Classifications

• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/92—Compositions for stimulating production by acting on the underground formation characterised by their form or by the form of their components, e.g. encapsulated material
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/82—Oil-based compositions

Definitions

• the invention relates generally to viscosifiable, low thermal conductivity annular fluids and methods of viscosifying, emplacing, and removing the fluids.
• Annular fluids or packer fluids are liquids which are pumped into annular openings such as, for example, (1) between a wellbore wall and one or more casing strings of pipe extending into a wellbore, or (2) between adjacent, concentric strings of pipe extending into a wellbore, or (3) in one or both of an A- or B-annulus in a wellbore comprising at least an A- and B-annulus with one or more inner strings of pipe extending into a said wellbore, which may be running in parallel or nominally in parallel with each other and may or may not be concentric or nominally concentric with the outer casing string, or (4) in one or more of an A-, B- or C- annulus in a wellbore comprising at least an A-, B- and C-annulus with one or more inner strings of pipe extending into a said wellbore, which may be running in parallel or nominally in parallel with each other and may or may not be concentric or nominally concentric with the outer casing string
• said one or more strings of pipe may simply run through a conduit or outer pipe(s) to connect one or more wellbores to another wellbore or to lead from one or more wellbores to a centralized gathering or processing center; and said annular fluid may have been emplaced within said conduit or ⁇ ipe(s) but external to said one or more strings of pipe therein.
• Insulating annular fluids or insulating packer fluids are annular fluids or packer fluids used to control heat loss - both conductive and convective heat losses. These insulating annular or packer fluids are especially necessary in oil or gas well construction operations conducted in low temperature venues of the world, for example, those areas having permafrost.
• Permafrost is a thick layer of frozen surface ground found often in arctic or antarctic regions, which frozen ground may be several hundred feet thick and presents a great obstacle to the removal of relatively warm fluids through a well pipe penetrating said frozen ground.
• warm fluid in the well pipe causes thawing of the permafrost in the vicinity of the well resulting in subsidence which can irreparably impair the permafrost environment and impose compressive and/or tension loads high enough to rupture or collapse the well casing and hence allow the escape of well fluids.
• the warm gas or oil coming to the surface in the well pipe becomes cooled by giving up its heat to the permafrost.
• gas hydrate crystals may form, which can freeze together and block the well pipe; alternatively, wax or asphaltenes may form, which can agglomerate and block the well pipe.
• annular heat loss is due to convection and to conduction.
• Heavy oil production is another operation which often can benefit from the use of an insulating annular fluid.
• a high-pressure steam or hot water is injected into the well and the oil reservoir to heat the fluids in the reservoir, causing a thermal expansion of the crude oil, an increase in reservoir pressure and a decrease of the oil's viscosity.
• damage to the well casing may occur when heat is transferred through the annulus between the well tubing and the casing.
• the resulting thermal expansion of the casing can break the bond between the casing and the surrounding cement, causing leakage.
• an insulating medium such as a packer fluid may be used to insulate or to help insulate the well tubing.
• the packer fluid also reduces heat loss and saves on the energy requirements in stimulation using hot-water or steam (huff-n-puff) or in hot-water- or steam- flooding.
• subsea fields In addition to steam injection processes and operations which require production through a permafrost layer, subsea fields —especially, subsea fields in deep water, 1 ,500 to more than 6,000 feet deep - require specially designed systems, which typically require an insulating annular or packer fluid.
• a subsea oil reservoir temperature may be between about 120 0 F and 250 0 F, while the temperature of the water through which the oil must be conveyed is often as low as 32°F to 50 0 F. Conveying the high temperature oil through such a low temperature environment can result in oil temperature reduction and consequently the separation of the oils into various hydrocarbon fractions and the deposition of paraffins, waxes, asphaltenes, and gas hydrates. The agglomeration of these oil constituents can cause blocking or restriction of the wellbore, resulting in significant reduction or even catastrophic failure of the production operation.
• U.S. Pat. No. 3,613,792 describes an early method of insulating wellbores.
• simple fluids and solids are used as the insulating medium.
• U.S. Pat. No. 4,258,791 improves on these insulating materials by disclosing an oleaginous liquid such as topped crude oils, gas oils, kerosene, diesel fluids, heavy alkylates, fractions of heavy alkylates and the like in combination with an aqueous phase, lime, and a polymeric material.
• 4,528,104 teaches a packer fluid comprised of an oleaginous liquid such as diesel oil, kerosene, fuel oil, lubricating oil fractions, heavy naphtha and the like in combination with an organophillic clay gellant and a clay dispersant such as a polar organic compound and a polyfunctional amino-silane.
• an oleaginous liquid such as diesel oil, kerosene, fuel oil, lubricating oil fractions, heavy naphtha and the like in combination with an organophillic clay gellant and a clay dispersant such as a polar organic compound and a polyfunctional amino-silane.
• the present disclosure relates to a method for emplacing a packer fluid into an annulus that includes preparing the packer fluid, where the packer fluid includes a hydrocarbon fluid, and a micronized weighting agent; and then pumping the packer fluid into the annulus.
• the present disclosure relates to a method of stimulating a well that includes injecting a gas into an annular fluid, where the fluid includes a hydrocarbon fluid, and a micronized weighting agent is also disclosed.
• Embodiments of the present disclosure relate to insulating packer fluids and methods of preparing and emplacing such fluids.
• Packer fluids according to the present disclosure have good long-term insulation properties, because they resist syneresis and separation of various components into separate phases, and have low thermal conductivities and unique rheological properties that minimize their movement once they are emplaced - and this minimization of movement, in turn, minimizes convective heat loss.
• a majority of annular heat loss is due to convection and conduction.
• Heat loss due to thermal conductivity may be controlled by proper selection of fluids, i.e., fluids with low thermal conductivities, while heat loss due to convection can be arrested or substantially diminished by increased viscosities of the fluids.
• thermal conductivities as low as 0.07 btu/(hrft-°F) can be obtained with gelled diesel or other hydrocarbon-based insulating annular fluid.
• disclosed embodiments relate to insulating packer fluids, and methods of emplacing and subsequently removing such fluids.
• Packer fluids according to embodiments disclosed herein may have relatively high densities, and may be adapted to survive in high temperature and/or high pressure wells.
• insulating packer fluids in accordance with disclosed embodiments comprise oil-based (hydrocarbon-based) fluids, comprising micronized weighting agents, because oil-based fluids typically have very low thermal conductivities.
• thermal conductivities as low as 0.07 btu/(hrft- o F) can be obtained with gelled diesel or other hydrocarbon-based insulating annular fluids.
• Fluids used in embodiments disclosed herein may include micronized weighting agents.
• the micronized weighting agents may be uncoated.
• the micronized weighting agents may be coated with a dispersant.
• fluids used in some embodiments disclosed herein may include dispersant coated micronized weighting agents.
• the coated weighting agents may be formed by either a dry coating process or a wet coating process.
• Weighting agents suitable for use in other embodiments disclosed herein may include those disclosed in U.S. Patent Application Publication Nos. 20040127366, 20050101493, 20060188651, U.S. Patent Nos. 6,586,372 and 7,176,165, and U.S. Provisional Application Serial No. 60/825,156, each of which is hereby incorporated by reference.
• Micronized weighting agents used in some embodiments disclosed herein may include a variety of compounds well known to one of skill in the art.
• the weighting agent may be selected from one or more of the materials including, for example, barium sulphate (barite), calcium carbonate (calcite), dolomite, ilmenite, hematite or other iron ores, olivine, siderite, manganese oxide, and strontium sulphate.
• barium sulphate barite
• calcium carbonate calcite
• dolomite ilmenite
• hematite or other iron ores olivine
• siderite manganese oxide
• manganese oxide and strontium sulphate
• the micronized weighting agent may have a dgo ranging from 1 to 25 microns and a d 5 o ranging from 0.5 to 10 microns.
• the micronized weighting agent includes particles having a d 90 ranging from 2 to 8 microns and a d 5 o ranging from 0.5 to 5 microns.
• the weighting agent may have a particle size distribution other than a monomodal distribution. That is, the weighting agent may have a particle size distribution that, in various embodiments, may be monomodal, which may or may not be Gaussian, bimodal, or polymodal.
• weighting agent particles must be sufficiently small to avoid issues of sag, but not so small as to have an adverse impact on rheology.
• weighting agent (barite) particles meeting the particle size distribution criteria disclosed herein may be used without adversely impacting the rheological properties of the wellbore fluids.
• a micronized weighting agent is sized such that: particles having a diameter less than 1 microns are 0 to 15 percent by volume; particles having a diameter between 1 microns and 4 microns are 15 to 40 percent by volume; particles having a diameter between 4 microns and 8 microns are 15 to 30 by volume; particles having a diameter between 8 microns and 12 microns are 5 to 15 percent by volume; particles having a diameter between 12 microns and 16 microns are 3 to 7 percent by volume; particles having a diameter between 16 microns and 20 microns are 0 to 10 percent by volume; particles having a diameter greater than 20 microns are 0 to 5 percent by volume.
• the micronized weighting agent is sized so that the cumulative volume distribution is: less than 10 percent or the particles are less than 1 microns; less than 25 percent are in the range of 1 microns to 3 microns; less than 50 percent are in the range of 2 microns to 6 microns; less than 75 percent are in the range of 6 microns to 10 microns; and less than 90 percent are in the range of 10 microns to 24 microns.
• Particles having these size distributions may be obtained by several means.
• sized particles such as a suitable barite product having similar particle size distributions as disclosed herein, may be commercially purchased.
• a coarser ground suitable material may be obtained, and the material may be further ground by any known technique to the desired particle size.
• Such techniques include jet-milling, ball milling, high performance wet and dry milling techniques, or any other technique that is known in the art generally for milling powdered products.
• appropriately sized particles of barite may be selectively removed from a product stream of a conventional barite grinding plant, which may include selectively removing the fines from a conventional API-grade barite grinding operation. Fines are often considered a by-product of the grinding process, and conventionally these materials are blended with courser materials to achieve API-grade barite. However, in accordance with the present disclosure, these byproduct fines may be further processed via an air classifier to achieve the particle size distributions disclosed herein.
• the micronized weighting agents may be formed by chemical precipitation. Such precipitated products may be used alone or in combination with mechanically milled products.
• the micronized weighting agents include solid colloidal particles having a deflocculating agent or dispersant coated onto the surface of the particle.
• colloidal refers to a suspension of the particles, and does not impart any specific size limitation. Rather, the size of the micronized weighting agents of the present disclosure may vary in range and are only limited by the claims of the present application.
• the micronized particle size generates high density suspensions or slurries that show a reduced tendency to sediment or sag, while the dispersant on the surface of the particle controls the inter-particle interactions resulting in lower rheological profiles.
• the combination of high density, fine particle size, and control of colloidal interactions by surface coating the particles with a dispersant reconciles the objectives of high density, lower viscosity and minimal sag.
• a dispersant may be coated onto the particulate weighting additive during the comminution (grinding) process. That is to say, coarse weighting additive is ground in the presence of a relatively high concentration of dispersant such that the newly formed surfaces of the fine particles are exposed to and thus coated by the dispersant. It is speculated that this allows the dispersant to find an acceptable conformation on the particle surface thus coating the surface. Alternatively, it is speculated that because a relatively higher concentration of dispersant is in the grinding fluid, as opposed to that in a drilling fluid, the dispersant is more likely to be absorbed (either physically or chemically) to the particle surface.
• coating of the surface is intended to mean that a sufficient number of dispersant molecules are absorbed (physically or chemically) or otherwise closely associated with the surface of the particles so that the fine particles of material do not cause the rapid rise in viscosity observed in the prior art.
• dispersant molecules may not actually be fully covering the particle surface and that quantification of the number of molecules is very difficult.
• the weighting agents include dispersed solid colloidal particles with a weight average particle diameter (dso) of less than 10 microns that are coated with a polymeric deflocculating agent or dispersing agent. In other embodiments, the weighting agents include dispersed solid colloidal particles with a weight average particle diameter (d 5 o) of less than 8 microns that are coated with a polymeric deflocculating agent or dispersing agent; less than 6 microns in other embodiments; less than 4 microns in other embodiments; and less than 2 microns in yet other embodiments.
• dso weight average particle diameter of less than 10 microns that are coated with a polymeric deflocculating agent or dispersing agent.
• the weighting agents include dispersed solid colloidal particles with a weight average particle diameter (d 5 o) of less than 8 microns that are coated with a polymeric deflocculating agent or dispersing agent; less than 6 microns in other embodiments; less than 4 microns in other embodiment
• the fine particle size will generate suspensions or slurries that will show a reduced tendency to sediment or sag, and the polymeric dispersing agent on the surface of the particle may control the inter-particle interactions and thus will produce lower rheological profiles. It is the combination of fine particle size and control of colloidal interactions that reconciles the two objectives of lower viscosity and minimal sag. Additionally, the presence of the dispersant in the comminution process yields discrete particles which can form a more efficiently packed filter cake and so advantageously reduce filtration rates.
• Coating of the micronized weighting agent with the dispersant may also be performed in a dry blending process such that the process is substantially free of solvent.
• the process includes blending the weighting agent and a dispersant at a desired ratio to form a blended material.
• the weighting agent may be un-sized initially and rely on the blending process to grind the particles into the desired size range as disclosed above.
• the process may begin with sized weighting agents.
• the blended material may then be fed to a heat exchange system, such as a thermal desorption system.
• the mixture may be forwarded through the heat exchanger using a mixer, such as a screw conveyor. Upon cooling, the polymer may remain associated with the weighting agent.
• the polymer/weighting agent mixture may then be separated into polymer coated weighting agent, unassociated polymer, and any agglomerates that may have formed.
• the unassociated polymer may optionally be recycled to the beginning of the process, if desired, hi another embodiment, the dry blending process alone may serve to coat the weighting agent without heating.
• a sized weighting agent may be coated by thermal adsorption as described above, in the absence of a dry blending process.
• a process for making a coated substrate may include heating a sized weighting agent to a temperature sufficient to react monomelic dispersant onto the weighting agent to form a polymer coated sized weighting agent and recovering the polymer coated weighting agent.
• one may use a catalyzed process to form the polymer in the presence of the sized weighting agent.
• the polymer may be preformed and may be thermally adsorbed onto the sized weighting agent.
• the micronized weighting agent may be formed of particles that are composed of a material of specific gravity of at least 2.3; at least 2.4 in other embodiments; at least 2.5 in other embodiments; at least 2.6 in other embodiments; and at least 2.68 in yet other embodiments.
• a weighting agent formed of particles having a specific gravity of at least 2.68 may allow wellbore fluids to be formulated to meet most density requirements yet have a particulate volume fraction low enough for the fluid to be pumpable.
• embodiments of the micronized weighting agent may include a deflocculating agent or a dispersant.
• the dispersant may be selected from carboxylic acids of molecular weight of at least 150 Daltons, such as oleic acid and polybasic fatty acids, alkylbenzene sulphonic acids, alkane sulphonic acids, linear alpha-olefin sulphonic acids, phospholipids such as lecithin, including salts thereof and including mixtures thereof.
• Synthetic polymers may also be used, such as HYPERMER OM-I (Imperial Chemical Industries, PLC, London, United Kingdom) or polyacrylate esters, for example.
• Such polyacrylate esters may include polymers of stearyl methacrylate and/or butylacrylate. In another embodiment, the corresponding acids methacrylic acid and/or acrylic acid may be used.
• acrylate or other unsaturated carboxylic acid monomers or esters thereof may be used to achieve substantially the same results as disclosed herein.
• the polymeric dispersant may have an average molecular weight from about
• the polymeric dispersant be polymerized prior to or simultaneously with the wet or dry blending processes disclosed herein.
• Such polymerizations may involve, for example, thermal polymerization, catalyzed polymerization, initiated polymerization or combinations thereof.
• weighting agent may be included.
• additional components may be mixed with the weighting agent to modify various macroscopic properties.
• anti-caking agents, lubricating agents, and agents used to mitigate moisture build-up may be included.
• solid materials that enhance lubricity or help control fluid loss may be added to the weighting agents and drilling fluid disclosed herein.
• finely powdered natural graphite, petroleum coke, graphitized carbon, or mixtures of these are added to enhance lubricity, rate of penetration, and fluid loss as well as other properties of the drilling fluid.
• Another illustrative embodiment utilizes finely ground polymer materials to impart various characteristics to the drilling fluid, rn instances where such materials are added, it is important to note that the volume of added material should not have a substantial adverse impact on the properties and performance of the drilling fluids.
• polymeric fluid loss materials comprising less than 5 percent by weight are added to enhance the properties of the drilling fluid.
• suitably sized graphite and petroleum coke are added to enhance the lubricity and fluid loss properties of the fluid.
• less than 5 percent by weight of a conventional anti-caking agent is added to assist in the bulk storage of the weighting materials.
• the particulate materials as described herein may be added to a drilling fluid as a weighting agent in a dry form or concentrated as slurry in an organic liquid.
• an organic liquid should have the necessary environmental characteristics required for additives to oil-based drilling fluids.
• the oleaginous fluid may have a kinematic viscosity of less than 10 centistokes (10 mm 2 /s) at 40 0 C and, for safety reasons, a flash point of greater than 60°C.
• Suitable oleaginous liquids are, for example, diesel oil, mineral or white oils, n-alkanes or synthetic oils such as alpha- olefm oils, ester oils, mixtures of these fluids, as well as other similar fluids known to one of skill in the art of drilling or other wellbore fluid formulation.
• the desired particle size distribution is achieved via wet milling of the courser materials in the desired carrier fluid.
• oleaginous fluid oil-based wellbore fluid
• other additives to create insulating packer fluids in accordance with described embodiments.
• the oleaginous fluid may be a liquid, more preferably a natural or synthetic oil, and more preferably the oleaginous fluid is selected from the group including diesel oil; mineral oil; a synthetic oil, such as hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alkyl ethers of fatty acids; similar compounds known to one of skill in the art; and mixtures thereof.
• diesel oil diesel oil
• mineral oil such as hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alky
• drilling fluids disclosed herein in a manner analogous to those normally used, to prepare oil -based drilling fluids.
• a desired quantity of oleaginous fluid such as a base oil, and a suitable amount of one or more micronized weighting agents are mixed together and any remaining components are added sequentially with continuous mixing.
• annular packer fluids may be formulated having densities up to about 20 ppg.
• weighting agents such as FeO 3
• Typical prior art annular fluids have significantly lower densities, such as about 8 ppg.
• additives that may be included in the wellbore fluids disclosed herein include, for example, gelling agents, wetting agents, organophilic clays, viscosifiers, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents, rheological additives and cleaning agents.
• gelling agents for example, gelling agents, wetting agents, organophilic clays, viscosifiers, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents, rheological additives and cleaning agents.
• gelling agents for example, gelling agents, wetting agents, organophilic clays, viscosifiers, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents, rheological additives and cleaning agents.
• surfactants for example, surfactants, dispersants, interfacial tension reducers, pH buffers
• top oil loss or “top oil separation”
• top oil separation This phenomenon is known as “top oil loss” or “top oil separation”
• gelling agents may be added in an amount of 0.1 % by weight up to about 5% by weight or preferably 0.5% by weight up to about 3.5% by weight or more preferably 1 % by weight up to about 2% by weight.
• a packer fluid comprises a rheological additive, as noted above, added to a hydrocarbon fluid that includes one or more gelling agents, such as phosphoric acid esters in the presence of a ferric or aluminum compound.
• the hydrocarbons may be diesels, paraffin oils, crude oils, kerosene, or mixtures thereof.
• the phosphoric acid esters may have same or different alkyl groups, having various lengths.
• the alkyl groups (i.e., the ester parts) of the phosphoric acid esters have two or more carbon atoms, and preferably at least one of the alkyl groups has 3 to 10 carbon atoms.
• the ferric or aluminum compounds may be organic or inorganic compounds, such as aluminum chloride, aluminum alkoxide, ferric chloride, organometallic complexes of aluminum or iron(III), amine carboxylic acid salts of aluminum or iron(III), etc.
• the phosphoric acid esters having a desired alkyl group may be prepared using phosphorous pentaoxide and triethyl phosphate (TEP) (or other similar phosphate triesters) in the presence of a trace amount of water:
• TEP triethyl phosphate
• the tri-ethyl phosphate ester (TEP) is partially hydrolyzed to produce a phosphoric acid diethyl ester.
• the phosphoric acid diethyl ester is then transesterified with a selected alcohol (ROH) to regenerate a phosphoric acid dialkyl ester having at least one and often two ester alkyl groups derived from the ROH.
• ROH selected alcohol
• the alcohol (ROH) 3 i.e., the length of the alkyl chain R, may be selected to provide the desired hydrophobicity.
• the alcohols (ROH) have 2 or more carbons (i.e., ethanol or higher), and preferably, 2 to 10 carbons, which may be straight or branched chains.
• the phosphoric acid dialkyl esters having the alkyl chain of 2-10 carbons long may be obtained from M-I L.L.C. (Houston, TX) under the trade name of ECF-976.
• the R group may include aromatic or other functional groups, as long as it can still provide proper solubility in the hydrocarbon base fluids.
• phosphoric acid esters may be prepared using phosphorous hemipentaoxide (or phosphorous pentaoxide P 2 Os) and a mixture of long chain alcohols, as disclosed in U.S. Patent No. 4,507,213:
• phosphoric acid esters include mono acid di-esters and di-acid monoesters.
• phosphonic acid esters may also use phosphonic acid esters, as disclosed in U.S. Patent No. 6,51 1,944 issued to Taylor et al.
• a phosphonic acid ester has an alkyl group directly bonded to the phosphorous atom and includes one acid and one ester group.
• gelling agents including anionic polymers, such as poly-(ethylene-co- chloroethylene-co-[sodium chloro ethylene-sulfonate]), or emulsions formed from an emulsifier and a water-miscible internal phase.
• ECF-976 from M-I L.L.C.
• a phosphonic acid ester complexing with a multivalent metal ion e.g., ferric or aluminum ion, or ECF-977 from M-I L.L.C.
• a multivalent metal ion e.g., ferric or aluminum ion, or ECF-977 from M-I L.L.C.
• gelling agents that may be used include oligovinyl pyrolidone, an oil soluble, very mildly cationic ter-polymer, available from International Specialty Products.
• Another suitable additive is EMI-759, available from M-I L.L.C.
• Suitable rheological additives in accordance with embodiments of the present disclosure may include alkyl diamides, such as those having a general formula: Rj-HN-CO-(CH 2 ) n -CO-NH-R 2 , wherein n is an integer from 1 to 20, more preferably from 1 to 4, yet more preferably from 1 to 2, and Ri is an alkyl groups having from 1 to 20 carbons, more preferably from 4 to 12 carbons, and yet more preferably from 5 to 8 carbons, and R 2 is hydrogen or an alkyl group having from 1 to 20 carbons, or more preferably is hydrogen or an alkyl group having from 1 to 4 carbons, wherein Ri and R 2 may or may not be identical.
• alkyl diamides such as those having a general formula: Rj-HN-CO-(CH 2 ) n -CO-NH-R 2 , wherein n is an integer from 1 to 20, more preferably from 1 to 4, yet more preferably from 1 to 2, and Ri is an alkyl groups having
• alkyl diamides may be obtained, for example, from M-I L.L.C. (Houston, TX) under the trade name of VersaPacTM.
• Other rheological additives include Bentone 150, TruVis, Garamite 1210, VG SupremeTM, and Laponite, which are organophilic clays, and RheThikTM, which is a viscosity modifier available, for example, from M-I L.L.C. (Houston, TX).
• OB WARP (which is disclosed in U.S. Patent No.
• 6,586,372 assigned to the assignee of the present invention, and which is expressly incorporated by reference in its entirety
• a 19.4 ppg formulation of OB WARP was formulated in accordance with embodiments disclosed in U.S. Patent No. 6,586,372, which is assigned to the assignee of the present invention.
• the OB WARP was mixed with EDC-99DW, which is a paraffin oil, followed by the addition of additional base oil, Bentone 150, and sufficient glycerol to constitute 2% by volume of the total mixture, on a Hamilton Beach mixer at ambient temperature.
• the resulting solution had a final density of 13.6 ppg.
• the rheological properties of the solution at 170 0 F were investigated. The rheological measurements were made using a Fann 35 viscometer, available from Farm instrument company.
• Viscosity is the ratio of the shear stress to the shear rate and is an indication of flow resistance. For many fluids, apparent viscosity changes for different values of shear rate, and is measured in centipoise (cP). Shear rate is measured in RPM or sec "1 . In this embodiment, the initial apparent viscosity was measured at six different shear rates: 600 rpm, 300 rpm, 200 rpm, 100 rpm, 6 rpm, and 3 rpm. The results are shown in Table 1, below.
• PV plastic viscosity
• YP yield point (lbs/100 ft 2 ) which is another variable used in the calculation of viscosity characteristics of drilling fluids.
• GELS lbs/100 ft 2 is a measure of the suspending characteristics and the thixotropic properties of a drilling fluid.
• Wellbore fluids formulated in accordance with embodiments disclosed herein may be used in stimulation operations. For example, it is believed that a fluid may be useful when injecting CO 2 at 400 0 F into an oil-producing zone.
• a high density (19.9 ppg) annular fluid may be used in connection with a deep well, where a packer has been emplaced.
• typical packers employ elastomeric rings to contact the borehole wall to hold the packer in place to isolate zones of a well. If large pressure differentials exist across the packer face, however, the packer will leak or slide. This can be a significant issue in certain deep wells.
• typical annular fluids therefore, tends to lead to failures in this type of well, as typical annular fluids have a density of only about 8 ppg. Accordingly, a relatively large ⁇ P is seen by the packer.
• a high density fluid formulated in accordance with an embodiment of the present invention may "spot" emplaced, as part of a two fluid (or more) system, where the high density fluid is placed on top of the packer in order to avoid the ⁇ P on the packer.
• both of the fluids can be formulated as gels, the fluids will not mix with each other.
• annular fluids formulated in accordance with the present disclosure which have significantly higher solids content than prior art annular fluids, may be used in applications that require higher density than prior art formulations.
• annular fluids formulated in accordance with embodiments disclosed herein have very good thermal properties while maintaining sufficient rheological properties.

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