used for SEM studies. The filter cake structure was influenced by electrolytes, temperature, and polymers.

In an unaged, uncontaminated mud, bentonite forms a card-house structure with low porosity. Electrolyte addition increases the average filter cake pore size. Temperature causes coagulation and dehydration of clay platelets. Polymers protect bentonite from such negative effects.

A fluid loss additive consisting of granular starch composition and fine particulate mica has been described (Cawiezel et al. 1996). It has been applied in a method for fracturing a subterranean formation penetrated by a borehole. The method comprises injecting the additive into the borehole and into contact with the formation, at a rate and pressure sufficient to fracture the formation, in an amount sufficient to provide fluid loss control.

Partially depolymerized starch provides decreased fluid losses at much lower viscosities than the corresponding starch derivatives that have not been partially depolymerized (Dobson and Mondshine 1997).

A fluid loss additive for a fracturing fluid comprises a mixture of natural and modified starches plus an enzyme (Williamson et al. 1991b). The enzyme degrades the α-linkage of starch but does not degrade the β-linkage of guar and modified guar gums when used as a thickener.

Natural or modified starches are utilized in a preferred ratio of 3:7 to 7:3, with optimum at 1:1, and the mix is used in the dry form for application from the surface down the well. The preferred modified starches are carboxymethyl and hydroxypropyl derivatives. Natural starches may be those of corn, potatoes, wheat, or soy, with cornstarch the most preferred.

Blends include two or more modified starches, as well as blends of natural and modified starches. The starches can be coated with a surfactant, such as sorbitan monooleate, ethoxylated butanol, or ethoxylated nonyl phenol, which act to aid dispersion into the fracturing fluid.

A fluid loss additive is described (Williamson et al. 1991a) that helps achieve a desired fracture geometry by lowering the spurt loss and leak-off rate of the fracturing fluid into the surrounding formation by rapidly forming a filter cake with low permeability. The fluid loss additive is readily degraded after the completion of the fracturing process. The additive has a broad particulate size distribution that is ideal for use in effectively treating a wide range of formation porosities and is easily dispersed in the fracturing fluid.

This fluid loss additive comprises a blend of modified starches or blends of one or more modified starches and one or more natural starches. They have been found to maintain injected fluid within the created fracture more effectively than natural starches. The additive is subject to controlled degradation into soluble products by a naturally proceeding oxidation reaction, or by bacterial attack by bacteria that are naturally present in the formation. The oxidation may be accelerated by adding oxidizing agents, such as persulfates and peroxides.

A polymeric material with a multimodal distribution refers to a material that contains at least two pluralities of polymer molecules, which have different average molecular weights.

Polymeric materials that are found in nature are generally monomodal with a rather narrow polydispersity (P) (Weaver et al. 2010). The polydispersity is in general defined as the ratio of two different averages of molecular weight, i.e., the ratio of weight average M_w to the number average, M_n. These averages are defined as:

where x_M is the mole fraction of polymer with a molecular weight of M and w_M is the weight fraction of polymer with a molecular weight of M.

Thus the polydispersity is:

Polydisperse materials can be obtained by mixing chemically equivalent materials that have different molecular weights. The latter can be obtained by synthesis of artificial materials under different conditions, or by controlled degradation of naturally occurring polymers.

Polymeric materials with small polydispersities may not be able to fill the pore spaces sufficiently to prevent fluid loss into the formation. For example, if the polymer molecules are all relatively large, all of them may be unable to fit within certain pore throats in the formation to plug the pore spaces therein.

On the other hand, polymers with a multimodal distribution contain a number of molecules that will fill and plug small pores, a number of molecules that will plug medium-sized pores, etc. The principle developed above is suitable for polymers as fluid loss additives in general, i.e., it is independent of the particular chemical nature of the polymer.

A wide variety of examples of polymers have been listed that operate according to this principle. Natural polymers include polysaccharides, while synthetic polymers include 2,2′-azobis(2,4-dimethyl valeronitril) (Weaver et al. 2010,pp. 5–15).

Hydroxypropyl guar gum gel can be crosslinked with borates (Miller et al. 1996), titanates, or zirconates. Borate crosslinked fluids and linear HEC gels are the most commonly used fluids for highworddash permeability fracture treatments. They are used for hydraulic fracturing fluid under high temperature and high shear stress.

In hydraulic cement slurries, fluid loss additives that are based on sulfonated or sulfomethylated lignins have been described.

Sulfonated or sulfomethylated lignins are reacted with phenolworddash blocking reagents, such as ethylene oxide, propylene oxide, or 1,2-butylene oxide (Schilling 1990). The fluid loss and thickening time characteristics of the cement slurry so produced is altered, either by increasing the molecular weight of the lignin through crosslinking with formaldehyde or epichlorohydrin, or by adding agents such as sodium sulfite, sodium metasilicate, sodium phosphate, and sodium naphthalene sulfonate.

Another method of altering lignins is amination with a polyamine and an aldehyde (Schilling 1991). The formulation also contains sodium carbonate, sodium phosphate, sodium sulfite, sodium metasilicate, or naphthalene sulfonate. The sulfonated or sulfomethylated aminated lignin shows less retardation (shorter thickening time) than a sulfonated or sulfomethylated lignin without the attached amine.

Lignite can be grafted with synthetic comonomers to obtain lignite fluid loss additives (Huddleston and Williamson 1990). The comonomers can be AMPS, N,N -dimethylacrylamide, acrylamide (AAm), vinylpyrrolidone, vinylacetate, acrylonitrile, dimethyl amino ethyl methacrylate, styrene sulfonate, vinylsulfonate, dimethyl amino ethyl methacrylate methyl chloride quaternary, or AA and its salts.

Various polymers, for example, lignin, lignite, derivatized cellulose polyvinyl alcohol (PVA), polyethylene oxide, polypropylene oxide, and polyethyleneimine, can be used as the backbone polymer onto which the other groups are grafted (Fry et al. 1987). The grafted pendant groups can be AMPS, acrylonitrile, N,N -dimethylacrylamide, AA, N,N -dialkylaminoethylmethacrylate, and their salts. One commercial example of such compounds is HALAD™ 413 (Lewis et al. 2008; Morgan et al. 2008).

A polymeric composition for reducing fluid loss in drilling muds and well cement compositions is obtained by the free radical polymerization of a water-soluble vinyl monomer in an aqueous suspension of lignin, modified lignins, lignite, and brown coal (Giddings and Williamson 1987; Williamson 1989). The vinyl monomers can be methacrylic acid, methacrylamide, hydroxyethyl acrylate, hydroxypropyl acrylate, vinylacetate, methylvinylether, ethylvinylether, N -methylmethacrylamide, N,N -dimethylmethacrylamide, vinylsulfonate, and additional AMPS. In this process, a grafting process to the coals by chain transfer may occur. Vinyl ethers are shown in Figure 2.5 and some acrylics are shown in Figure 2.6.

The polymers are prepared by common polymerization techniques (Zhang et al. 1990). For example, they are made by providing a foamed, aqueous solution of water-soluble monomeric material, in which polymerization is started by adding an initiator. The monomeric material is exothermically polymerizing to form a foamed gel, which is then comminuted.

Preferably, the polymerization temperature is held below 60∘C for at least the first 10 min of the reaction and it then rises due to its exothermic nature. Graft copolymers that can be made by this technique and that are of particular value as fluid loss additives are formed from a polyhydroxy polymer, a sulfonate monomer, further AAm and AA.

Vinyl-grafted wattle tannin comprises a wattle tannin grafted with AMPS and small amounts of AAm (Huddleston et al. 1992). The wattle tannin is present at levels of 2–14%, and the AMPS is present at 98–84% accordingly.

Lignites that originated from Greece have been tested for their ability to control the filtration characteristics of water-bentonite suspensions (Kelessidis et al., 2009 and Kelessidis et al., 2007). The properties of a series of lignite samples from various peat/lignite deposits in Greece were compared with a commercial lignite product.

The samples were characterized with respect to their contents of humic and fulvic acids, humins, oxygen, ash, and their cation exchange capacity.

Most samples show a good filtration control when used in water-bentonite suspensions, even after exposure to temperatures of 177∘C, and some were found to be superior to the commercial product. The fluid loss was dependent on the humic and fulvic acid content and thus also on the total organic content of the samples. The correlation is shown in Figure 2.7.

An improvement index η, has been used, which is defined as follows:

Here, V_a is the volume of fluid loss after aging and V_b is the fluid loss of the base fluid under standardized conditions.

Better performance was observed after addition of 3% w/v lignite. Total humic and fulvic acids as percentage of dry lignite matter and the organic matter as lignite percentage showed a weak inverse correlation with the fluid loss volumes.

The rheograms of bentonite suspensions in its hydrated and thermally aged states has been measured. Three percent lignite of varying origin has been added to the aged suspensions. The resulting rheograms are given in Figure 2.8.

The addition of lignite reduces the shear stress. In the high shear rate range, the rheograms exhibit a linear behavior (Kelessidis et al., 2009). The reduction in the shear stress is very similar for all the lignite types tested.

A water-soluble polymer of monoallylamine, c.f., Figure 2.9, can be used in conjunction with a sulfonated polymer such as a water-soluble lignosulfonate, condensed naphthalene sulfonate, or sulfonated vinyl aromatic polymer to minimize fluid loss from the slurry during well cementing operations (Roark et al., 1986 and Roark et al., 1987). The polymer may be a homopolymer or a copolymer, and may be crosslinked or not.

These components react with each other in the presence of water to produce a gelatinous material that tends to plug porous zones and to minimize premature water loss from the cement slurry into the formation.

Organophilic polyphenolic materials for OBMs have been described (Cowan et al. 1988). The additives are prepared from a polyphenolic material and one or more phosphatides, these being phosphoglycerides obtained from vegetable oils, preferably commercial lecithin.

The oxidized, sulfonated, or sulfomethylated derivatives of humic acids, lignosulfonic acid, lignins, phenolic condensates, or tannins may serve as polyphenolic materials.

A fluid loss additive is described that uses graded calcium carbonate particle sizes and a modified lignosulfonate (Johnson and Smejkal 1993). Optionally, a thixotropic polymer, such as a wellan or xanthan gum polymer is used to keep the CaCO₃ and lignosulfonate in suspension.

In this application, it is important that the calcium carbonate particles are distributed across a wide size range to prevent filtration or fluid loss into the formation. Furthermore, the lignosulfonate must be polymerized enough to reduce its water solubility. The modified lignosulfonate is necessary for the formation of a filter cake essentially on the surface of the wellbore.

Because the modified lignosulfonate, prevents the filter cake particles from invading the wellbore no high-pressure spike occurs during the removal of the filter cake, which would indicate damage of the formation and wellbore surface. The additive is useful in fracturing fluids, completion fluids, and workover fluids.

Tests have shown that a fluid loss additive based on a sulfonated tannic-phenolic resin is effective for fluid loss control at high temperatures and pressures, and it exhibits good resistance to salt and acid (Huang 1996).

Latex emulsions that are prepared by conventional emulsion polymerization become unstable in the presence of salt. In order to improve the salt tolerance of latex emulsions in sealant compositions, it is usual to add surfactants, such as ethoxylated nonyl phenol sulfates. Alternatively, a cheaper solution is to use a colloidally stabilized latex, which contains a protective colloid. Suitable examples include partially and fully hydrolyzed PVA, cellulose ethers, starch derivatives, natural and synthetic gums, and synthetic copolymers (Reddy and Palmer 2009).

As another alternative, the backbone of the latex may be modified by incorporating moieties with surfactants properties. Since the surfactant is then chemically bound to the polymer, it cannot be easily removed. An example of such a material is a carboxylated butadiene acrylonitrile latex. The carboxyl groups confer electrical charge to the polymeric backbone.

Alternatively, functionalized silane can be introduced into the polymer. This moiety is capable of adsorbing the protective colloid. A suitable functionalized silane is γ-mercaptopropylspacetrimethoxyspacesilane.

It has been demonstrated that a carboxyl modified latex can produce slurries with satisfactory properties without needing latex-stabilizing surfactants (Reddy and Palmer 2009).

The water permeability of a formation can be controlled by the addition of a water-soluble copolymer, formed from a hydrophobic or hydrophobically modified hydrophilic monomer and a hydrophilic monomer (Zamora et al. 2007). Suitable monomers are shown in Table 2.8.

The polymerization proceeds in an aqueous solution or emulsion. 2,2′-Azo bis(2-amidinopropane)dihydrochloride is added as radical initiator (Zamora et al. 2007). This azo-type initiator is water soluble. In order to quaternize the polymers, if desired, benzylcetyldimethyl ammonium bromide can be added.

Homopolymers and copolymers from amido sulfonic acid- or salt-containing monomers can be prepared by reactive extrusion, preferably in a twin screw extruder (Sopko and Lorentz 1991). The process produces a solid polymer. Copolymers of AAm, N -vinyl-2-pyrrolidone, and (NaAMPS) are proposed to be active as fluid loss agents. Another component of the formulations is the sodium salt of naphthalene formaldehyde sulfonate (Boncan and Gandy 1986). The fluid loss additive is mixed with hydraulic cements in suitable amounts.

A fluid loss additive for hard brine environments has been developed (Stewart et al. 1988), consisting of a hydrocarbon, an anionic surfactant, an alcohol, a sulfonated asphalt, a biopolymer, and optionally an organophilic clay, a copolymer of N -vinyl-2-pyrrolidone and NaAMPS. Methylenebisacrylamide can be used as a crosslinker (Patel 1998). Crosslinking imparts thermal stability and resistance to alkaline hydrolysis.

Terpolymers and tetrapolymers have been proposed as fluid loss additives for drilling fluids (Stephens 1988; Stephens and Swanson 1992). The constituent monomers are a combination of non-ionic monomers and ionic monomers. The non-ionic monomer can be AAm>, N,N -dimethylacrylamide, N -vinyl-2-pyrrolidone, N -vinylacetamide, or dimethyl amino ethyl methacrylate. Ionic monomers are AMPS, sodium vinylsulfonate, and vinylbenzene sulfonate. The terpolymer should have a molecular weight between 0.2 MDalton and 1 MDalton.

A formulation consisting of AMPS, AAm, and itaconic acid has been proposed (Garvey et al. 1988). Such polymers are used as fluid loss control additives for aqueous drilling fluids, and are advantageous when used with lime or gypsum-based drilling muds containing soluble calcium ions.

For sea water muds, another example (Bardoliwalla 1986b) is a copolymer of 10% AMPS and 90% AA in its sodium salt form. The polymers have an average molecular weight of 50–1000 kDalton.

A terpolymer from a family of intramolecular polymeric complexes (i.e., polyampholytes), which are terpolymers of AAm–methyl styrene sulfonate-methacrylamido propyltrimethyl ammonium chloride has been reported (Peiffer et al. 1986; Audibert-Hayet et al. 1998).

A terpolymer formed from ionic monomers AMPS, sodium vinylsulfonate, or vinylbenzene sulfonate itaconic acid, and a non-ionic monomer, for example, AAm, N,N -dimethylacrylamide, N -vinylpyrrolidone, N -vinylacetamide, and dimethyl amino ethyl methacrylate, is used as a fluid loss agent in oil well cements (Savoly et al. 1987).

The terpolymer should have a molecular weight of 0.2–1 M Dalton, and comprises AMPS, AAm, and itaconic acid. Such copolymers also serve in drilling fluids (Zhang and Ye 1998).

A tetrapolymer consisting of 40–80 molmathchar45% of AMPS, 10–30 molmathchar45% of vinylpyrrolidone, 0–30 molmathchar45% of AAm, and 0–15 molmathchar45% of acrylonitrile was also suggested as a fluid loss additive (Lange and Boehmer 1988). Even at high salt concentrations, these polymers yield high-temperature-stable, protective colloids that provide minimal fluid loss under pressure.

For water-based drilling fluids, water-soluble polymers are adequate, typically polyacrylamide, but they have a limited temperature stability.

Polymers based on AAm have been developed that exhibit effective rheological properties and high-temperature/high-pressure (HTHP) filtration control at temperatures of 260∘C or more (Jarrett and Clapper 2010). They are terpolymers composed of AAm, AMPS, or alkali metal salts, and a third monommer that can be an acrylate, N -vinyl lactam, or N-vinylpyridine (Jarrett and Clapper 2010). Examples of copolymers are listed in Table 2.9.

In order to assist effective seal forming for filtration control, a plugging agent is added (Jarrett and Clapper 2010). Examples of suitable plugging agents include the following: sized sulfonated asphalt, limestone, marble, mica, graphite, cellulosics and lignins, and cellophanes.

Other additives may be used in the drilling fluid system, including shale stabilizers, further filtration control additives, suspending agents, dispersants, anti-balling additives, lubricants, weighting agents, seepage control additives, lost circulation additives, drilling enhancers, penetration rate enhancers, corrosion inhibitors, buffers, gelling agents, crosslinking agents, salts, biocides, and bridging agents (Jarrett and Clapper 2010).

After static aging up to 260∘C for 16 h, the HTHP filtrate was measured extensively, with results of less than 25 cm³min⁻¹ (Jarrett and Clapper 2010).

Similar copolymers with N -vinyl-N -methylacetamide as a comonomer have been proposed for hydraulic cement compositions (Ganguli 1992).

The polymers are effective at well bottom hole temperatures ranging from 93–260∘C (200–500∘F) and are not adversely affected by brine. Terpolymers of 30–90 molmathchar45% AMPS, 5–60 molmathchar45% of styrene, and residual AA are also suitable for well cementing operations.

A fluid loss additive useful for cementing oil and gas wells is a blend of a copolymer of AAm/vinyl imidazole (Crema et al., 1991 and Crema et al., 1993; Kucera et al. 1989). The second component in the blend is a copolymer of vinylpyrrolidone and the sodium salt of vinylsulfonate. Details are given in Table 2.10. The copolymers are mixed together in proportions between 20:80 and 80:20. Sodium or potassium salts or a sulfonated naphthalene formaldehyde condensate can be used as a dispersant.

An N -vinylpyrrolidone/AAm random copolymer (0.05–5.0%) is used for cementing compositions (Cheung 1993; Le et al. 1998). Furthermore, a sulfonate-containing cement dispersant is necessary. The additive can be used in wells with a bottom hole temperature of 80–300∘F (30–150∘C).

The fluid loss additive mixture is especially effective at low temperatures, for example, below 100∘F (40∘C) and in sodium silicate–extended slurries. For aqueous cement slurries a copolymer of N -vinylpyrrolidone and a salt of styrene sulfonic acid has been proposed (Sedillo et al. 1987). A naphthalene sulfonic acid salt condensed with formaldehyde serves as a dispersant.

The fluid loss control of aqueous, clay-based drilling mud compositions is enhanced by the addition of a hydrolyzed copolymer of AAm and an N -vinylamide (Costello et al. 1990). The copolymer, which is effective over a broad range of molecular weights, contains at least 5 molmathchar45% of the N -vinylamide units, which are hydrolyzed to N -vinylamine units. The copolymers can be made from various ratios of N -vinylamide and AAm by using common radical polymerization techniques.

N -Vinylamide can be polymerized by the inverse emulsion polymerization technique (Lai and Vijayendran 1989). The polymers so produced are used for cementing compositions for oil and gas wells. The method for preparing the inverse, or water-in-oil, emulsion involves colloidally dispersing an aqueous solution containing 10–90% water-soluble N -vinylamide in a hydrocarbon liquid, using a surfactant with a hydrophilic-lipophilic balance value between 4 and 9. The weight ratio of monomer-containing aqueous solution to hydrocarbon liquid is preferably from 1:2 to 2:1. To initiate the polymerization, an azo-type free radical initiator is used. The resultant high molecular weight polymer emulsion has a low viscosity, ranging from 2 to less than 10 cP at 15% solids (60 rpm Brookfield and 20∘C), thus eliminating problems of solution viscosity that arise when it is prepared by a solution polymerization process.

Copolymers of styrene with AMPS that have fluid loss capabilities suitable for use in well cementing operations have been described (Brothers 1989). The styrene is present at 15–60 molmathchar45%, and the AMPS at 40–85 molmathchar45%. The polystyrene units are not hydrophilic, so AMPS will affect the solubility in water. AMPS is shown in Figure 2.10.

Copolymers of mainly AA with 2–20% of itaconic acid are described as fluid loss additives for aqueous drilling fluids (Bardoliwalla 1986a). The polymers have an average molecular weight of 100–500 kDalton and are water-dispersible. They are advantageous when used with muds containing soluble calcium and muds containing chloride ions, such as sea water muds.

Copolymers from the monomers AMPS, diallyldimethylammonium chloride (DADMAC), N-vinyl-N-methylacetamide, AAms, and acrylates are particularly useful as fluid loss additives (Hille et al. 1996). The molecular weights of the copolymers range from 200–1000 kDalton, and are used in suspensions of solids in aqueous systems, including saline, as water binders. In these systems, the water release to a formation is substantially reduced by the addition of one or more of these copolymers.

A copolymer of AMPS and other vinyl monomers produces a suitable formulation for filtration reducers, which has good temperature resistance (over 200∘C), and good tolerance to salts and calcium compounds (Li et al. 1996).

Polymers or copolymers of N -vinyl lactam monomers or vinyl-containing sulfonate monomers produce an additive for reducing the water loss and enhancing other properties of well-treating fluids in high-temperature subterranean environments. Organic compounds like lignites, tannins, and asphaltic materials are added as dispersants (Bharat 1990).

Oil-soluble polymers in the form of a gel can be used as a fluid loss additive for drilling WBM compositions to improve the high-temperature stability. Also, improved shear resistance can be obtained (Guichard et al., 2007 and Guichard et al., 2008). Such oil-soluble polymers are copolymers based on acrylates, styrene, vinyl toluene, butadiene, and others (Braden 2006).

Crosslinking monomers include allyl maleate, divinylbenzene, and multifunctional acrylates, as well as methacrylates. The monomers are detailed in the literature (Guichard et al. 2006). These acrylic copolymers are also used as binders for masonry applications, concrete and metal protection, intumescent coatings (Magnet et al. 2008), and as modifiers for toner compositions.

Oil-soluble polymers are highly efficient in small proportions as a fluid loss reducers, and may be incorporated in the mud at levels of only 0.5–2.5%. The polymer is added to a WBM prepared by conventional methods, either to replace the conventional fluid loss reducers, or in addition (Guichard et al. 2008). Mud formulations have been given in detail elsewhere (Guichard et al. 2006).

In addition, the filtration value is significantly reduced after high-temperature aging when a crosslinked copolymer is used in a standard water-based drilling fluid formulation (Guichard et al. 2008).

Fluid loss can be reduced by adding a terpolymer. The monomers and the composition are given in Table 2.11.

A series of mud systems and additives that have been in common use in coal-bed methane drilling have been evaluated with respect to their impact on the permeability of the coal matrix. Laboratory tests using both artificially cleated gypstone rock, as well as large-diameter coal cores, were performed as an assessment. In particular, various mud systems have been tested, including polyanionic and non-ionic cellulose and starch.

Muds based on xanthan gum, HEC, and Na-CMC did not have a negative impact on coal permeability. FLC™ 2000 and Q-Stop are very effective in building a thin filter cake on the coal surface almost instantaneously.

FLC™ 2000 is a micelle surfactant that very quickly forms a deformable barrier across coal cleats. Q-Stop consists of cellulose fibers. During production simulation experiments, a small pressure drop was sufficient to remove the filter cake.

It was shown that the permeability of the coal returned to its original value. This indicates that no permanent permeability damage is caused by the use of these additives. On the other hand, using the same coal type, the near-wellbore coal permeability was reduced by 87.5% by the addition of coal fines. Based on these laboratory studies, successful field applications in horizontal drilling could be achieved (Gentzis et al., 2009). The damage is illustrated in Table 2.12.

The rate of hydrocarbon flow declines when the bottom hole pressure falls below the dew point. When this occurs, a liquid aqueous phase accumulates near the well, sometimes termed condensate blocking. This effect reduces the relative permeability of the hydrocarbons and thus the productivity of the well (Nguyen et al. 2010b).

Also, if water swellable clays are present in this region, swelling is likely to occur, which reduces the permeability of the formation further. Well treatment fluids sometimes decrease the relative permeability of hydrocarbons. Capillary forces can tightly hold these treatment fluids. The rate of hydrocarbon flow can be also reduced by other factors, namely (Nguyen et al. 2010b):

The high velocity in the porous medium near the wellbore is sometimes sufficient to mobilize fines that subsequently can plug channels in the formation. Formation sand and fines often become unstable and migrate due to water movement through the formation. This is most likely to occur when the water phase is mobile because most of the fines are water-wet.

The presence of a mobile water phase can cause the migration of fines and subsequent formation damage. This needs to be minimized, since fines block flow paths, choking the potential production of the well, and also cause damage to downhole and surface equipment (Nguyen et al. 2010b).

Unconsolidated subterranean zones include those that contain loose particulates and those where the bonded particulates have insufficient bond strength to withstand the forces produced by the production of fluids through the zones. Support devices, such as screens and slotted liners, are often used to provide support for these unconsolidated formations in order to prevent a collapse of the formation.

In some instances, the annulus around the support device is gravel packed to reduce the voids between the device and the wellbore wall. Gravel packing forms a filtration bed near the wellbore, which acts as a physical barrier to the transport of unconsolidated formation fines with the production of hydrocarbons.

One common type of gravel packing operation involves placing a gravel pack screen in the wellbore, and packing the surrounding annulus with gravel of a specific mesh size, designed to prevent the passage of formation sand. Basically, the gravel pack screen is a filter, designed to retain the gravel placed during a gravel pack operation. Gravel packs may be time-consuming and expensive to install. Due to the time and expense needed it is sometimes advantageous to place a screen without the gravel.

An expandable screen is often installed to maintain the diameter of the wellbore for ease of access at a later time by eliminating installation of conventional screens, gravel placement, and other equipment.

Consolidation of a subterranean formation zone is often performed by pumping in a sequence of a resin, a spacer fluid and a catalyst. Such a resin application may be problematic when an insufficient amount of the spacer fluid is used, since the resin may contact the external catalyst too early.

An extensive review of literature concerning the methods for controlling unconsolidated particulates has been presented (Nguyen et al. 2010b). In addition, treatment fluids for controlling the migration of unconsolidated particulates in subterranean formations have been developed, which use a diluted epoxy resin. As diluent, a fluid that is miscible with water is used, i.e., methanol (Nguyen et al. 2010a). The addition of this solvent adjusts the viscosity of the resin composite so that a high degree of penetration into the subterranean formation can occur.

Hydrocarbon-producing wells are often stimulated by hydraulic fracturing operations, wherein a viscous fracturing fluid is introduced into the hydrocarbon-producing zone at a hydraulic pressure that is enough to create or enhance a fracture.

Generally, the fracturing fluid contains suspended proppant particles that are to be placed in the fractures to prevent them from fully closing (once the hydraulic pressure is released). This process forms conductive channels within the formation through which hydrocarbons can flow. Once at least one fracture is created, and at least a portion of the proppant is substantially in place, the viscosity of the fracturing fluid may be reduced, to remove it from the formation.

In certain circumstances, a portion of the fracturing fluid may be lost, e.g., through undesirable leak-off into natural fractures present in the formation. This is problematic because such natural fractures often have higher stresses than those created by a fracturing operation. These higher stresses may damage the proppant and cause it to form an impermeable plug in the natural fractures, which may prevent hydrocarbons from flowing through the natural fractures.

Conventionally, operators have attempted to solve this problem by including a fluid loss control additive in the fracturing fluid. These are generally rigid particles having a spheroid shape, but their use can be problematic in itself, since they may require particles that have a distinct particle size distribution in order to achieve efficient fluid loss control. For example, when used to block the pore throats in the formation, enough large particles will be required to obstruct most of the pore throat, and a sufficient proportion of relatively small particles will also be required to obstruct the interstices between the large particles. Such a particle size distribution may be difficult to obtain without incurring the added expense of reprocessing the materials, for example, by cryogenic grinding (Todd et al. 2006).

Polymers have been used as fluid loss control additives in cementing operations, including HEC and carboxymethylhydroxyethyl cellulose; copolymers of AMPS and AAm or N,N -dimethylacrylamide; and lignin or lignite grafted with AMPS, acrylonitrile, and N,N -dimethylacrylamide.

They may not provide the desired level of fluid loss control at high temperatures, however, i.e., at least about 260∘C (Lewis et al. 2009). Alternatively, a backbone of a humic acid salt has been proposed that has the moieties mentioned above grafted onto it. These graft copolymers are particularly suitable for use as fluid loss control additives in high-temperature applications.

Humic acids are produced by the decomposition of organic matter, such as dead plants, and may contain allomelanins found in soils, coals, and peat. The backbone may also contain PVA, PEO, polypropylene oxide, polyethyleneimine, and combinations of these moieties. Humic acid may be treated with KOH, NaOH, or NH₄OH to make it soluble in water.

The solution so produced is further concentrated to increase its humic acid content, or it may be used directly in the grafting process. The graft copolymers may be prepared by free radical polymerization techniques. The initiator employed is usually a redox reagent, capable of generating a free radical in the humic acid.

The performance of these additives has been tested with regard to cementing. Compressive strength and thickening time tests were performed to compare the performance of a range of cement compositions. The fluid loss of these compositions was tested at high temperatures (Lewis et al. 2009). The formulations provide desirable thickening times and compressive strengths.

Viscoelastic materials exhibit both viscous and elastic properties under mechanical deformation. Such materials exhibit a hysteresis in their stress strain curves. Further, a relaxation of stress occurs under constant strain, i.e., the stress is diminished. Moreover, viscoelastic materials exhibit creep.

A simple model for such materials was developed by James Clerk Maxwell in 1867 (Maxwell 1867). A Maxwell fluid or Maxwell body can be modeled by an idealized viscous damper and an idealized elastic spring connected in series. The basic device is shown in Figure 2.13.

The Maxwell model can hence explain both the elastic and viscous properties of a body. Some basic issues of the Maxwell model have been revisited (Rao and Rajagopal, 2007). The basic Maxwell model can be represented by:

The change in total elongation ε_t in time t is the sum of the change of elongation of the damper ε_D and the change of elongation of the spring ε_t. The right hand side of Eq. 2.6 is simply Newton's law of flow together with Hooke's law of the elongation of an ideal spring, i.e.,

The latter is given in the more uncommon differential form. Thus, η is the Newtonian viscosity, σ is the stress, and E is the elastic modulus. (By the way, if the spring and the damper are coupled in parallel instead of consecutively, the Kelvin-Voigt model emerges, which may be experienced in self-closing doors.)

The property of viscoelasticity has been well investigated (Rehage and Hoffmann, 1988). Aqueous solutions of cationic surfactants with strong binding forces of the ions show properties similar to gels.

Microstructural transitions and rheological properties of viscoelastic solutions formed in a catanionic surfactant system were studied using a combination of rheology and dynamic light scattering (Yin et al., 2009). The rheological behavior of such systems can be very complicated. In a study of a surfactant system based on dodecyltriethylammonium bromide and sodium dodecyl sulfate, worm-like micelles began to form above a certain surfactant concentration. In an intermediate concentration range, the system exhibits a linear viscoelasticity with the characteristics of a Maxwell fluid. Eventually, at higher surfactant concentrations, a transition from linear micelles to branched structures may take place.

The changes of the viscosity at zero shear rate with the total concentration of surfactant with a ratio of dodecyltriethylammonium bromide to sodium dodecyl sulfate of 27/73 are shown in Figure 2.14.