Patent Application
20130126163
The invention relates to a method of hydraulic fracturing a subterranean formation by introducing into the formation a treatment fluid containing a viscosifying agent and aphrons.
Hydraulic fracturing is a common stimulation technique used to enhance production of fluids from subterranean formations in oil, gas and geothermal wells. In a typical hydraulic fracturing treatment operation, a fracturing fluid is pumped at high pressures and high rates into a wellbore penetrating a subterranean formation to initiate and propagate a fracture in the formation. The treatment fluid typically contains proppant which is deposited in the fracture. The proppant serves to hold the fracture open and provides a highly conductive pathway for hydrocarbons and/or other formation fluids to flow into the wellbore.
Fracturing fluids generally include a viscosifying or gelling agent (such as a polysaccharide material or a viscoelastic surfactant) to increase the viscosity of the fluid and to enhance formation of a proppant bed into the fracture. Such fluids may be linear (non-crosslinked) gels or crosslinked gels. Crosslinked gels more easily build filter cakes, even in high permeability formations, and thus exhibit better fluid loss control and less leak-off to the formation than linear gels. Filter cakes formed from crosslinked gels, however, are known to clog the well, damage proppant bed permeability and invade the formation. In addition, fluids containing crosslinked gels are known to require more extensive well clean up and to leave undesirable traces in the recoverable hydrocarbons that may be expensive to remove.
Since linear gels are less damaging to the formation, they are often preferred over crosslinked fluids. A disadvantage of linear gels, however, is their relative failure to be able to build satisfactory filter cakes. This results in high levels of fluid loss into the formation and typically requires large volumes of fluid for each treatment. Such loss of fracturing fluid into the formation has an effect on the fracture size and geometry created during the operation.
“Foam fracturing” is a specific type of fracturing technique. It can be carried out by generating a foam on the surface and then injecting the foam under pressure into the formation. The foam can be generated on the surface by combining, for example, nitrogen gas or carbon dioxide with an aqueous fluid. Foam fracturing can also be carried out by generating a foam in-situ in the formation. For instance, methods of foam fracturing have been reported in the literature wherein a stabilized liquid-liquid emulsion formed with liquid carbon dioxide is injected into the formation and a stabilized foam is formed in-situ when the gas is heated by the formation. Once the desired fracturing is achieved, pressure is released at the well head causing the foam to expand and exit the well. Like linear gels, however, it is not uncommon for such treatment fluids to be undesirable because of risk of fluid leak-off to the formation.
A need exists therefore for linear fluids and foam fracturing fluids which exhibit greater capability of serving as a fluid barrier in order to reduce fluid leak-off to the formation.
Embodiments of the invention include methods and compositions for the reduction of fluid loss in subterranean formations during hydraulic fracturing.
In one embodiment, the invention relates to a method of fracturing a hydrocarbon-bearing subterranean formation by introducing into the formation a fracturing fluid containing a viscosifying agent and aphrons.
In another embodiment of the invention, the invention relates to a method of fracturing a hydrocarbon-bearing subterranean formation by introducing into the formation a foam fracturing fluid containing a viscosifying agent and aphrons.
In another embodiment of the invention, the invention relates to a method of reducing fluid leak-off into the formation during a fracturing operation by introducing into the formation a treatment fluid containing a viscosifying agent and aphrons.
In another embodiment of the invention, the invention relates to a method of reducing fluid leak-off into the formation during a fracturing operation by introducing into the formation a foam treatment fluid containing a viscosifying agent and aphrons.
In another embodiment, the invention relates to a method of forming a fluid barrier during a fracturing operation by introducing into the formation a fracturing fluid containing a viscosifying agent and aphrons.
In another embodiment, the invention relates to a method of forming a fluid barrier during a fracturing operation by introducing into the formation a foam fracturing fluid containing a viscosifying agent and aphrons.
In another embodiment of the invention, the invention relates to a method of reducing or preventing fluid loss during a fracturing operation by introducing into the formation a fluid containing a linear gel and aphrons.
In another embodiment of the invention, the invention relates to a method of reducing or preventing fluid loss during a fracturing operation by introducing into the formation a foam fluid containing a linear gel and aphrons.
In another embodiment, the invention relates to a method of reducing fluid loss in a sand control operation, such as gravel packing, frac pack treatments, etc. by introducing into the well a fluid containing a viscosifying agent and aphrons.
In another embodiment, the invention relates to a method of reducing fluid loss in a sand control operation, such as gravel packing, frac pack treatments, etc. by introducing into the well a foam fluid containing a viscosifying agent and aphrons.
In order to more fully understand the drawings referred to in the detailed description of the present invention, a brief description of each drawing is presented, in which:
Illustrative embodiments of the invention are described below as they might be employed in a fracturing and sand control operation. In the interest of clarity, not all features of an actual implementation are described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developers' specific goals, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. Further aspects and advantages of the various embodiments of the invention will become apparent from consideration of the following description.
The fracturing method described herein consists of pumping into a subterranean formation a fracturing fluid containing a viscosifying agent and aphrons. The fracturing fluid is effective in the stimulation of low permeability formations where recovery efficiency is limited. For instance, hydraulic fracturing may be used in low permeability gas reservoirs, such as those having an in-situ matrix permeability to gas of 0.5 mD or less. Reservoirs with low in-situ matrix permeability often contain trapped saturated fluids since the reservoir is in contact with mobile water and exhibits capillary equilibrium with the mobile water. Such reservoirs are prevalent in the Deep Basin area in Canada, the Powder River Basin in the central portion of the United States and the Permian Basin in Texas where the average in-situ permeability may be 0.1 mD or less. The productivity of low permeability gas reservoirs is dependent on the proper selection of an appropriate fracturing fluid.
The presence of the aphrons in the fracturing fluids provides high viscosity at low shear rates, e.g., the viscosity of the fluids may be as high as 300,000 cP at 0.01 s−1 or 1400 cP at 20 s−1.
The fluids are helpful in controlling fluid loss by creating a high resistance to movement into the formation openings. As such, the fracturing fluids described herein are especially useful in hydraulic fracturing operations where high leak-off potential exists. Further, the aphrons in the fracturing fluid move faster than the liquid phase of the fluid and thus move toward the front of the fluid as the fluid is being pumped into the formation. The fracturing fluid, unlike a drilling fluid, does not circulate through the well. The bubble barrier and radial-flow pattern of the fluid rapidly reduce the shear rate and raise the fluid viscosity, severely curtailing fluid invasion into the formation. The aphrons thereby plug pore throats in the formation minimizing spurt loss. When pressure is released, aphrons move from the pore throats. The fluids prevent or reduce fluid loss into the formation especially where high leak-off potential exists.
The presence of the aphrons in the fracturing fluid provide increased stability to the fluid, as indicated by an enhanced half-life and thus enhance the ability of the fluid to seal permeable formations.
The preparation and properties of aphrons is described in Felix Sebba, Foams and Biliquid Foams-Aphrons, John Wiley & Sons, 1987, herein incorporated by reference. Aphrons can further be prepared by the methods disclosed in U.S. Pat. Nos. 6,022,727; 5,314,644; 5,397,001; 5,783,118; 5,352,436; 4,162,970; 4,112,025; 4,717,515; 4,304,740; and 3,671,022, each incorporated herein by reference.
Aphrons are considered to be microbubbles composed of a core, typically spherical, or internal phase encapsulated in a thin shell. The shell contains surfactant molecules which are positioned such that they produce an effective barrier against coalescence with adjacent aphrons. Aphrons have been characterized as a core of air and a shell composed of three layers of surfactant molecules and a viscosified aqueous layer. The first phase contains surfactant molecules which provide a barrier against the second phase. The second phase is described as being comprised of viscosified water, an optional stabilizer, and surfactant molecules positioned such that the hydrophobic portion of the molecules extend into a third phase. The third phase is described as containing another layer of surfactant molecules aligned with the hydrophilic (polar) portion extending into the bulk fluid. The third phase then contains a bi-layer of surfactant molecules, which as serve as an effective barrier to coalescence with adjacent aphrons. It is believed that the outermost surfactant layer is not strongly associated with the rest of the aphron and may be shed when aphrons are forced against each other. Since aphrons exhibit little affinity for each other, they may form agglomerates without coalescence. Agglomerated aphrons or polyaphrons have been reported to be stable over a period of months, with no evident phase separation. Not only do such aphrons exhibit little affinity for each other, they exhibit little affinity for the mineral surfaces of the pore or fracture of the formation. Consequently the seal formed by aphrons is soft. The lack of adhesion seen with agglomerated aphrons enables aphrons to be easily removed from pores or fractures after pressure is released.
The surfactant of the aphrons must be compatible with the base liquid and the viscosifying agent of the fracturing fluid such that the low shear rate viscosity of the fluid may be maintained. The aphron-generating surfactant may be anionic, non-ionic, or cationic depending on compatibility with the viscosifier. Preferred anionic foaming surfactants include alkyl sulfates, alpha olefin sulfonates, alkyl (alcohol) ether sulfates, refined petroleum sulfonates, ethoxylated alcohols, amine oxide, betaines and fatty alkanolamides as well as mixtures thereof. Typically these surfactants have an alkyl chain having 8 to about 18 carbon atoms, preferably about 12 to about 16 carbon atoms. Preferred non-ionic surfactants are ethoxylated alcohols and amine oxides having an alkyl chain length of about 10 to about 18 carbon atoms, preferably from about 12 to about 16 carbon atoms.
The aphrons may further contain a surfactant having one or more stabilizers incorporated therein, such as alkyl alcohols, fatty alkanolamides, and alkyl betaines. Generally the alkyl chain will contain from about 10 to about 18 carbon atoms. The aphrons may further contain one or more stabilizers incorporated therein, such as alkyl alcohols, fatty alkanolamides, and alkyl betaines. Generally the alkyl chain will contain from about 10 to about 18 carbon atoms.
The aphrons contain a wide size distribution ranging up to about 200 um in diameter, typically between from about 25 um to about 200 um.
The quantity of aphrons in the fluid depends on the density required. Generally, the fluid will contain less than about 20% by volume aphrons, preferably less than about 15% by volume of aphrons.
The fracturing fluid contains a viscosifying agent. Suitable viscosifying agents include polymeric gels and viscoelastic surfactants. The polymeric gels are preferably linear, i.e., not crosslinked. Incorporation of aphrons into a linear gel provides a fracturing fluid with increased viscosity at low shear rates and low viscosity at high shear rates. The aphrons further extend the power law region beyond that would normally be trending toward a Newtonian fluid behavior at shear rates less than 20 sec−1.
Suitable polymers include hydratable polysaccharides such as galactomannan gums (including underivatized guars and derivatized guars), cellulose and cellulose derivatives, starch, starch derivatives, xanthan, derivatized xanthan and mixtures thereof. In a preferred embodiment, the viscosifying polymer is a guar or derivatized guar. Guar and derivatized guar provide.
The polysaccharide is preferably selected from the group consisting of guar, carrageenan, xanthan and derivatives thereof, gum Arabic, gum ghatti, karaya, tragacanth, pectin, starch, locust bean gum, welan gum, karaya gum, scleroglucan, diutan, tamarind and chemically modified derivatives of these gums including derivatives of cellulose such as the pendent derivatives hydroxyethyl, hydroxypropyl, hydroxypropylcarboxymethyl, hydroxyethylcarboxymethyl, carboxymethyl or methyl.
Specific examples of polysaccharides useful in the present invention include but are not limited to underivatized guar, hydroxypropyl guar, carboxymethyl guar, carboxymethyl hydroxypropyl guar, carboxymethyl hydroxypropyl guar and known derivatives of these gums. Specific cellulosic derivatives include hydroxyethyl cellulose (HEC), carboxymethyl hydroxyethyl cellulose (CMHEC), carboxymethyl cellulose (CMC), as well as dialkyl carboxymethyl celluloses.
The xanthan may be an unmodified xanthan gum, non-acetylated xanthan gum, non-pyruvylated xanthan gum or non-acetylated-non-pyruvylated xanthan gum. The non-pyruvylated xanthan gums include those xanthenes with and without acetate substituents. Preferred are conventional xanthan and non-acetylated xanthan gums. Suitable xanthan gums include such conventional xanthan gums as native xanthan gums, like those described in U.S. Pat. Nos. 3,020,206, 3,020,207, 3,391,060 and 4,154,654, all of which are herein incorporated by reference.
Suitable viscoelastic surfactants are those which are capable of providing the requisite width to the initiated fracture. The viscoelastic surfactant may be micellular, such as worm-like micelles, surfactant aggregations or vesicles, lamellar micelles, etc. Such micelles include those set forth in U.S. Patent No. 6,491,099; 6,435,277; 6,410,489; and 7,115,546, herein incorporated by reference.
The viscoelastic surfactant may be a cationic, amphoteric or anionic surfactant. Suitable cationic surfactants include those having only a single cationic group which may be of any charge state (e.g., the cationic group may have a single positive charge or two positive charges). The cationic group preferably is a quaternary ammonium moiety (such as a linear quaternary amine, a benzyl quaternary amine or a quaternary ammonium halide), a quaternary sulfonium moiety or a quaternary phosphonium moiety or mixtures thereof. Preferably the quaternary group is quaternary ammonium halide or quaternary amine, most preferably, the cationic group is quaternary ammonium chloride or a quaternary ammonium bromide.
The amphoteric surfactant preferably contains a single cationic group. The cationic group of the amphoteric surfactant is preferably the same as those listed in the paragraph above. The amphoteric surfactant may be one or more of glycinates, amphoacetates, propionates, betaines and mixtures thereof. Preferably, the amphoteric surfactant is a glycinate or a betaine and, most preferably, the amphoteric surfactant is a linear glycinate or a linear betaine.
The cationic or amphoteric surfactant has a hydrophobic tail (which may be saturated or unsaturated). Preferably the tail has a carbon chain length from about C12-C18. Preferably, the hydrophobic tail is obtained from a natural oil from plants, such as one or more of coconut oil, rapeseed oil and palm oil. Exemplary of preferred surfactants include N,N,N trimethyl-1-octadecammonium chloride: N,N,N trimethyl-1-hexadecammonium chloride; and N,N,N trimethyl-1-soyaammonium chloride, and mixtures thereof.
Exemplary of anionic surfactants are sulfonates, phosphonates, ethoxysulfates and mixtures thereof. Preferably the anionic surfactant is a sulfonate. Most preferably the anionic surfactant is a sulfonate such as sodium xylene sulfonate and sodium naphthalene sulfonate.
In one preferred embodiment, a mixture of surfactants are utilized to produce a mixture of (1) a first surfactant that is one or more cationic and/or amphoteric surfactants set forth above and (2) at least one anionic surfactant set forth above.
The viscosifying agent is present in the fracturing fluid in an amount sufficient to impart to the fluid the desired low shear rate viscosity. Generally the fluids will contain a concentration from about 1.4 kg/m3 (0.5 ppb) to about 28.5 kg/m3 (10 ppb), preferably from about 2.85 kg/m3 (1.0 ppb) to about 14.3 kg/m3 (5.0 ppb).
The aqueous liquid of the fracturing fluid may be fresh water, sea water, or a brine containing soluble salts such as sodium chloride, potassium chloride, calcium chloride, magnesium chloride, sodium bromide, potassium bromide, calcium bromide, zinc bromide, sodium formate, potassium formate, cesium formate, and mixtures thereof. The brine may contain one or more soluble salts at any desired concentration up to saturation. Indeed, super saturated brines can be utilized where a solids free fluid is not desired or required.
The fracturing fluid may further contain stabilizers, such as those capable of enhancing the ability of the fluid to seal openings in the formation. Suitable stabilizers include those set forth in U.S. Pat. No. 7,037,881, herein incorporated by reference, and include biopolymer/magnesium oxide/sodium chloride, polyacrylamide/chromic acetate, doubly derivatized HEC/Fe2, liquid rubber bases, liquid wax bases, water soluble glues (e.g. Elmer's glue), polyvinyl alcohol (PVOH)/alkyl ether sulfates, PVOH/betaines, and mixtures thereof. When present, the stabilizer is typically present in an amount between from about 0.05% to about 2% of the net weight of the fluid composition, preferably from about 0.1% to 1%.
The fracturing fluid may further contain one or more well treatment agents, such as corrosion inhibitors, biocides, fungicides, lubricity additives, shale control additives, etc.
The fracturing fluids should have a basic pH. The pH can be obtained as is well known in the art by the addition of bases to the fluid, such as potassium hydroxide, potassium carbonate, sodium hydroxide, sodium carbonate, magnesium hydroxide, magnesium oxide, calcium oxide, calcium hydroxide, zinc oxide, and mixtures thereof
The well treatment fluid used herein may further be energized (containing less than or equal to 53 volume percent of foaming agent) or foamed with a gas (containing more than 53 volume percent of foaming agent). In a preferred embodiment, the amount of foaming agent in the treatment fluid is such to provide an energized fluid between from about 20% to 50% by volume of internal gas or a foamed fluid having from about 63 to about 94% by volume of internal gas. While nitrogen and liquid CO2 are more common for use as the suitable foaming agent for foamed and energized fluids, any other gas or fluid, such as inert gases, like argon, or natural gas, known in the art may be utilized. Foamed and energized fluids reduce the density by reducing the amount of water without loss of treatment fluid volume and increase the viscosity of the well treatment fluid. Their use is especially desirable when treating a subterranean formation which is sensitive to water (such as under-pressured gas reservoirs like dry coal beds and wells which are which are rich in swellable and migrating clays)) where it is desired to minimize the amount of water in the fluid. The presence of the gas in the well treatment fluid is especially effective in controlling leak-off into the natural and created fractures as well as providing increased viscosity to the fluid while minimizing the amount of water pumped into the formation.
In some instances, it may be desirable to add a non-gaseous foaming agent to the treatment fluid. When used, such non-gaseous foaming agents are typically used in conjunction with a foaming gas. Non-gaseous foaming agents often contribute to the stability of the resulting fluid and reduce the requisite amount of water in the fluid. In addition, such agents typically increase the viscosity of the fluid. For instance, when the amount of internal gas in the treatment fluid exceeds 30% by volume, a non-gaseous foaming agent may further be added to the fluid in order to create a foamed fluid. The addition of a non-gaseous foaming agent typically increases the viscosity of the treatment fluid. In addition to increasing viscosity, the non-gaseous foaming agent further contributes to the stability of the resulting fluid. Non-gaseous foaming agents may be amphoteric, cationic or anionic and may include surfactants based on betaines, alpha olefin sulfonates, sulfate ethers, ethoxylated sulfate ethers and ethoxylates.
Suitable anionic non-gaseous foaming agents include alkyl ether sulfates, ethoxylated ether sulfates, phosphate esters, alkyl ether phosphates, ethoxylated alcohol phosphate esters, alkyl sulfates and alpha olefin sulfonates. Preferred as alpha-olefin sulfonates are salts of a monovalent cation such as an alkali metal ion like sodium, lithium or potassium, an ammonium ion or an alkyl-substituent or hydroxyalkyl substitute ammonium in which the alkyl substituents may contain from 1 to 3 carbon atoms in each substituent. The alpha-olefin moiety typically has from 12 to 16 carbon atoms.
Preferred alkyl ether sulfates are also salts of the monovalent cations referenced above. The alkyl ether sulfate may be an alkylpolyether sulfate and contains from 8 to 16 carbon atoms in the alkyl ether moiety. Preferred as anionic surfactants are sodium lauryl ether sulfate (2-3 moles ethylene oxide), C8-C10 ammonium ether sulfate (2-3 moles ethylene oxide) and a C14-C16 sodium alpha-olefin sulfonate and mixtures thereof. Especially preferred are ammonium ether sulfates.
Suitable cationic non-gaseous foaming agents include alkyl quaternary ammonium salts, alkyl benzyl quaternary ammonium salts and alkyl amido amine quaternary ammonium salts.
Preferred as non-gaseous foaming agent are alkyl ether sulfates, alkoxylated ether sulfates, phosphate esters, alkyl ether phosphates, alkoxylated alcohol phosphate esters, alkyl sulfates and alpha olefin sulfonates.
The following examples are illustrative of some of the embodiments of the present invention. Other embodiments within the scope of the claims herein will be apparent to one skilled in the art from consideration of the description set forth herein. It is intended that the specification, together with the examples, be considered exemplary only, with the scope and spirit of the invention being indicated by the claims which follow.
All percentages set forth in the Examples are given in terms of weight units except as may otherwise be indicated.
The following components were used in the Examples:
Go Devil II™, a blend comprising approximately 70 wt % xanthan gum, 20 wt % starch, 9 wt % oligosaccharide and 1 wt % magnesium oxide, sold by MASI Technologies, LLC;
Activator I™ (“Act I”) is comprised of approximately 90 wt % oligosaccharide and 10 wt % magnesium oxide, sold by MASI Technologies, LLC;
Activator II (“Act II”) is a pH buffer and is a magnesium oxide-based blend comprised of approximately 90 wt % magnesium oxide and 10 wt % oligosaccharide, sold by MASI Technologies, LLC;
Actiguard™ (“ACT”) is a shale inhibitor composed of approximately 61 wt % cottonseed oil, 36 wt % lecithin, and 3 wt % Tergitol 15-S-5™. Actiguard is a product of MASI Technologies, LLC;
Blue Streak™ is a surfactant of approximately 18 wt % alcohol ether sulfate, 8 wt % cocobetaine, 1 wt % hydroxypropylguar, and 73 wt % water, sold by MASI Technologies, LLC;
Aphronizer A™ is 80% alkylether sulfate, amine salt, 10% propylene glycol, 5% alkoxylated alcohol and 5% water, a product of MASI Technologies, LLC;
Aphronizer B™ is polyvinyl alcohol, a product of MASI Technologies, LLC;
GW-4 is soluble standard guar, a product of Baker Hughes Incorporated;
GW-38 is carboxymethylhydroxylpropyl guar, a product of Baker Hughes Incorporated;
GLFC-5D is a high yield guar in mineral oil, concentration of dry polymer (GW-3) in slurry is 4 lbs/1,000 gallons fluid a product of Baker Hughes Incorporated; and
Plasticizer (“P”) is an aphron shell enhancer.
Aqueous blends were prepared as set forth in Table I:
Each of the fluids was prepared in a Waring blender. The water was initially sheared to approximately 1500 rpm after the addition of each component. The fluid was allowed to mix for 2 minutes, and the shear rate was then adjusted to maintain a good vortex in the fluid. After the addition of the last component, BlueStreak, the shear rate was increased until the fluid foamed to the desired volume. In some instance, air was introduced to the fluid using an air hose while the fluid was mixed to attain the required foam volume.
The contents were then poured into an OFITE sample cup and the viscosity of the linear gel was determined on a Model 900 viscometer, commercially available from OFI Testing Equipment, Inc. (OFITE), at 1, 3, 6, 10, 30, 60, 100 and 300 rpm using a R1B1 rotor-bob configuration@ 511 sec−1. The results are illustrated in
The rheology of fluids was evaluated in a Fann 50 viscometer equipped with a R1 B5 rotor-bob (radius=1.8415 cm; length=14.240 cm) and bob (radius=1.5987 cm; length=8.7280 cm) assembly. The method used is defined in the American Petroleum Institute's ANSI/API Recommended Practice 13M. The fluid was initially sheared at 100 sec−1 followed by a shear rate sweep of 100, 80, 60 and 40 sec−1 to calculate the power law indices n′ and K′. The fluid was sheared at 100 sec−1 in between shear rate sweeps, and the shear rate sweep was repeated every 30 minutes. The testing was configured to run temperature ramps from 75-250° F., with temperature increasing 25° F. every 30 minutes. The results are shown in
Foams F2, F5, F6 and F8 were prepared by placing 175 ml of fluid into a Waring 1 L Blender and adding nitrogen. The blender was covered and the mixture blended at high speed for 20 seconds. The content of the blender was then poured instantly into a 100 ml graduated cylinder and a stopwatch was started. Foam half-life time is recorded when 50 ml of liquid drains to the bottom of the cylinder, i.e., the amount for the fluid to lose half of the entrained air at room temperature and pressure.
The foam quality, Q, was calculated as follows:
Tables I, II, III and IV show the results of a 70 foam quality of F2 (foamed to 600 mL), F5 (foamed to 500 mL), F6 (foamed to 500 mL) and F8 (foamed to 400 mL), respectively. The maximum observed fluid volume for F2, F6 and F8 was 16 mL and the maximum observed fluid volume for F5 was 21 mL.
The Tables show that replacing the Go Devil II polymer with GW-38 or GW-4 provided less foam height and a shorter foam half-life than the formulation with 2ppb Go Devil II.
The rheology of the fluids in Table V was evaluated using a flow-loop rheometer at 30° C.
A 70 quality foam for each of F10, F11, F12 and F13 was obtained by loading 95 mls of the fluid into the flow-loop which had a 312 ml capacity. The balance was then filled with 70 vol. % N2 gas. After the N2 was added, the fluid in the circulation loop was foamed/emulsified by shearing it with the aid of the nozzle and the temperature increased with the heating jacket on the loop. The pressure was 1,000 psi to more closely simulate well conditions. After the N2 was added, the fluid in the circulation loop was foamed/emulsified by shearing it with the aid of the nozzle and the temperature increased with the heating jacket on the loop. The foam loop was designed to simulate down hole conditions by measuring the rheology of the foam after exposure to the bottom hole temperature for either 30, 60 or 90 minutes. All of the compounds of the formulation were batch mixed except the crosslinker, which is injected “on the fly.” The foam was ranked from 1-10 on foam stability, based upon visual inspection, according to the following scale:
1-3 Extreme gas breakout. Severe slug flow;
4-5 Gas breakout at intermittent intervals. Usually will have larger bubble size;
6-7 A few bubbles of gas breakout, Good foam with small and medium bubble sizes; and
8-10 Good foam. No gas breakout. Small bubble size. Shaving cream texture. F10 at 200° F. did not show a stable foam at 250° F.; Flt exhibited a foam ranking of 3 and 674 cP at 40 sec−1; F12 exhibited poor foam properties; and F12 had a ranking of 4.5 and 726 cP at 40 sec−1.
From the foregoing, it will be observed that numerous variations and modifications may be effected without departing from the true spirit and scope of the novel concepts of the invention.
