WO2011090924A1 - Systems and methods for producing oil and/or gas - Google Patents
Systems and methods for producing oil and/or gas Download PDFInfo
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- WO2011090924A1 WO2011090924A1 PCT/US2011/021499 US2011021499W WO2011090924A1 WO 2011090924 A1 WO2011090924 A1 WO 2011090924A1 US 2011021499 W US2011021499 W US 2011021499W WO 2011090924 A1 WO2011090924 A1 WO 2011090924A1
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- oil
- oil column
- horizontal
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- polymer
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/30—Specific pattern of wells, e.g. optimizing the spacing of wells
- E21B43/305—Specific pattern of wells, e.g. optimizing the spacing of wells comprising at least one inclined or horizontal well
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- 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
- C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
- C09K8/588—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids characterised by the use of specific polymers
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/20—Displacing by water
Definitions
- the present disclosure relates to systems and methods for producing oil and/or gas.
- EOR Enhanced Oil Recovery
- thermal thermal
- chemical/polymer chemical/polymer
- gas injection gas injection
- Thermal enhanced recovery works by adding heat to the reservoir.
- the most widely practiced form is a steamdrive, which reduces oil viscosity so that can flow to the producing wells.
- Chemical flooding increases recovery by reducing the capillary forces that trap residual oil and/or by reducing the interfacial tension between oil and water.
- Polymer flooding improves the sweep efficiency of injected water by more closely matching the oil and injectant viscosity and mobility ratio. Miscible injection works by creating a mixture of the injectant and the oil that flows more easily towards the production well than the oil by itself.
- System 100 includes underground formation 102, underground formation 104, underground formation 106, and underground formation 108.
- Production facility 110 is provided at the surface.
- Well 112 traverses formations 102 and 104, and terminates in formation 106. The portion of formation 106 is shown at 114. Oil and gas are produced from formation portion 114 through well 112, to production facility 110.
- Well 112 has vertical portion 112a and inclined portion 112b. Gas and liquid are separated from each other, gas is stored in gas storage 116 and liquid is stored in liquid storage 118.
- U.S. Patent Application Publication Number US 2009/308609 discloses a system comprising a well drilled into an underground formation; a production facility at a topside of the well; a water production facility connected to the production facility; wherein the water production facility produces water by removing some ions and adding an agent which increases the viscosity of the water and/or increases a hydrocarbon recovery from the formation, and injects the water into the well.
- U.S. Patent Application Publication Number US 2009/308609 is herein incorporated by reference in its entirety.
- U.S. Patent Application Publication Number US 2008/194434 discloses the use of water-soluble polymers for tertiary mineral oil production by introducing the polymer into a mineral oil deposit, in which the water-soluble polymers are used in the form of a dispersion of the water-soluble polymer and at least one water-soluble, polymeric stabilizer.
- U.S. Patent Application Publication Number US 2008/194434 is herein incorporated by reference in its entirety.
- the invention provides a method for producing oil and/or gas from an underground formation comprising locating a suitable formation with an oil column located above an aquifer; drilling at least one horizontal production well near a top of the oil column; performing primary production to produce a first quantity of fluids from the oil column;
- Improved systems and methods for enhanced recovery of hydrocarbons from a formation with a polymer flood Improved systems and methods for enhanced recovery of hydrocarbons from a formation with a fluid containing a dissolved polymer.
- Figure 1 illustrates an oil and/or gas production system.
- Figure 2a and 2b illustrate a well pattern.
- Figures 2c and 2d illustrate the well pattern of Figure 2a during enhanced oil recovery processes.
- FIG. 3 illustrates oil and/or gas production systems.
- Array 200 includes well group 202 (denoted by horizontal lines) and well group 204 (denoted by diagonal lines).
- array of wells 200 are vertical wells. In another embodiment, array of wells 200 are horizontal wells. In still a further embodiment, array of wells 200 may be inclined at an angle between vertical and horizontal.
- Array 200 defines a production area, enclosed by the rectangle. Array 200 is within area 220 which is within the oil column or pay zone. Area 220 is located above area 222, which may be an aquifer. Each well in well group 202 has horizontal distance 230 from the adjacent well in well group 202. Each well in well group 202 has vertical distance 232 from the area 222.
- Each well in well group 204 has horizontal distance 236 from the adjacent well in well group 204.
- Each well in well group 204 has vertical distance 238 from the area of 222.
- array may be composed of vertical wells that are perpendicular to the earth's surface, horizontal wells that are parallel to the earth's surface, or wells that are inclined at some other angle, for example 30 to 60 degrees with respect to the earth's surface.
- Each well in well group 202 is distance 234 from the adjacent wells in well group 204.
- Each well in well group 204 is distance 234 from the adjacent wells in well group 202.
- each well in well group 202 is located above the two wells in well group 204. In some embodiments, each well in well group 204 is located below two wells in well group 202.
- horizontal distance 230 is from about 25 to about 1000 meters, or from about 30 to about 500 meters, or from about 35 to about 250 meters, or from about 40 to about 100 meters, or from about 45 to about 75 meters, or from about 50 to about 60 meters.
- vertical distance 232 is from about 25 to about 1000 meters, or from about 30 to about 500 meters, or from about 35 to about 250 meters, or from about 40 to about 100 meters, or from about 45 to about 75 meters, or from about 50 to about 60 meters.
- vertical distance 238 is from about 5 to about 500 meters, or from about 10 to about 250 meters, or from about 15 to about 125 meters, or from about 20 to about 50 meters, or from about 25 to about 75 meters, or from about 30 to about 40 meters.
- vertical distance 238 is from about 15% to about 90% of vertical distance 232, or from about 25% to about 75%, or from about 35% to about 60%.
- horizontal distance 236 is from about 25 to about 1000 meters, or from about 30 to about 500 meters, or from about 35 to about 250 meters, or from about 40 to about 100 meters, or from about 45 to about 75 meters, or from about 50 to about 60 meters. In some embodiments, distance 234 is from about 15 to about 750 meters, or from about 20 to about 500 meters, or from about 25 to about 250 meters, or from about 30 to about 100 meters, or from about 35 to about 75 meters, or from about 40 to about 50 meters.
- array of wells 200 may have from about 10 to about 1000 wells or a larger number of wells as needed for a development, for example from about 5 to about 500 wells in well group 202, and from about 5 to about 500 wells in well group 204.
- array of wells 200 is seen as a top view with well group 202 and well group 204 being vertical wells spaced on a piece of land. In some embodiments, array of wells 200 is seen as a cross-sectional side view with well group 202 and well group 204 being horizontal wells spaced within a formation.
- the recovery of oil and/or gas with array of wells 200 from an underground formation may be accomplished by any known method. Suitable methods include subsea production, surface production, primary, secondary, or tertiary production. The selection of the method used to recover the oil and/or gas from the underground formation is not critical.
- oil and/or gas may be recovered from a formation into a well, and flow through the well and flowline to a facility.
- enhanced oil recovery with the use of a polymer mixture for example a mixture of water and a polymer, may be used to increase the flow of oil and/or gas from the formation.
- Figure 2b a cross-sectional view of Figure 2a taken along the line a-a is shown.
- Figure 2b shows array of wells 200 with horizontal production well 202 and horizontal injection well 204.
- Oil column 220 located above aquifer 222.
- Oil column 220 has height 250, for example from about 10 m to about 200 m, or from about 20 m to about 100 m, or from about 30 m to about 60 m in height.
- Production well 202 is a height 232 above the interface between oil column 220 and aquifer 222 for example from about 10 m to about 200 m, or from about 20 m to about 100 m, or from about 30 m to about 60 m in height.
- Injection well 204 is a height 238 above the interface between oil column 220 and aquifer 222 for example from about 5 m to about 100 m, or from about 10 m to about 50 m, or from about 15 m to about 30 m in height.
- Production well 202 is a height 254 above injection well 204 for example from about 5 m to about 100 m, or from about 10 m to about 50 m, or from about 15 m to about 30 m in height.
- height 232 is from about 70% to about 100%, for example from about 75% to about 95% of height 250.
- height 238 is from about 30% to about 70%, for example from about 35% to about 65%, or from about 40% to about 60% of height 250.
- height 254 is from about 30% to about 70%, for example from about 35% to about 65%, or from about 40% to about 60% of height 250.
- array of wells 200 is illustrated.
- Array 200 includes well group 202 (denoted by horizontal lines) and well group 204 (denoted by diagonal lines).
- a polymer mixture is injected into well group 204, and oil is recovered from well group 202. As illustrated, the polymer mixture has injection profile 208, and oil recovery profile 206 is being produced to well group 202.
- polymer mixture is injected into well group 202, and oil is recovered from well group 204. As illustrated, the polymer mixture has injection profile 206, and oil recovery profile 208 is being produced to well group 204.
- polymer mixture or a mixture including a polymer may be injected at the beginning of a cycle, and water may be injected at the end of the cycle to push the polymer mixture towards the producing wells.
- the polymer injection may follow a period of water injection, or the polymer mixture may be the first injectant into the reservoir.
- polymer mixtures injected into the formation may be recovered from the produced oil and/or gas and re-injected into the formation.
- oil as present in the formation prior to the injection of any enhanced oil recovery agents has a viscosity of at least about 5 centipoise, or at least about 10 centipoise, or at least about 25 centipoise, or at least about 50 centipoise, or at least about 75 centipoise, or at least about 90 centipoise.
- oil as present in the formation prior to the injection of any enhanced oil recovery agents has a viscosity of up to about 125 centipoise, or up to about 250 centipoise, or up to about 500 centipoise, or up to about 1000 centipoise, or up to about 10,000 centipoise.
- the oil may have a viscosity from about 150 to about 300 centipoise.
- the injected polymer mixture may have a viscosity from about 10 to about 200 centipoise, for example from about 25 to about 150, or from about 50 to about 125 centipoise.
- oil column 220 may have a horizontal permeability greater than about 10 milli-Darcies up to about three Darcies, up to about five Darcies, or up to about 10 Darcies. In some embodiments, oil column 220 may have a vertical permeability from about 0.3 to about 0.7 times the horizontal permeability.
- array of wells 200 is illustrated.
- Array 200 includes well group 202 (denoted by horizontal lines) and well group 204 (denoted by diagonal lines).
- polymer mixture is injected into well group 204, and oil is recovered from well group 202.
- polymer mixture has injection profile 208 with overlap 210 with oil recovery profile 206, which is being produced to well group 202.
- Releasing at least a portion of polymer mixture and/or other liquids and/or gases may be accomplished by any known method.
- One suitable method is injecting polymer mixture into a first well, and pumping out at least a portion of polymer mixture with gas and/or liquids through a second well.
- the selection of the method used to inject at least a portion of polymer mixture and/or other liquids and/or gases is not critical.
- polymer mixture and/or other liquids and/or gases may be pumped into a formation at a pressure up to the fracture pressure of the formation.
- polymer mixture may be mixed in with oil and/or gas in a formation to form a mixture which may be recovered from a well.
- a quantity of polymer mixture may be injected into a well, followed by another component to force polymer mixture across the formation.
- another component for example water in liquid or vapor form, water with a smaller amount of dissolved polymer to increase its viscosity, carbon dioxide, other gases, other liquids, and/or mixtures thereof may be used to force polymer mixture across the formation.
- from about 0.1 to about 5 pore volumes of the polymer mixture may be injected, for example from about 0.2 to about 2 pore volumes, or from about 0.3 to about 1 pore volumes of polymer mixture may be injected.
- the injection of polymer mixture may be followed by from about 0 to about 10 pore volumes of water, for example from about 3 to about 8 pore volumes of water.
- System 400 includes underground formation 402, formation 404, formation 406, and formation 408.
- Production facility 410 is provided at the surface.
- Well 412 traverses formation 402 and 404 has openings at formation 406 along the length of its horizontal portion. Portions of formation 414 may be optionally fractured and/or perforated.
- Gas and liquid may be separated, and gas may be sent to gas storage 416, and liquid may be sent to liquid storage 418.
- Production facility 410 is able to mix, produce and/or store polymer mixture, which may be produced and stored in production / storage 430.
- Polymer mixture is pumped down well 432 and then along its horizontal portion, to portions 434 of formation 406. Polymer mixture traverses formation 406 to aid in the production of oil and gas, and then polymer mixture, oil and/or gas may all be produced to well 412, to production facility 410. Polymer mixture may then be recycled, for example by utilizing a oil-water gravity separator, centrifuge, demulsifiers, boiling, condensing, filtering, and other separation methods as are known in the art, then re-injecting polymer mixture into well 432.
- a quantity of polymer mixture or polymer mixture mixed with other components may be injected into well 432, followed by another component to force polymer mixture or polymer mixture mixed with other components across formation 406, for example water in gas or liquid form; water mixed with one or more salts; other liquids; and/or mixtures thereof.
- from about 0.1 to about 2 for example from about 0.25 to about 1 pore volumes of polymer mixture may be injected into well 432.
- from about 0.5 to about 10 for example from about 1 to about 5 pore volumes of a polymer - water mixture having a viscosity at least about 25% less than the first polymer mixture, for example at least about 50% less than the viscosity of the polymer mixture may be injected into well 432.
- from about 1 to about 10 pore volumes of water may be injected into well 432.
- well 412 which is producing oil and/or gas is representative of a well in well group 202
- well 432 which is being used to inject polymer mixture is representative of a well in well group 204.
- agents for increasing the viscosity of a flooding fluid mixture may be water-soluble or water-dispersible, high molecular weight polymers.
- agents for increasing the viscosity and/or increasing oil recovery may include one or more of:
- Ciba Alcoflood 1275A, Alcoflood 1285REL, Praestol 2640SL, and Spurefloc AF1266;
- V scleroglucans
- polyacrylamide includes any cationic, anionic, nonionic or amphoteric polymer that may be comprised of acrylamide or methacrylamide recurring units.
- the polyacrylamides may be vinyl-addition polymers and may be prepared by methods such as by homopolymerization of acrylamide or by copolymerization of acrylamide with cationic, anionic, and/or nonionic comonomers. Suitable cationic
- comonomers include diallyldialkylammonium halides, the acid and quaternary salts of dialkylaminoalkyl(alk)acrylates and dialkylaminoalkyl(alk)acrylamides, for example the methyl chloride, benzyl chloride and dimethyl sulfate quaternary salts of
- dimethylaminoethylacrylate dimethylaminoethylmethacrylate, dimethylaminoethyl- acrylamide, dimethylaminoethylmethacrylamide, and diethylaminoethylacrylate, for example diallyidimethylammonium chloride and the methyl chloride quaternary salt of
- Anionic comonomers may include acrylic acid, methacrylic acid, and 2-acrylamido-2-methylpropanesulfonic acid, and salts thereof, for example acrylic acid and sodium acrylate.
- Nonionic comonomers may include acrylonitrile and
- alkyl(meth)acrylates such as methylacrylate, methylmethacrylate, and ethyl acrylate.
- the polyacrylamides may also be formed by post-reaction of polyacrylamides in a manner well- known to those skilled in the art by reacting the polyacrylamide with a reagent capable of changing the chemical structure of the polymer. Post-reactions of polyacrylamide may include hydrolysis with acid or base to produce hydrolyzed polyacrylamide, Mannich reaction (optionally followed by quaternization to produce quaternized Mannich polyacrylamide), and reaction with hydroxylamine (or salt thereof) to produce hydroxamated polyacrylamide.
- Cationic and anionic polyacrylamides may be used.
- agents for increasing the viscosity include polymers comprising an N-vinyl lactam and an unsaturated amide, such as N-vinyl-2- pyrrolidone, including homopolymers, copolymers and terpolymers, as disclosed in U.S. Patent No. 6,030,928, herein incorporated by reference in its entirety.
- agents for increasing the viscosity include viscosifiers, such as polymeric thickening agents, that may be added to all or part of an injected water composition in order to increase the viscosity thereof.
- agents have a weight average molecular weight of from about 1X10 6 to about 40X10 6 , for example from about 5X10 6 to about 30X10 6 , or for example from about from about 4 to about 7 million or from about 15 to about 30 million. In some embodiments, the molecular weight is about 100,000 or greater, for example about 1,000,000 or greater, such as about 10,000,000 or greater. Molecular weights may be determined by light scattering, using commercially available instrumentation and techniques that are known in the art.
- agents are sold by a variety of companies including Dow Chemical Co. in Midland, Mich.
- One agent may be Alcoflood.RTM. 1235, a water soluble polymeric viscosifier available from Ciba Specialty Chemicals in Tarrytown, N.Y.
- the agent may be added to the water at a concentration of about 0.001% to about 1% by weight of the total solution.
- the reduction of the mobility of a fluid in a porous media such as an oil-bearing reservoir can be accomplished by increasing the viscosity of the fluid, decreasing the permeability of the porous media, or by a combination of both.
- the agent may both increase the viscosity of water and/or reduce the permeability of a reservoir as a solution flows through it.
- the extent to which a particular concentration of a given agent performs these two functions may be very roughly a function of the agent's average molecular weight.
- agents for increasing the viscosity of the flooding water achieve a solution viscosity of at least about 10 centipoises at room
- agents may be selected based on viscosity retention, porous media flow performance, high temperature, high salinity, and high pressure conditions.
- a solution with an agent may be at least five times more viscous than sea water.
- agents may be water-soluble or water-dispersible.
- a composition includes an agent for increasing the viscosity, an aqueous fluid, and one or more of: surfactants, cosurfactants, corrosion inhibitors, oxygen scavengers, bactericides, and any combination thereof.
- a mixture of an agent and water may be subjected to shear forces in dynamic liquid dispersing or pumping devices such as centrifugal pumps.
- the mixtures can also be pumped in a loop so that they pass through the centrifugal pump several times until the desired polymer properties are obtained.
- Dynamic dispersing and pumping devices may be hydrodynamic flow machines, for example single- or multiple-stage rotary centrifugal pumps such as radial centrifugal pumps. Turbulent flow conditions are flow conditions characterized by irregular variations in the velocity of the individual liquid particles.
- a mixture may be passed through static cutting units with available water in order to provide a uniform slurry of particulate gel solids having a desired solids content without substantially degrading the agent, for example, reducing its molecular weight.
- the gel slurry resulting from passage through the static units may be either (a) introduced into a holding tank with gentle stirring for about 1-4 hours until the gel disappears and the agent dissolves to give a homogeneous solution concentrate at room temperature or slightly below, e.g., 15-20 C, or (b) the gel slurry may be fed continuously into a series of multiple hold tanks with sufficient overall residence time to form the homogeneous solution concentrate by the last hold tank.
- the homogeneous solution concentrate can then be passed through standard static mixers with available water for final dilution.
- the agent may be a polymer that may be prepared in the presence of crosslinking or branching agents, such as methylenebisacrylamide, and/or in the presence of chain transfer agents, such as isopropanol and lactic acid.
- crosslinking or branching agents such as methylenebisacrylamide
- chain transfer agents such as isopropanol and lactic acid.
- the amount of crosslinking agent is increased, the resulting aqueous composition of dispersed polymer tends to contain larger amounts of water-swellable polymer.
- the resulting aqueous composition of dispersed polymer tends to contain lesser amounts of water-swellable polymer.
- Chain transfer agents tend to reduce polymer molecular weight and to render soluble polymers which would otherwise be water-swellable because of the presence of crosslinking agents.
- the aqueous compositions of the instant invention may contain water-soluble dispersed polymer or water-swellable dispersed polymer, or mixtures thereof.
- the agent may be a polymer, such as polyacrylamide, that may be prepared by using techniques such as polymerization in solution, water-in-oil emulsion, water-in-oil microemulsion or aqueous dispersion, for example water-in-oil emulsion or water- in-oil microemulsion.
- Polyacrylamide particles may be formed by methods such as by grinding or comminution of a solution-polymerized mass of dry polyacrylamide. Spray-dried polyacrylamide particles may be used and may be formed by spray-drying a polyacrylamide- containing dispersion, water-in-oil emulsion, or water-in-oil microemulsion.
- the agent may be a polymer, which may be mixed with water by contacting of the polymer particles with the moving stream of water so that it results in an aqueous composition comprised of about 0.01% or greater of dispersed polymer, for example 0.05% or greater, for example 0.1% or greater, for example 0.2% or greater, by weight based on total weight of said aqueous composition.
- the aqueous composition may contain more than 5% of dispersed polymer by weight, based on total weight of aqueous composition, but in other cases contains about 5% or less of dispersed polymer, for example about 2% or less, for example about 1% or less, on the same basis.
- agents for increasing the viscosity of the water include a small but effective amount of polymer used to produce the desired viscosity or other properties in the injection fluid. Based upon the properties of the formation and the intended nature and duration of the process, the type and amount of the agent may be selected to achieve the desired effects over the appropriate time period. In some embodiments, the amount of agent used will be in the range of from about 500 ppm to about 10,000 ppm, for example about 1,000 ppm to about 3,000 ppm, based on the weight of the injection fluid. Generally, there will be selected an economical amount and type of polymer to produce the desired effect for the required time.
- a composition comprising at least one water- soluble polymer may be prepared by combining at least one water-soluble polymer together in any sequence.
- the amount of water soluble polymer may be about 200 to about 10,000 ppm, for example about 250-500 ppm based on the entire combination.
- the composition further comprises aqueous fluid
- the aqueous fluid utilized will comprise or contain water and may be about 88 to about 99.91 wt % of the final combination.
- the composition may also contain other solvents, alcohols, and/or salts.
- the polymer solutions may contain the polymers in
- concentrations up to about 5000 ppm concentrations up to about 5000 ppm.
- the upper concentration limit may be only due to the increasing viscosity, and the lower limit may be based on the increasing costs for recovery using larger amounts of more dilute solutions.
- oil and/or gas produced may be transported to a refinery and/or a treatment facility.
- the oil and/or gas may be processed to produce commercial products such as transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers.
- Processing may include distilling and/or fractionally distilling the oil and/or gas to produce one or more distillate fractions.
- the oil and/or gas, and/or the one or more distillate fractions may be subjected to a process of one or more of the following: catalytic cracking, hydrocracking, hydrotreating, coking, thermal cracking, distilling, reforming, polymerization, isomerization, alkylation, blending, and dewaxing.
- ISC In-situ combustion
- Steam injection is normally applied at low reservoir pressure but has been evaluated for the reservoir pressure of lOObar, yielding an a-priori low thermal efficiency.
- Hybrid processes combining steam and gas injection were tested in an effort to increase the thermal efficiency of the process.
- polymer is normally applied to oils with viscosity less than lOOcP. Adequate polymer injectivity is achieved using horizontal polymer injectors, these being optimally located to reduce chemical loss to the aquifer.
- the field under examination consists of several separate topographically flat oil bearing accumulations (so-called "reservoir highs").
- the reservoirs are at a depth of ⁇ 900m below ground level are normally pressured having an initial pressure of approximately 100 bar.
- the reservoir fluid is a highly undersaturarated 20° API medium heavy oil with low gas- oil-ratio (0.5 v/v) and viscosity in the range 250-500cP at a reservoir temperature of 50°C.
- the main productive unit comprises aeolian sands deposited in an arid continental setting.
- the main productive unit is a massive sandstone unit, with no further stratigraphic subdivisions because of its relative homogeneity.
- the sands are friable and unconsolidated, net average porosity is 27%, net average horizontal permeability over 5 Darcies and vertical permeability is estimated to be 0.3 - 0.7 times horizontal permeability.
- the top of the formation is unconformably overlain by another unit with similar properties to the formation and in excellent hydraulic communication. These two are thus considered as one single producing zone. Overlying these two are poorer quality sandy and shaly diamictites and a Cretaceous shale forming the structural top seal.
- Horizontal production wells are completed at the top of the reservoir so as to maximize distance from the aquifer.
- Horizontal completion intervals are typically 400m to 550m in length and the predominat completion type are pre-drilled liners (PDL) and wire-wrap screens (WWS).
- PDL pre-drilled liners
- WWS wire-wrap screens
- EZIP Expandable Zonal Inflow Profiler
- Beam pump is the preferred means of artifical lift although a small number of wells are completed with Electric Submersible Pump (ESP).
- ESP Electric Submersible Pump
- ISC In situ combustion
- ISC is probably one of the oldest EOR methods, proposed and tried in the field. However, it took many disappointing field experiences to understand better the key requirements for a successful ISC drive. ISC is a displacement process that requires good injectivity to sustain a robust combustion front. Furthermore, early oxygen breakthrough and poor sweep efficiency are key factors to take into account when ISC is considered.
- a team was established with a objectives of investigating and ranking suitable EOR processes, demonstrate technical and commercial feasibility and proposing a maturation plan including requirements for field trial, as appropriate.
- the adopted workflow is to first establish a fundamental understanding of each EOR process, tailor the process to address the special characteristics of the field, develop a notional development plan and corresponding forecasts so that wells, surface facilities and operational requirements could be assessed.
- Numerical simulations have been performed at several scales as appropriate to the various stages of the study. Taking for example, ISC, initial mechanistic simulation models were performed at the lab-scale to match and extract governing process parameters (fuel deposition, air requirement, reaction stochiometry and kinetics) from experimental data. Next followed a 2D conceptual pattern-scale modeling exercise to establish ISC modeling workflow and to complete an initial assessment of well spacing, configuration and required injection rates. Later, 3D conceptual and 3D geological sector models were constructed to take proper account of reservoir properties and topology. Forecasts from these models were scaled to a "field-scale" for screening level economics. Risks and uncertainties are expressed as a simple recovery range around a base case, informed by sensitivity analysis using sector models.
- a top-down combustion drive is proposed to account for the tendency of gas override in heavy oil and to balance the aquifer. The aim is to force the combustion front downwards and reduce aquifer influx.
- the combination of top-down combustion and an optimized aquifer drive is the basis for the TAAD (Thermally Assisted Aquifer Drive) concept.
- TAAD Thermally Assisted Aquifer Drive
- Stage two is characterised as a hot oil rim production, where the top of the reservoir in the combustion pattern is filled with flue gas
- the first runs with a 3D conceptual model showed a poorer recovery during this last TAAD phase.
- the poorer performance of the TAAD phase was related to depletion of the gas zone and re-saturation of the gas zone. Gas production will move the oil rim into gas zone, resulting in locking oil as residual saturation.
- increase of water production resulted in early watering out of the producer.
- the key to a successful TAAD stage is to balance the offtake of the aquifer and gas cap.
- the oil rim gas (flue/inert) injection is proposed to maintain the gas cap and pressure, and thereby manage the oil rim after combustion.
- the air injection rate is the most important parameter in combustion projects. Firstly, because it governs both the requirement for air compression and the capacity of produced gas handling facilities it strongly impacts the economics. Secondly a too low injection rate can lead to die out of the front or to coking the formation due to LTO reactions. Because of the top-down design in a relatively thick oil column (> 15 m), the required air rate is much higher than in a usual pattern or line drive ISC process. This is because much more air is required to burn the volume from top to bottom, as compared to the volume to burn in thin reservoirs in a line drive setting. The challenge to make ISC work, both technically and economically, for these reservoir conditions is to minimize the required air capacity by maintaining a high ultimate recovery.
- the well configuration is most important for the deployment of ISC - TAAD.
- the injectors have to be located at the top of the structure and the producers half way in the oil column.
- the optimal (economical and ultimate recovery) pattern consists of 2 horizontal production wells, approximately 500m long, and 3 vertical air injection wells. The distance between the two horizontal producers is 75m.
- Figure 5 shows the single ISC pattern.
- the side elevation shows the difference in depth between the injectors and producers. Note that in a full field arrangement the ratio between injector and producer will be 3 to 1.
- a 3D model is used in order to generate more realistic and reliable forecasts for ISC. All model properties are kept the same as the 2D model, in order to evaluate the impact of a 3D geometry on the results. In addition, a 3D model with realistic geological properties was also generated.
- the workflow for 3D modeling is first to optimize the simulation runs based on the 2D model results.
- optimisation includes both numerical and subsurface process optimization.
- the numerical optimization of the CMG STARS deck resulted in reduction of the runtime from more then 3 days to a few hours only.
- only a number of the optimized and most promising scenarios have been run using a 9-point discretisation scheme to check grid orientation effects.
- These same selected runs also have been run using the geological model.
- These final runs were used to generate the forecasts for evaluation of the ISC potential.
- the full field forecast is generated using a simulation of 3 ISC patterns, shown in figure 6.
- the production profile from the inner pattern is taken to be representative for an ISC production well.
- the full field forecast is based on scaling of the production profile of this inner pattern.
- the conceptual model had to be used for the simulations. Therefore a sweep efficiency factor of 0.85 is applied to correct the forecast for (geological) heterogeneities. This factor is based on the difference between the geological and conceptual model results for a single pattern simulation.
- the size of a full high was assumed so that 12 horizontal producers can be laid out with 11 'rows' of 3 injectors.
- the total air rate per phase is then 1,320,000 m3/day, given that the air rate for each well is 40,000 m3/day each.
- the air injection phase is 2.5 years and the gas follow up lasts 7.5 years, injecting only 20% of the initial rate.
- the incremental recovery at the end of the project is approximately 18% yielding a cumulative- Air-Oil-Ratio of 2000 m
- top-down steam drive is illustrated schematically in Figure 9.
- the key in this concept is to first inject steam in the bottom wells as a pre-soak phase (b). This establishes a hot fluid path of high mobility between the bottom and top wells. In the next phase (c) the bottom wells are converted to producers and top wells to injectors.
- a top-down drive is established with a good sweep efficiency, where gravity drainage is a key mechanism for recovery.
- a gas follow-up (d) is evaluated, whereby a non-condensable gas, such as flue gas, is injected.
- a non-condensable gas such as flue gas
- the main challenge for a steam drive in reservoirs with a strong bottom aquifer is the thermal efficiency, which strongly depends on the pressure in the reservoir.
- Historical reservoir performance indicates that reservoir pressure cannot easily be lowered by aquifer pump off (APO).
- APO aquifer pump off
- steam temperature is high (300 °C at 90 bar) and the latent heat of steam is low; these effects combine to reduce overall thermal efficiency with increase heat losses from the reservoir.
- a further consideration is wellbore heat loss in injection wells, however assuming a completion with packer and a gas filled annulus we calculate heat losses to be acceptable - due to a gas-filled annulus and high injection rates in excess of 500m3/d/well. Reservoir heat losses impact the lateral growth of the steam chamber.
- a challenge for the proposed steam development is steam conformance along the horizontal injection completion.
- Steam rate, steam quality, and inflow along the horizontal injector completion may require profile control devices such as venture choke, interval control values (ICV) or interval control devices (ICD).
- profile control devices such as venture choke, interval control values (ICV) or interval control devices (ICD).
- ICV interval control values
- Present simulation work does not indicate a strong requirement for profile control but well costs estimates have assumed thermal-EZIP for well segmentation and multiple sliding sleeve devices allowing a limited means of controlling inflow. Further analysis would be required if this options were taken forward as the preferred concept.
- FIG. 9 The well configuration of the top-down steam pattern is clearly shown in Figure 9.
- a pattern consist of a horizontal well located a the top of the oil column and two horizontal wells located about half way down the oil column. After pre-steam-soaking the lower production wells, the top well is the steam injector and the other wells located in the oil column are switched to be oil producers.
- Figure 10 shows a 3D model representing a element of symmetry (EOS). Also depicted in the same figure are the multiple steam patterns.
- EOS element of symmetry
- the 3D model shown in figure 10 is build using a 2D model. It is extended to 3D using the same geological model as was used for our evaluation of ISC. Three top-down steam drive scenarios have been considered, scenarios are governed by differing assumptions of steam generation capacity:
- a further scenario takes the base case but with a switch to non-condensable gas after several years in order to provide voidage replacement and pressure support while recovering the still heated, mobile oil through bottom producers.
- flue gas a mixture of C0 2 (11 mole%) and N 2 (89 mole%) resulting from combustion of CH 4 in the steam generator.
- HPSI oil recovery and energy efficiency
- Pre-soak is especially important to establish a thermal path between the steam chamber and the bottom producers at the beginning of the project. For this reason in the base case the bottom wells in the centre of the pattern are steam pre-soaked for 1 year before commencing top steam injection, whereas later production wells do not require pre- soak. In the blanket case all of the bottom wells are pre-soaked at the same time.
- Well timing for producers is determined in the base case by the speed of growing steam chamber, which drives the oil towards the flanks and the aquifer. Each additional bottom producer should come on stream just before the oil bank reaches it, because opening the well too late would mean drawing the oil against the steam drive.
- the steam chamber grows laterally 86m (one well spacing) approximately every 18 months, which governs the frequency of new wells.
- Production well location is between the pre-existing water cones (locations within the cones where oil saturation is typically 25 s.u. lower were not considered).
- Producer off-take rate between 400-600 m Id is optimal. Lower rates allow oil to segregate between the well and the aquifer. High rates excessively cool the production wells leading to an increase in watercut.
- Figure 11 shows the forecasts for a no further action case (NFA) (brown), HPSI base and blanket (red) and gas follow-up (orange) scenarios. All the scenarios have a common period of 5 years of primary production followed by 5 years of infill production. Steam pre- soaks start after 10 years of cold production and the top-down steam drive starts in year 11, when the first incremental oil response can be seen.
- the blanket case shows a significant acceleration of oil recovery compared to the base case as a result of the more aggressive steam injection policy.
- Gas follow-up starts after 5 years of steam injection, marked by a sharp increase in the cOSR (light blue) in year 15 and a flattening slope of the recovery curve. Quantitative results for oil recovery and cOSR of the HPSI and gas follow-up scenarios are summarised in Table 2.
- the gas follow-up scenario provides a improvement over the HPSI base case in energy efficiency (OER up by 40%) and net recovery.
- OER up by 40% energy efficiency
- net recovery net recovery.
- detailed analysis of the gas follow-up process shows that it is applicable only in topologically confined areas, prone to early gas breakthroughs, and requires additional CAPEX on gas handling and compression equipment.
- Polymer flooding in medium heavy oil reservoirs is the final option we evaluated.
- a high polymer solution is required but low in-situ brine salinity means that required polymer concentrations are acceptable.
- high permeability makes it possible to stretch the viscosity limit of a standard polymer application above normal upper limit i.e. 150 cP.
- a remaining challenge is the presence of a strong bottom aquifer as the high reservoir pressure results in difficulty in injecting the viscous polymer.
- the comparatively thin oil column and the consequent proximity of injectors to the OWC mean that some polymer is lost to the aquifer, reducing the efficiency of the flood.
- a development concept is proposed where the impact of the aquifer influx is minimized.
- a polymer development in medium-heavy oil is not a straightforward polymer project.
- a high viscosity polymer slug is required to push the crude towards the producer.
- the strong bottom aquifer influx keeps the pressure high and impedes injectivity.
- due to the presence of a bottom aquifer the injected polymer could be lost to the aquifer. It is evident there will be some losses, but the well configuration should be chosen to minimise loses to the aquifer and maximize recovery.
- the aquifer influx itself also will cause mixing of aquifer water with the polymer solution, thereby diluting the solution and lowering the slug viscosity.
- the second concept is selected based on conceptual modelling in 3D using a simple homogeneous 3-D box model.
- the spacing between the producers is the same as for the ISC and HPSI concept; 75 m. This short well spacing provides a fast oil response, in the producers, to polymer injection.
- the selected well configuration is then taken through an optimization exercise using a 3D geological model.
- the polymer simulation model is based on the model used for ISC and HPSI. The same sector model was used and all the crude properties were identical (Figure 13). A polymer phase was added to the model, where mixing with water is captured by a mixing rule.
- the geological model was used for optimisation of the selected concept (concept 2 in figure 13) with respect to injection rate, polymer viscosity and slug size injected. In this case, an optimum polymer viscosity is about 100 cP, and the injection rate 500 m3/day for a 500 m long horizontal well.
- the maximum injection pressure was set to 1000 kPa above the initial reservoir pressure.
- the incremental recovery of a polymer pattern is 11% with significant production acceleration (figure 14).
- the optimised concept was then used to evaluate the potential of polymer flooding and compared to the ISC and HPSI results. Evaluation and Comparison of EOR Processes
- Polymer has the lowest facilities CAPEX of the three options comprising deep aquifer source wells, water injection & polymer facilities (polymer handling, mixing and distribution).
- Aquifer source water is selected on the basis of plentiful supply and elimination of the requirement to intensive cleaning of produced water.
- Chemical OPEX might be expected to be prohibitive - the a high polymer slug viscosity is required to assure stable reservoir displacement, however reservoir salinity is low and high reservoir permeability allows choice of a high molecular polymer. Together these effects contribute to an acceptable polymer concentration (2000ppm) which limits both the size of polymer facilities and recurring chemical costs.
- a method for producing oil and/or gas from an underground formation comprising locating a suitable formation with an oil column located above an aquifer; drilling at least one horizontal production well near a top of the oil column; performing primary production to produce a first quantity of fluids from the oil column; drilling at least one horizontal injection well at a location between the horizontal production well and a bottom of the oil column; injecting water mixed with a viscosifier into the horizontal injection well while producing a second quantity of fluids through the horizontal production well from the oil column.
- the horizontal production well is at a distance of 25 meters to 100 meters from the horizontal injection well.
- the oil column comprises a oil column height from a top of the oil column to an interface between the oil column and the aquifer at the bottom of the oil column; wherein the horizontal production well is at a location within 20% of the oil column height from the top of the oil column.
- the method also includes a mechanism for injecting a water based mixture into the formation, after the water mixed with a viscosifier has been released into the formation.
- the oil column comprises a oil column height from a top of the oil column to an interface between the oil column and the aquifer at the bottom of the oil column; wherein the horizontal injection well is at a location between
- the oil column comprises a oil column height from a top of the oil column to an interface between the oil column and the aquifer at the bottom of the oil column; wherein a distance between the horizontal injection well and the horizontal production well is between 30% and 70% of the oil column height.
- drilling at least one horizontal production well further comprises drilling an array of production wells comprising from 5 to 500 wells, and wherein drilling at least one horizontal injection well further comprises drilling an array of injection wells comprising from 5 to 500 wells.
- each of the production wells are at a distance from about 50 m to about 100 m from each other, measured horizontally.
- the oil column has a height from about 25 m to about 50 m, measured vertically. In some embodiments, the oil column comprises an oil having a viscosity from 50 to 250 centipoise, prior to the injection of the water mixture.
- the horizontal production well comprises a water mixture profile in the formation, and the horizontal injection well comprises an oil recovery profile in the formation, the method further comprising an overlap between the water mixture profile and the oil recovery profile.
- a first horizontal production well and a second horizontal production well comprise a pair of adjacent production wells which are separated by a horizontal production well separation distance, further wherein the horizontal injection well is located from about 40% to about 60% of the horizontal production well separation distance.
- the viscosifier comprises a water soluble polymer.
- the oil in the formation comprises a first viscosity
- the water mixture comprises a second viscosity
- the first viscosity is within 75 centipoise of the second viscosity.
- the oil in the formation comprises a first viscosity
- the water mixture comprises a second viscosity
- the second viscosity is from about 25% to about 100% of the first viscosity.
- the horizontal production well produces the water mixture, and oil and/or gas.
- the method also includes recovering the water mixture from the oil and/or gas, if present, and then optionally re-injecting at least a portion of the recovered water mixture into the formation.
- the water mixture is injected at a pressure from 0 to 37,000 kilopascals above the initial reservoir pressure, measured prior to when injection begins.
- the oil column comprises a permeability from 0.0001 to 15 Darcies, for example a permeability from 0.001 to 1 Darcy.
- the method also includes converting at least a portion of the recovered oil and/or gas into a material selected from the group consisting of transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers.
- a method for producing oil and/or gas from an underground formation comprising locating a suitable formation with an oil column located above an aquifer, and at least two horizontal production well near a top of the oil column, which oil column has already undergone primary production to produce a first quantity of fluids from the oil column; drilling at least one horizontal injection well at a vertical location between the horizontal production well and a bottom of the oil column, and at a horizontal location between the two horizontal production wells; injecting water mixed with a viscosifier into the horizontal injection well while producing a second quantity of fluids through the horizontal production wells from the oil column.
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US13/522,751 US20120292026A1 (en) | 2010-01-22 | 2011-01-18 | Systems and methods for producing oil and/or gas |
CA2787045A CA2787045A1 (en) | 2010-01-22 | 2011-01-18 | Systems and methods for producing oil and/or gas |
RU2012136119/03A RU2012136119A (en) | 2010-01-22 | 2011-01-18 | SYSTEMS AND METHODS FOR OIL AND / OR GAS PRODUCTION |
CN2011800144040A CN102803648A (en) | 2010-01-22 | 2011-01-18 | Systems and methods for producing oil and/or gas |
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US29742910P | 2010-01-22 | 2010-01-22 | |
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US (1) | US20120292026A1 (en) |
CN (1) | CN102803648A (en) |
CA (1) | CA2787045A1 (en) |
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WO (1) | WO2011090924A1 (en) |
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CA2787045A1 (en) | 2011-07-28 |
US20120292026A1 (en) | 2012-11-22 |
RU2012136119A (en) | 2014-02-27 |
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