Chemicals Used in Oil-Field Operations - ACS Publications - American

Chapter 1

Chemicals Used in Oil-Field Operations

Downloaded by UNIV OF GUELPH LIBRARY on May 23, 2012 | http://pubs.acs.org Publication Date: July 10, 1989 | doi: 10.1021/bk-1989-0396.ch001

John K. Borchardt Westhollow Research Center, Shell Development Company, Houston, TX 77251-1380

Chemicals of various types are used i n every stage of drilling, completing, and producing oil and gas wells. This review describes these chemicals, why they are used, and recent developments. These chemicals include common inorganic s a l t s , t r a n s i t i o n metal compounds, common organic chemicals and solvents, water-soluble and o i l - s o l u b l e polymers, and surfactants. As existing f i e l d s become depleted, use of chemistry to maintain production v i a well stimulation, more e f f i c i e n t secondary recovery operations, and enhanced oil recovery become ever more important.

The modern chemical industry i s highly dependent on crude o i l and natural gas feedstocks. Conversely, chemicals, the science of chemistry and chemical engineering j o i n petroleum engineering to play an important r o l l i n the production of o i l and gas. The discovery rate of of major new o i l f i e l d s i s declining, p a r t i c u l a r l y i n the United States. As the petroleum industry becomes more dependent on increasing production from existing f i e l d s , the use of chemicals to more e f f i c i e n t l y d r i l l and operate o i l and gas wells and enhance productivity from these f i e l d s w i l l grow. Environmen t a l considerations w i l l probably be an increasingly important i n the choice of chemicals used i n well treatment f l u i d s p a r t i c u l a r l y in offshore locations. While geochemistry plays a role i n the discovery of o i l and gas and production chemicals are used to break produced oil-water emulsions and as f r i c t i o n reducers i n pipelines, t h i s review w i l l be r e s t r i c t e d to the chemistry and chemicals involved i n d r i l l i n g , completing, stimulating, and operating production and i n j e c t i o n wells and i n enhanced o i l recovery. D r i l l i n g Fluids D r i l l i n g f l u i d s (1-3) are often c a l l e d d r i l l i n g muds because of t h e i r appearance. This i s due to the dispersed clays added to most 0097-6156/89/0396-0003$13.95A) © 1989 American Chemical Society In Oil-Field Chemistry; Borchardt, J., et al.; ACS Symposium Series; American Chemical Society: Washington, DC, 1989.


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drilling fluids. The d r i l l i n g f l u i d i s circulated down the d r i l l pipe, around the d r i l l b i t , and up the wellbore while d r i l l i n g i s i n progress. The purpose of the d r i l l i n g f l u i d i s to cool and lubricate the d r i l l b i t , suspend formation cuttings and l i f t them to the surface, and control formation pressure reducing pressure surges up the wellbore (thereby reducing the p o s s i b i l i t y of blowouts). By cooling the d r i l l b i t and removing the cuttings from the bottom of the well bore, the rate of d r i l l i n g can be increased. The d r i l l i n g f l u i d i s designed to be thixotropic i . e . , have high v i s c o s i t y under low shear conditions when moving up the wellbore carrying suspended s o l i d s and have low v i s c o s i t y under the high shear conditions near the d r i l l b i t where rapid f l u i d movement i s necessary to cool the d r i l l b i t . D r i l l i n g f l u i d s usually contain water as the primary component. However, oil-based muds may be used f o r high temperature operations and f o r d r i l l i n g highly water-sensitive formations. Oil-based muds are of two types, o i l - e x t e r n a l emulsions containing as much as 50% water i n the i n t e r n a l phase or an oil-based f l u i d containing l i t t l e i f any water. A great many additives can be used to impart desired properties to the d r i l l i n g f l u i d . In general, the deeper and hotter the well, the more chemical additives are needed to obtain the desired f l u i d properties. These additives can be c l a s s i f i e d into d i f f e r e n t types by function. These include: Weighting materials which are used to adjust f l u i d density and thus hydrostatic pressure exerted on the formation by the wellbore fluid. The objective i s to prevent sudden pressure surges or blowouts during d r i l l i n g while simulataneously avoiding excessive f l u i d leak-off into formations being penetrated by the well bore. Barium sulfate (barite) i s the most commonly used weighting agent. Other insoluble minerals used include hematite, s i d e r i t e , and lead sulfide. Salts may be dissolved i n the base water to increase fluid viscosity. The use of high density calcium chloride, sodium and calcium bromides, and zinc bromide solutions and blends thereof has become common i n the U.S. Gulf Coast region (4-6). These f l u i d s are somewhat corrosive (7) and the use of corrosion i n h i b i t o r s such as thiocyanate ion has been recommended. However, these f l u i d s have excellent formation damage c h a r a c t e r i s t i c s ; f l u i d leakoff from the wellbore into the formation has l i t t l e adverse e f f e c t on rock permeability (8,9). F l u i d loss additives such as s o l i d p a r t i c l e s and water-thickening polymers may be added to the d r i l l i n g mud to reduce f l u i d loss from the well bore to the formation. Insoluble and p a r t i a l l y soluble f l u i d loss additives include bentonite and other clays, starch from various sources, crushed walnut h u l l s , l i g n i t e treated with caustic or amines, resins of various types, g i l s o n i t e , benzoic acid flakes, and c a r e f u l l y sized p a r t i c l e s of calcium borate, sodium borate, and mica. Soluble f l u i d loss additives include carboxymethyl c e l l u l o s e (CMC), low molecular weight hydroxyethyl c e l l u l o s e (HEC), carboxymethylhYdroxyethYl c e l l u l o s e (CMHEC), and sodium acrylate. A large number of water-soluble v i n y l copolymers and terpolymers have been described as f l u i d loss additives f o r d r i l l i n g and completion f l u i d s i n the patent l i t e r a t u r e . However, r e l a t i v e l y few appear to be used i n f i e l d operations.

In Oil-Field Chemistry; Borchardt, J., et al.; ACS Symposium Series; American Chemical Society: Washington, DC, 1989.


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Controlling f l u i d loss loss i s p a r t i c u l a r l y important i n the case of the expensive high density brine completion f l u i d s . While copolymers and terpolymers of v i n y l monomers such as sodium poly(2acrylamido-2-methylpropanesulfonate-co-N,N-dimethylacrylamide-coa c r y l i c acid) has been used (10), hydroxyethyl c e l l u l o s e i s the most commonly used f l u i d loss additive (11). I t i s d i f f i c u l t to get most polymers to hydrate i n these brines (which may contain less than 50% wt. water). The treatment of HEC p a r t i c l e surfaces with aldehydes such as glyoxal can delay hydration u n t i l the HEC p a r t i c l e s are well dispersed (12). S l u r r i e s i n low v i s c o s i t y o i l s (13) and alcohols have been used to disperse HEC p a r t i c l e s p r i o r to t h e i r addition to high density brines. This and the use of hot brines has been found to a i d HEC d i s s o l u t i o n . Wetting agents such as sulfosuccinate diesters have been found to r e s u l t i n increased permeability i n cores invaded by high density brines (14). Foaming agents provide another way to reduce f l u i d loss i s i n the d r i l l i n g f l u i d s . Mist or foam d r i l l i n g i s used i n r e l a t i v e l y shallow formations; commonly used foaming agents include ^^_^g alpha-olefin sulfonates and alcohol ethoxysulfates. While these d r i l l i n g f l u i d s have not been used extensively i n recent years, the development of improved foaming agents and systems containing water thickening polymer to s t a b i l i z e the foam has been reported (15). Defoamers are used to reduce undesirable foaming which often occurs when saline d r i l l i n g f l u i d s e x i t the well bore. Tributylphosphate, low molecular weight a l i p h a t i c alcohols, polyglycols, f a t t y alcohol g l y c o l ethers, acetylenic glycols, aluminum stearate, potassium chloride, silicone-based defoamers, and sodium alkylaromatic sulfonates have been used. Lost c i r c u l a t i o n chemical treatments are necessary when the d r i l l b i t penetrates a " t h i e f zone and very large amounts of d r i l l i n g f l u i d are l o s t to the formation. In t h i s s i t u a t i o n , the addition of water thickeners or s o l i d p a r t i c l e s may not be s u f f i c i e n t . The face of the formation can be plugged using a rapidly setting cement s l u r r y or a process involving the i n - s i t u gelation/precipitation of sodium s i l i c a t e , treatment with Portland cement, and i n less serious cases by plugging the formation face with shredded c e l l o phane, crushed walnut and almond h u l l s , cedar and cane f i b e r s , and c a r e f u l l y sized sodium chloride and calcium carbonate p a r t i c l e s . V i s c o s i f i e r s are used as rheology modifiers to a i d i n suspending rock cuttings as they are carried to the surface. Many of the f l u i d loss additives described above are used i n t h i s application. Clays such as bentonite (montmorillonite) are the most commonly used rheology modifiers. The main organic polymers that are used, polysaccharides and acrylamide and acrylate polymers, often have limited temperature s t a b i l i t y or exhibit excessive temperature thinning i n deep hot wells. At concentrations below 2.8 g/L, xanthan gum i s a more e f f e c t i v e solids suspending agent than HEC, CMC, and p a r t i a l l y hydrolyzed polyacrylamide (16). While starches are commonly used, they are r e l a t i v e l y poor v i s c o s i f i e r s . Acids and b a c t e r i a l enzymes r e a d i l y attack the acetal linkages r e s u l t i n g i n f a c i l e depolymerization. Both formaldehyde and isothiazolones have been used as starch biocides (17). Development of improved high temperature water v i s c o s i f i e r s for d r i l l i n g and other o i l f i e l d applications i s underway. For the c

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present, oil-based d r i l l i n g f l u i d s o f f e r the best alternative f o r elevated temperature applications despite t h e i r r e l a t i v e l y high cost. S t a b i l i z i n g agents are used to maintain d r i l l i n g f l u i d rheological properties at highly elevated downhole temperatures. Chromium and chromium-free lignosulfonates, polyglycol ethers, sodium poly s t y r e n e sulfonate-co-maleic anhydride), and a melanin polymer have been used i n t h i s application. Additives such as sodium d i e t h y l d i thiocarbamate have been used to s t a b i l i z e aqueous polysaccharides such as xanthan gum (18). Flocculants cause c o l l o i d a l clay p a r t i c l e s to coagulate thus promoting separation from the d r i l l i n g f l u i d which has been c i r c u l a t e d down the wellbore and returned to the surface. The treated f l u i d may then be pumped back down the well bore. Sodium chloride, hydrated lime, gypsum, sodium tetraphosphate, polyacrylamide, polY(acrylamide-co-acrylic acid), cationic polyacrylamides, and poly(ethylene oxide) have been used commercially. Thinners and dispersants are used to prevent excessive f l o c c u l a t i o n of clay p a r t i c l e s and maintain pumpability of the f l u i d . Tannins, various lignosulfonate s a l t s , sodium tetraphosphate and other phosphates, and synthetic polymers such as sodium poly(styrene sulfonate-co-maleic anhydride) have been used. F r i c t i o n reducers such as p a r t i a l l y hydrolyzed polyacrylamide may also be used i n d r i l l i n g f l u i d s (19). They allow f l u i d to be c i r c u l a t e d through the well bore more e a s i l y thereby reducing horsepower requirements for the c i r c u l a t i n g pumps and thus decreasing well treatment costs. Lubricants o f f e r a means of reducing torque and increasing the e f f e c t i v e horsepower to the d r i l l b i t by reducing f r i c t i o n . Various vegetable o i l s , graphite powder, soaps, asphalt blends, air-blown asphalt c o l l o i d s , d i e s e l o i l , and f a t t y acid esters have been used. Pipe-freeing agents are used to reduce f r i c t i o n and increase l u b r i c i t y i n areas of expected d r i l l pipe sticking such as angles i n deviated wellbores. Soaps, surfactants, o i l s , soda lime, glass beads, and cationic polyacrylamide have been used. Corrosion i n h i b i t o r s are used to reduce the corrosion of surface equipment, surface casing, and the d r i l l s t r i n g by d r i l l i n g and well treatment f l u i d s . Many d i f f e r e n t corrosion i n h i b i t o r s have been used. These include amine s a l t s such as ammonium s u l f i t e - b i s u l f i t e blends, zinc carbonate, zinc chromate, hydrated lime, f a t t y amine s a l t s of alkylphosphates, cationic polar amines, ethoxylated amines, and t e r t i a r y c y c l i c amines. Commercial products are usually proprietary blends of chemicals. Bactericides are used to control b a c t e r i a l growth which can cause corrosion, plugging of the fomation face, and a l t e r a t i o n of d r i l l ing f l u i d rheological properties. Paraformaldehyde, glutaraldehyde, sodium hydroxide, lime derivatives, dithiocarbamates, isothiazolones, and diethylamine have a l l been used. pH control aids i n reducing corrosion and scaling and i n control l i n g interaction of the d r i l l i n g f l u i d with formation minerals. Sodium hydroxide, calcium carbonate, sodium bicarbonate, sodium carbonate, potassium hydroxide, magnesium oxide, calcium oxide, fumaric acid, and formic acid have a l l been used commercially i n t h i s application.



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Formation damage control chemicals are added to reduce the permea b i l i t y damage that occurs when d r i l l i n g f l u i d enters the formation. This also aids i n preventing erosion of the formation into the wellbore. Maintaining the c y l i n d r i c a l geometry and uniform diameter of the welbore aids i n subsequent cementing operations. Potassium chloride, ammonium chloride, sodium chloride, gypsum, sodium s i l i c a t e , p a r t i a l l y hydrolyzed polyacrylamide and poly(acrylamide-co-acrylic acid), certain polymers having quaternary ammonium groups i n the repeat unit (see Chapter 10), and lignosulfonate derivatives have a l l been used to reduce formation damage. Scale i n h i b i t o r s are used to prevent the formation of insoluble calcium s a l t s when the d r i l l i n g f l u i d contacts formation minerals and saline formation waters. Commonly used scale i n h i b i t o r s include sodium hydroxide, sodium carbonate, sodium bicarbonate, polyacrylates, polyphosphates, and phosphonates. Emulsifiers have been used to prepare o i l - e x t e r n a l emulsion d r i l l ing f l u i d s . Surfactants used as emulsifiers include f a t t y acid s a l t s , f a t t y acid amides, petroleum sulfonates, and lignosulfonates. Because of the r e l a t i v e l y low cost of many of the chemicals used i n d r i l l i n g f l u i d s , development of more cost e f f e c t i v e additives i s a major challenge. However, improved high temperature polymers, surfactants, and corrosion i n h i b i t o r s are under development i n many laboratories. Cementing Fluids (20,21) After completion of the d r i l l i n g operation, s i e e l casing i s lowered down the well bore and into the d r i l l i n g f l u i d . A spacer f l u i d i s then pumped down the well bore to remove the d r i l l i n g f l u i d and prevent contact of the d r i l l i n g mud with the cement slurry. E f f i c i e n t displacement of the d r i l l i n g mud also promotes bonding of the cement s l u r r y to rock surfaces. Intermixing of the spacer and the d r i l l i n g f l u i d should not produce solids or a high v i s c o s i t y phase. Most spacers are aqueous and contain polymers to increase f l u i d v i s c o s i t y . Spacer density i s usually intermediate between that of the d r i l l i n g f l u i d and the cement s l u r r y (22). Salts may be added to control f l u i d density and pH. Surfactants are used to a i d removal of d r i l l i n g mud from formation surfaces. Water-wetting surfactants also a i d i n making the casing and exposed rock surfaces water-wet to promote good cement bonding (23). This i s p a r t i c u l a r l y important when using oil-based d r i l l i n g f l u i d s . Turbulent flow at reasonable pump rates aids i n removal of d r i l l i n g mud from surfaces (24). Downhole devices c a l l e d scratchers can be i n s t a l l e d on the casing to scrape d r i l l i n g mud residues from formation surfaces. Other devices c a l l e d c e n t r a l i z e r s may be attached to the casing to center i t i n the wellbore. With increased development work from offshore platforms, more non-vertical (deviated) wells are being d r i l l e d . S e t t l i n g of mud solids to the low side of the well bore can result i n a continuous channel of undisplaced d r i l l i n g mud solids i n the casing annulus


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that reduce the effectiveness of cement bonding (25,26). Converse l y , cement s o l i d s can s e t t l e from the s l u r r y before i t sets resulting i n a channel of water i n the high side of the casing annulus. Proper design of both the d r i l l i n g f l u i d ( p a r t i c u l a r l y through use of surfactants as dispersants) and the cement s l u r r y (including good control over cement set time) are necessary to prevent t h i s . The cement s l u r r y i s pumped down the casing and up the annular space between the casing and the formation. The spacer and d r i l l i n g f l u i d are thus displaced by the cement s l u r r y . A compatible f l u i d (one that does not substantially a l t e r the set time of the cement slurry) i s pumped into the wellbore to displace nearly a l l the cement s l u r r y into the annular space between the casing and the formation. The well i s then shut i n to allow the cement to set. This bonds the casing to the formation and isolates o i l - and gas-bearing formations from aquifers and brine-containing formations. F l u i d communication between formations can adversely a f f e c t production operations or lead to contamination of potable water aquifers. Incomplete displacement of f l u i d from the annular space can r e s u l t i n gaps i n the cement sheath through which f l u i d s from d i f f e r e n t formations can intermingle. In t h i s s i t u a t i o n , a "squeeze cementing" treatment i s required to plug these gaps. Portland cement or rapidly setting sodium s i l i c a t e s l u r r i e s can be used i n t h i s operation. When cementing high pressure gas formations, the gas can penetrate the cement s l u r r y before i t sets greatly weakening the set cement (27). Various solutions to t h i s problem have been proposed including the use of cement s l u r r y formulations which expand as they harden thereby r e s i s t i n g gas invasion (28). Foamed cement s l u r r i e s have been used to provide a low density cement s l u r r y to reduce permeability damage to highly sensitive formations through reduced f l u i d loss (29). Glass microspheres have also been used to substantially reduce cement s l u r r y density (30, 31). Other additives which reduce cement s l u r r y density to a lesser extent include bentonite, f l y ash, s i l i c a t e s , p e r l i t e , g i l s o n i t e , diatomaceous earth, and o i l emulsions (see c i t a t i o n s i n reference 29). Corrosion-resistant cements have been developed for use i n wells used to i n j e c t s u p e r c r i t i c a l carbon dioxide for enhanced o i l recovery (32). These are based on Portland cement and high levels (as much as 40% wt.) of additives such as f l y ash. Epoxy resins have been successfully used as cements i n corrosive environments (33). Lignosulfonates and lignosulfonate derivatives are used extensively as cement set time retarders (20, 21). Many of the same additives used i n d r i l l i n g muds are used i n cement s l u r r i e s and spacer f l u i d s for s i m i l a r purposes. Completion Fluids and Operations (1,20,34) After cementing the well, communication must be established with the productive formation. This i s done i n an operation c a l l e d perforating. The wellbore i s f i l l e d with a non-damaging f l u i d of



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the proper density to control pressure surges while not exhibiting excessive f l u i d loss to the formation. A perforating t o o l or "gun" i s lowered into the well bore and placed opposite the productive formation. The gun f i r e s p r o j e c t i l e s or powerful jets of gas generated i n small explosions to penetrate the casing and cement sheath. Perforations are generated i n a controlled pattern and spacing chosen a f t e r considering the formation properties and productive capacity. A small amount of acid may be used to wash the perforations to remove pulverized debris which reduces the f l u i d carrying capacity of the perforations and adjacent formation. Production tubing i s then lowered into the hole and the productive portion(s) of the well i s o l a t e d using sealing tools c a l l e d packers (21). This i s done to produce from more than one formation simul taneously and to minimize the volume of o i l and gas i n the wellbore during production. F l u i d loss from the wellbore to the formation may be reduced using the less permeability damaging d r i l l i n g f l u i d loss additives described above. In saturated brines, c a r e f u l l y sized sodium chloride p a r t i c l e s have been used to temporarily plug the formation face (35). The p a r t i c l e s may be dissolved by pumping a less saline f l u i d down the wellbore. Sand production from poorly consolidation formations i s a s i g n i f i cant problem i n important o i l producing areas such as the U.S. Gulf Coast; Kern County, C a l i f o r n i a ; Venezuela; Alberta; Nigeria; and Indonesia. The most commonly used technique f o r sand control i s c a l l e d gravel packing. A s l u r r y of as much as 1.8 kg of c a r e f u l l y sized sand p a r t i c l e s per l i t e r of aqueous f l u i d i s pumped downhole. The sand p a r t i c l e size i s chosen based on size analyses of the formation sand (19,36). The sand-carrying capacity of the water i s enhanced by increasing i t s v i s c o s i t y using 20-80 l b polysaccharide per 1000 gallon. The most commonly used polysaccharide i s hydroxyethyl c e l l u l o s e because i t s low content of insoluble s o l i d s mini mizes permeability damage to the formation (37). Carboxymethyl c e l l u l o s e and d e r i v i t i z e d guars are occasionally used i n t h i s application (1). Methods of s t a b i l i z i n g polysaccha rides o r i g i n a l l y developed f o r hydraulic fracturing applications (see below) hold promise f o r increasing the range of temperatures at which polysaccharide polymers can be used i n gravel packing applications. Certain mixtures of polymers have been shown to form complexes which exhibit substantially higher than expected solution v i s c o s i t y under low shear conditions. Xanthan gum blends with guar gum (38, 39), sodium poly(styrene sulfonate) (40), polyacrylamide (41), sulfonated guar gum (38), sodium poly(vinylsulfonate) (40), hydrolyzed sodium poly(styrene sulfonate-co-maleic anhydride) (38), and poly(ethylene oxide) (41) and blends of xanthan gum and locust bean gum have exhibited substantially higher than expected solution v i s c o s i t y (42, 43). An enzyme, acid, or oxidative "breaker" i s added to e f f e c t a controlled depolymerization and thus a programmed loss of f l u i d viscosity. This depolymerization i s timed to occur when the sandladen f l u i d i s opposite the productive formation. The sand then drops out of suspension and i s packed against the formation. The sand creates a high permeability f l u i d pathway from the formation


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into the wellbore while s u b s t a n t i a l l y preventing the migration of formation p a r t i c l e s . Downhole tools such as wire-wrapped screens or l i n e r s are used i n conjunction with gravel packing. These devices serve to hold the sand i n place. Since formation damage i s a c r i t i c a l factor i n successful gravel pack treatments, continuing e f f o r t s are being made to improve the formation damage c h a r a c t e r i s t i c s of polysaccharide f l u i d s both before and after depolymerization (37). Recently, grades of hydroxyethyl c e l l o l o s e having improved formation damage c h a r a c t e r i s t i c s were introduced into the market place. Injecting epoxy, furan, or furan-formaldehyde resins into poorly consolidated formations to consolidate them was a common sand control practice f o r thin highly productive formations (4446). Organic solvents (46) and silane coupling agents (47) are used to promote adhesion of the r e s i n to the rock surface. Excess r e s i n i s flushed deeper into the formation to minimize r e s i n hardening i n the flow channels since t h i s would reduce formation permeability. While e f f e c t i v e , the r e l a t i v e l y high cost of t h i s sand control method as compared to gravel packing has r e s t r i c t e d i t s use. The use of aqueous s l u r r i e s of epoxy resins can reduce solvent costs (44). Surfactants, p a r t i c u l a r l y fluorochemicals, may hold promise for increasing epoxy r e s i n f l u i d i t y (49). The i n s i t u crosslinking of polybutadiene has been proposed as a method of reducing r e s i n costs (50). The gravel packing technique could be used to place resin-coated sand against a poorly consolidated formation (51-53). The r e s i n i s then cured r e s u l t i n g i n a hard, but permeable mass holding formation sand grains i n place. S i l i c a d i s s o l u t i o n i n high temperature steam i n j e c t i o n wells can destroy the i n t e g r i t y of a gravel pack and lead to sand production when the well i s placed back on production (54). Use of a resin-coated sand could a i d i n maintaining gravel pack s t a b i l i t y and effectiveness. Another method of sand control i s use of a s i l i c o n halide which reacts with water at the surface of sand grains forms SiO^ which can bond the grains together (55). Reducing the cost of sand consolidation could be very useful since the a p p l i c a b i l i t y of gravel packing methods i s limited by the bottom hole c i r c u l a t i n g temperature and the limited temperature s t a b i l i t y of polysaccharide polymers. Hydraulic Fracturing (20,56) Since hydraulic fracturing i s reviewed i n a subsequent chapter, t h i s important production stimulation technique w i l l be only b r i e f l y discussed. Hydraulic fracturing i s a process whereby the permeability of a formation i s increased by generating high permea b i l i t y cracks i n the rock. P a r t i c u l a t e suspensions (usually sand s l u r r i e s ) are injected at s u f f i c i e n t l y high rates (which require high i n j e c t i o n pressures) to generate fractures i n the rock which are held open by the suspended proppant i n the fracturing f l u i d . The majority of hydraulic fracturing treatments are performed using water-based f l u i d s ; foams (with nitrogen or carbon dioxide as the gas phase) have been used extensively i n recent years to reduce formation damage. Oil-external emulsions have also been used f o r



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the same purpose. Ingredients used i n hydraulic fracturing are chosen from the following: A v i s c o s i f i e r , usually a polysaccharide, i s used to suspend the proppant during pumping and placement i n the rock fracture. Generally 2-7g of guar per l i t e r of fracturing f l u i d i s used. Hydrolytic depolymerization beings at 79.6 C (34). The degradation rate i n a l k a l i n e media, acid, and i n the presence of c e l l u l a s e and hemicellulase enzymes has been determined (1). Most fracturing treatments employ a crosslinked polymer. A disadvantage of guar i s the r e l a t i v e l y high l e v e l of insoluble materials normally l e f t i n the product after processing, 10-14% wt. (57). Alkaline r e f i n i n g can reduce the insoluble materials l e v e l substantially, to ca. 3.9% wt. (58). Guar deriva tives such as HPG and carboxymethylhydroxypropyl guar (CMHPG) contain fewer insolubles, 150 F. The most commonly used crosslinking agents are organotitanates, borates, and zirconium compounds. Organozirconates are the preferred crosslinkers f o r hydroxyethyl c e l l u l o s e (79-81). Antimonates and aluminum compounds have also been used as polysaccharide crosslinkers. Encapsulation of crosslinkers and the use of ligands to complex with the t r a n s i t i o n metal atom have been used to delay crosslinking (82). Delayed crosslinking which occurs within the formation under lower shear conditions can provide higher and more predictable crosslinked f l u i d v i s c o s i t y (83). Polyamines such as tetramethylenediamine can be used to accelerate crosslinking reactions (84). A breaker; an enzyme (at T225 F. Methanol and sodium t h i o s u l f a t e are the most commonly used (86). Sodium d i t h i o carbamate, alkanolamines, and t h i o l derivatives of imidazolines, thiazolines, and other heterocyclic compounds have also been tested for t h i s application. Calcined dolomite (87) and Cu(l) and C u ( l l ) s a l t s (88) have been reported to increase the thermal s t a b i l i t y of HEC. Biocides are used to prevent aerobic b a c t e r i a l degradation of fracturing f l u i d s i n surface mixing and storage tanks. Anaerobic b a c t e r i a l growth i n the wellbore and within the formation has to be controlled to prevent introduction and/or growth of these bacteria within the formation during the fracturing treatment and subsequent generation and production of hydrogen s u l f i d e . Glutaraldehyde, chlorophenates, quaternary amines, and i s o t h i a z o l i n e derivatives have been used (89,90). The biocide i s best added to the base f l u i d before addition of the polysaccharide v i s c o s i f i e r . pH buffers are added to the base f l u i d to keep the pH basic. This promotes rapid polymer p a r t i c l e dispersion and controls polysaccharide hydration rate to avoid formation of large, p a r t i a l l y hydrated p a r t i c l e s . Other techniques to promote complete polymer hydration include vigorous mixing and slow addition of the polysaccharide. Specially designed mixing devices have been used to promote rapid p a r t i c l e dispersion (91). Adding already prepared dispersions of guar, HPG, and HEC i n nonaqueous media i s another means of promoting rapid



1. BORCHARDT


13

polymer p a r t i c l e dispersion and complete hydration (81,92). Wetting polymer surfaces with ethylene g l y c o l (92) or isopropanol (93) has also been used as a means of promoting rapid polymer dispersion p r i o r to the onset of hydration. Various p a r t i c l e surface treatments have been used to delay polymer hydration u n t i l polymer p a r t i c l e s have been thoroughly dispersed. These include guar treatment with borax (2,94) and HEC treatment with glyoxal (95). Buffers also are used to maintain the proper pH for the crossl i n k i n g reaction to occur at an optimum rate. Sodium bicarbonate and sodium carbonate are used to a t t a i n basic pH while weak acids: a c e t i c , fumaric, formic, and adipic, are generally used to obtain a c i d i c pH values. Formation damage control additives are added to reduce permeability damage caused by clay swelling and consequent fine p a r t i c l e migra t i o n (which can also occur i n the absence of clay swelling). Potassium chloride, ammonium chloride, sodium chloride, and, f o r longer term treatment effectiveness, organic polymers containing quaternary ammonium groups i n the repeat unit have been used f o r t h i s application. While avoiding permeability damage to the formation adjacent to the propped fracture i s c r i t i c a l i n determin ing i n i t i a l hydrocarbon production rate, f l u i d conductivity i n the propped fracture i s the primary determinant of long-term productiv i t y (96). Surfactants are used to s t a b i l i z e water-in-oil emulsions and to promote rapid return of injected f l u i d s and a faster return of the well to hydrocarbon production. Although they are expensive, water-soluble fluorochemicals have been shown to be e f f e c t i v e i n t h i s application (97,98). Foams have become widely used to l i m i t the f l u i d l o s t to the formation and thus reduce formation damage. Foam c e l l size plays a major role i n determining f l u i d rheology (99). Guar, HPG, and xanthan gum s t a b i l i z e the foam bubbles by increasing the v i s c o s i t y of the surrounding aqueous f l u i d . Both nitrogen and carbon dioxide have been used as the i n t e r n a l phase of the foam (100-102) and foams based on each exhibit similar rheological behavior i n laminar flow (102) and similar f l u i d loss behavior (103,104). The carbon dioxide i s pumped as a s u p e r c r i t i c a l f l u i d which changes to a gas downhole (105). Acidizing Chemicals (20,106) Acid treatments f a l l into three general types: Acid washing i s used to dissolve acid-soluble scales from the well bore and to open gravel packs and perforations plugged by such scales. Matrix a c i d i z i n g i s the i n j e c t i o n of acids into the formation at a pressure below the formation parting pressure (the pressure at which natural fractures are forced open by injected f l u i d s ) . Properly designed, the injected acid enters the flow channels of the formation and flows r a d i a l l y outward from the wellbore dissolv ing mineral f i n e p a r t i c l e s i n the flow channels. Minerals forming the flow channel walls also react with the acids. These processes increase formation permeability near the wellbore. The end result



14

OIL-FIELD CHEMISTRY

i s to increase well productivity without increasing the produced water:oil or g a s : o i l r a t i o s . So-called "wormholes" can be formed when the injected acid primarily enters the largest diameter flow channels i n carbonate rock further widening them (107). Acid only invades the small flow channels a short distance greatly reducing treatment effectiveness. High f l u i d loss rates, low i n j e c t i o n rates, and reduced rates of acid-rock reactions decrease the wormhole length. In the t h i r d type of a c i d i z i n g , fracture a c i d i z i n g , acid i s injected above the parting or fracture pressure of the formation. The acid reacts with the minerals on the exposed fracture face i n a process c a l l e d etching. With s u f f i c i e n t etching, the fracture does not reseal when normal well production or i n j e c t i o n operations are resumed. Acids can sometimes break emulsions within the formation either by reducing the pH or by dissolving f i n e p a r t i c l e s which can s t a b i l i z e emulsions. Breaking the emulsion reduces f l u i d v i s c o s i t y thus increases the f l u i d carrying capacity of the flow channel. Acids may be used as breakers to reduce the v i s c o s i t y of acidsensitive fracturing gels. Acids are sometimes used ahead of fracturing f l u i d s to dissolve mineral f i n e p a r t i c l e s and allow more rapid i n j e c t i o n of the fracturing f l u i d . When used as the i n i t i a l stage of a squeeze cementing treatment, the acid-promoted mineral and d r i l l i n g mud p a r t i c l e d i s s o l u t i o n can r e s u l t i n increased entry of the cement s l u r r y into the desired portions of the formation. Acids are selected based on the nature of the well treatment and the mineralogy of the formation. The c r i t i c a l chemical factors i n properly selecting an acid are: stoichiometry (how much forma tion material i s dissolved by a given amount of acid), the equilibrium constant (complete reaction of the acid i s desired), and reaction rate between the acid and the formation material (106). Mineral acids include hydrochloric acid and blends of hydrochloric and hydrofluoric acid (usually 12% HCl/3% HF). Hydrochloric acid i s used to acidize carbonate formations. Its advantages are r e l a t i v e l y low cost, high carbonate mineral dissolving power, and the formation of soluble reaction products (which minimizes forma tion damage). The primary disadvantage of hydrochloric acid i s i t s corrosive nature. Hydrofluoric acid may be prepared by d i l u t i o n of a concentrated aqueous solution or by reaction of enough ammonium b i f l u o r i d e with aqueous 15% HCl to prepare a 12% HCl/3% HF solution. Hydrochloric - hydrofluoric acid blends have the major advantage of dissolving silicaceous mineral including clays and s i l i c a f i n e p a r t i c l e s . HCl/HF blends are quite corrosive. E a r l i e r corrosion i n h i b i t o r s limited the maximum strength of the acid to 15% by weight. Improved corrosion i n h i b i t o r s (see below) have made the use of higher acid concentrations, such as 28% HCl more common. More d i l u t e solutions may i n i t i a l l y be injected in sandstone a c i d i z i n g to reduce the formation of insoluble sodium and potassium f l u o r o s i l i c a t e s by displacing saline formation water before i n j e c t i o n of hydrochloric acid.



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Organic acids used i n carbonate rock a c i d i z i n g include formic, acetic, sulfamic, and chloroacetic acids. These have the advantage of being less corrosive than the mineral acids. This permits use in applications requiring a long contact time with pipe (as perfo rating f l u i d s ) or with aluminum- or chrome- plated pump parts. I t i s also easier to retard ( i n h i b i t ) reaction of organic acids with carbonates at elevated temperatures. This permits deeper penetra t i o n of the acid treatment f l u i d into the formation. Organic acids are used to a much smaller extent than mineral acids due to t h e i r higher cost and incomplete reaction with many carbonate minerals. Sulfamic and chloroacetic acids are seldom used except i n situa tions such as remote well locations where t h e i r s o l i d form (100% a c t i v i t y ) makes transportation costs a c r i t i c a l consideration. The 180 F decomposition temperature l i m i t s the use of sulfamic acid to temperatures below ca. 160 F. Mixed acid systems are blends of mineral acids and organic acids. Combinations that have been used i n carbonate a c i d i z i n g include acetic acid/HCl and formic acid/HCl. While these are less corro sive than hydrochloric acid alone, the organic acid may not react completely with the rock. Blends of formic acid and hydrofluoric acid have been used i n high temperature sandstone a c i d i z i n g and are less corrosive than HC1/HF blends. High f l u i d i n j e c t i o n rates are often required. For t h i s reason, f r i c t i o n reducers are often used i n acid f r a c t u r i n g . These include polyacrylamide and acrylamide copolymers, guar gum, hydroxyethyl c e l l u l o s e , and karaya gum (108) In many cases, i t i s desirable to retard the rate of acid rock reactions to permit deeper penetration of the treatment f l u i d into the formation. Four techniques hve been used to accomplish t h i s : using retarded acids which generate HF in s i t u , chemically retarding the acid by placing an organic f i l m on rock surfaces, using polymers to increase acid v i s c o s i t y (use of so-called "gelled" acids), and foaming or emulsifying the acid to increase the apparent v i s c o s i t y . Retarded acids are primarily applicable to sandstone a c i d i z i n g . Fluoroboric acid slowly hydrolyzes to form the more reactive hydrofluoric acid (109,110). The time required for t h i s hydrolysis process may enable deeper penetration of the HF into the formation although one report contradicts these findings (111). Na^TiF^ and similar s a l t s also slowly generate HF i n acid media (112). Phosphorous acid addition to hydrochloric acid has been used to reduce the HCl reaction rate with limestone (113). Organic polymers have been used to increase the v i s c o s i t y of acids. The primary application i s i n fracture a c i d i z i n g . Binary and ternary acrylamide copolymers are the most commonly used chemicals for t h i s application. Many of these polymers degrade rapidly i n strong acids at temperatures >130 F; development of more stable polymers suitable for high temperatures i s desirable. Recently developed polymers for t h i s application include acrylamide copolymers with: methacryloyltrimethylammonium chloride (114) 2-acrylamido-2-methylpropanesulfonic acid (115) methacryloyloxyethyltrimethylammonium methosulfate (116). N-vinyl lactam (117)



16

OIL-FIELD CHEMISTRY

Other polymers used i n t h i s application include: poly(vinylpyrrolidinone) (118,119) sodium poly(vinylsulfonate-co-vinylamide) (120) sodium poly(acrylamide-co-N-vinyl lactam-co-vinyl sulfonate) (119) and mixtures of sodium poly(2-acrylamido-2-methylpropanesulfonate-co-N-vinylacetamide) and p o l y ( a c r y l i c acid-co-vinylformamide-co-vinylpyrrolidinone) (120). Despite i t s limited s t a b i l i t y i n acid (1), guar gum has been used to thicken 3-15% hydrochloric acid (121). An a l l y l ether guar gum adduct has been proposed for use as an acid v i s c o s i f i e r (122). Zr(IV) crosslinked CMHEC has been used to thicken hydrochloric acid (81). Low v i s c o s i t y o i l - e x t e r n a l retarded hydrochloric acid microemulsions exhibiting quite low acid d i f f u s i o n rates (ca. 1% of that of aqueous HCl) have been developed (123,124). Foaming (125) or emulsifying acid (106) also has the e f f e c t of l i m i t i n g the contact of the acid with formation surfaces and increasing acid v i s c o s i t y thereby reducing the rate of acid-rock chemical reactions. The foaming agents are generally nonionic surfactants and the gas phase i s usually nitrogen. The acid i s usually the i n t e r n a l phase of emulsified acids and the f l u i d contains 10-30% of a low v i s c o s i t y hydrocarbon as the external phase. Polyacrylamide has been used to thicken the aqueous phase of hydrochloric acid emulsions (126) while nonionic surfactants have been used as the emulsifiers (127). Overall, emulsified acids appear to be the most suitable for high temperature formations. By adding an oil-wetting surfactant to an acid, one can promote the temporary formation of a f i l m on formation surfaces thus reducing the rate of rock d i s s o l u t i o n . Acids containing these surfactants are known as chemically retarded acids. Surfactants are also used to break low mobility o i l emulsions. Organic amines and quaternary ammonium s a l t s (128), alkylphenol ethoxylates (128), poly(ethylene oxide-co-propylene oxide-copropylene glycol) (129) and a l k y l - or a l k y l a r y l polyoxyalkylene phosphate esters (130) are among the surfactants that have been used. Mutual solvents have been used to reduce surfactant adsorption on formation minerals, p a r t i c u l a r l y oil-wetting surfactants (131). Ethylene g l y c o l monobutyl ether i s the most commonly used mutual solvent. Formation permeability damage caused by p r e c i p i t a t i o n of dissolved minerals such as c o l l o i d a l s i l i c a , aluminum hydroxide, and aluminum fluoride can reduce the benefits of a c i d i z i n g (132-134). Careful treatment design, p a r t i c u l a r l y i n the concentration and amount of HF used i s needed to minimize t h i s problem. Hydrofluoric acid i n i t i a l l y reacts with clays and feldspars to form s i l i c o n and aluminum f l u o r i d e s . These species can react with additional clays and feldspars depositing hydrated s i l i c a i n rock flow channels (106). This usually occurs before the spent acid can be recovered from the formation. However, some workers have concluded that permeability damage due to s i l i c a p r e c i p i t a t i o n i s much less than previously thought (135).



1. BORCHARDT


P r e c i p i t a t i o n of Fe(III) compounds from acid solutions as the pH increases above 2.2 i s a p a r t i c u l a r problem. Complexing agents that have been used include 5 - s u l f o s a l i c y l i c acid and c i t r i c acid (136); dihydroxymaleic acid (137); ethylenediaminetetraacetic acid (138); l a c t i c acid (138); blends of hydroxylamine hydrochloride, c i t r i c acid, and glucono-delta-lactone (139); n i t r i l o a c e t i c acid; blends of c i t r i c acid and acetic acid; l a c t i c acid; and gluconic acid (140). Diverting agents a s s i s t i n d i s t r i b u t i n g acid more uniformly through the perforated formation i n t e r v a l (141). These are usually o i l soluble hydrocarbon r e s i n p a r t i c l e s . They may be dissolved by post-acid i n j e c t i o n of xylene or s i m i l a r solvents. O i l - s o l u b l e waxes, naphthalene, and s o l i d organic acids such as benzoic acid have also been used (142). Best r e s u l t s are obtained using a broad range of p a r t i c l e sizes. Blends of sodium hypochlorite with 15% HCl and with 12% HCl/3% HF have been used to stimulate aqueous f l u i d i n j e c t i o n wells(143). Waterflood i n j e c t i o n wells have also been stimulated by i n j e c t i n g linear alcohol propoxyethoxysulfate s a l t s i n the absence of any acid (144). The o i l near the well bore i s mobilized thus increasing the r e l a t i v e permeability of the rock to water (145). Temperature e f f e c t s on i n t e r f a c i a l tension and on surfactant s o l u b i l i t y can be a c r i t i c a l factor i n surfactant s e l e c t i o n f o r t h i s application (146). Corrosion i n h i b i t i o n i s primarily associated with a c i d i z i n g . Buffered hydrofluoric acid compositions have been shown to be less corrosive (147). Corrosion i n h i b i t o r s are designed to reduce the rate of reaction of f l u i d with metal surfaces, generally by forming films on the surfaces. Acetylenic alcohols and amines are f r e quently components of corrosion i n h i b i t o r blends. Other compounds that have been used include nitrogen heterocyclics, substituted thioureas, thiophenols, and alpha-aminoalkyl thioethers (148). Arsenic compounds can be very e f f e c t i v e corrosion i n h i b i t o r s but t h e i r t o x i c i t y , ineffectiveness i n hydrochloric acids above 17% active and i n the presence of H«S, and t h e i r a b i l i t y to poison refinery catalysts has limited t h e i r use (148). Epoxy resins have been coated onto metal surfaces and cured with a polyamine to reduce corrosion (149). High density brine completion f l u i d s also often require the use of corrosion i n h i b i t o r s (8,9). Blends of thioglycolates and thiourea; a l k y l , alkenyl, or alkynyl phosphonium s a l t s ; thiocyanate s a l t s ; mercaptoacetic acid and i t s s a l t s ; and the reaction products of pyridine or pyrazine derivatives with dicarboxylic acid monoanhydrides have been used as high density brine corrosion inhibitors. Hydrogen s u l f i d e promoted corrosion can be a serious problem (150); the best solution i s prevention. Corrosion problems can be minimized by choice of the proper grades of s t e e l or corrosion resistant a l l o y s , usually containing chromium or n i c k e l (150, 151) and avoiding generation of H«S by s u l f a t e reducing bacteria i n situations where H^S i s not i n i t i a l l y present. Cathodic protection of casing i s often e f f e c t i v e for wells less than 10,000 feet deep (150).


17

18

OIL-FIELD CHEMISTRY

Scale i n h i b i t o r s may also be used i n a c i d i z i n g . These include alcohol ethoxysulfonic acids (152). Scale i n h i b i t o r s are also used in water and enhanced o i l recovery i n j e c t i o n wells and include low molecular weight poly(vinylsulfonate), polymethylmethacrylate-coethylenediamine) (153), bis(phosphonomethylene)aminomethylene carboxylic acid, and p o l y ( a c r y l i c acid-co-3-acrylamido-3-methylbutanoic acid). Ethylenediaminetetraacetic acid and similar complex-ing agents have been used to remove scale from formation surfaces near wellbores.


Formation Damage Control Chemicals The f l u i d flow capacity of rock, p a r t i c u l a r l y the rock adjacent to an o i l or gas well i s c r i t i c a l i n determining well productivity. The region near the wellbore acts as a choke for the entire forma t i o n ; because the flow i s r a d i a l more and more f l u i d i s flowing through a given volume of rock as the f l u i d approaches the well bore. The reduction of the rock f l u i d carrying capacity i s referred to as formation damage. Formation damage may be due to invasion of rock c a p i l l a r i e s by s o l i d p a r t i c l e s i n wellbore f l u i d s ( d r i l l i n g and completion f l u i d s ) and plugging of rock c a p i l l a r i e s adjacent to fractures by fine s o l i d p a r t i c l e s i n fracturing f l u i d s . These fines may be generated when sand-laden fracturing f l u i d passes through small o r i f i c e s such as choke valves at high flow rates and pressures (67) or by proppant crushing within the fracture. They may also be due to the use of s o l i d f l u i d loss additives. This type of formation damage may be reduced by f i l t r a t i o n of f l u i d s before t h e i r entry into the well bore and by proper choice and s i z i n g of s o l i d p a r t i c l e s used in d r i l l i n g , gravel packing, and fracturing f l u i d s . Acidizing the rock immediately adjacent to the wellbore can dissolve clays, s i l i c a p a r t i c l e s , and precipitates plugging rock flow channels. However, p r e c i p i t a t i o n of hydrated s i l i c a , fluoroaluminates, and iron compounds (above pH 2.2) i n a c i d i z i n g can cause formation damage reducing well treatment effectiveness (see above). Reduced i n j e c t i v i t y due to formation damage can be a s i g n i f i c a n t problem i n i n j e c t i o n wells. Precipitate formation due to ions present i n the i n j e c t i o n water contacting counterions i n formation f l u i d s , s o l i d s i n i t i a l l y present i n the i n j e c t i o n f l u i d (scaling), b a c t e r i a l corrosion products, and corrosion products from metal surfaces i n the i n j e c t i o n system can a l l reduce permeability near the wellbore (153). The consequent reduced i n j e c t i o n rate can r e s u l t i n a lower rate of o i l production at offset wells. Dealing with corrosion and b a c t e r i a l problems, compatibility of ions i n the i n j e c t i o n water and formation f l u i d s , and f i l t r a t i o n can a l l a l l e v i a t e formation damage. Formation damage can also be caused by chemical and physical interactions of f l u i d and rock. Low s a l i n i t y f l u i d s can cause swelling of water-expandable clays. The resulting larger clay dimensions can reduce the f l u i d carrying capacity of rock flow channels. The expanded clay p a r t i c l e s are more susceptible to the shear forces of flowing f l u i d s . In addition, clays act as the cementing medium i n many sandstone formations. Swelling weakens t h i s cementation and can cause the release of mineral f i n e



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p a r t i c l e s . Fines migration i n Berea sandstone occurs when the s a l i n i t y of the flowing phase drops below a c r i t i c a l s a l t concentration (CSC) (155,156). The CSC varies f o r d i f f e r e n t monovalent cations i n solution and decreases with increasing ion exchange a f f i n i t y of the clay for the cation. The CSC of multivalent cations i s very low (157). Flowing f l u i d s can carry these f i n e p a r t i c l e s to constrictions i n the flow channels where they form a plug. Inorganic s a l t s ; KC1, NH^Cl, CaCl^, or high concentrations of NaCl have been used i n wellbore f l u i d s , fracturing f l u i d s , and i n j e c t i o n f l u i d s to temporarily reduce formation damage by converting the more water-expandable smectite and mixed layer clays to less swelling forms through ion exchange processes. However, the potassium, ammonium, or calcium ions on the clays are themselves subject to ion exchange processes and the clays may l a t e r be converted back to the more water-expandable sodium form. Once clay swelling has occurred, i n j e c t i o n of s a l t s w i l l not reverse forma t i o n damage. An a c i d i z i n g treatment to p a r t i a l l y dissolve the clays i s required for t h i s . The addition of potassium hydroxide to i n j e c t i o n waters has been used to s t a b i l i z e clays and maintain i n j e c t i v i t y (158). Some degree of permanence appears to r e s u l t from t h i s treatment since i n j e c t i v i t y appeared to be substantially maintained during subse-quent i n j e c t i o n of low s a l i n i t y water. More permanent s t a b i l i z a t i o n of water-swelling clays may be achieved by bonding the clay surface cation exchange s i t e s together so that simultaneous ion exchange at a large number of s i t e s i s required for desorption of the clay s t a b i l i z e r . This may be accom plished by i n j e c t i o n of hydroxyaluminum, z i r c o n y l chloride, or certain quaternary ammonium s a l t polymers. A 6-12 hour well shut-in period i s required to allow polymerization of hydroxyalumi num on formation surfaces to occur (159). Because hydroxyaluminum i s removed from mineral surfaces by f l u i d s at pH

Chemicals Used in Oil-Field Operations - ACS Publications - American

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