process for oil production

专利摘要:
PROCESSES FOR THE PRODUCTION OF OIL The present invention is directed to a process for the production and separation of oil. An aqueous fluid having an ionic content of at most 0.15 and a total dissolved solids content from 200 ppm to 10,000 ppm is introduced into an oil-bearing formation. Oil and water are produced from the subsequent formation to the introduction of the aqueous fluid into the formation. A brine solution having a total dissolved solids content of more than 10,000 ppm and demulsifier is mixed with the oil and water produced from the formation. The oil is then separated from a mixture of oil, water, demulsifier, and a brine solution.
公开号:BR112015002736B1
申请号:R112015002736-9
申请日:2013-08-07
公开日:2021-05-25
发明作者:Albert Joseph Hendrik Janssen；Bartholomeus Marinus Josephus Marie Suijkerbuijk
申请人:Shell Internationale Research Maatschappij B.V.；
IPC主号:

专利说明:

Field of Invention
[001] The present invention is directed to a process for the production of hydrocarbons from a hydrocarbon support formation. In particular, the present invention is directed to a process for producing hydrocarbons and water from a hydrocarbon support formation and separating the hydrocarbons from water. Fundamentals of the Invention
[002] Only a portion of the oil present in an oil-bearing formation is recoverable as a result of the natural pressure of the formation. Oil recovered from this "primary" recovery generally ranges from 5% to 35% of the oil in the formation. Improved oil recovery methods have been developed to increase the amount of oil that can be recovered from a formation carrying oil above and beyond that recovered in primary recovery.
[003] Water flooding, in which water is injected through an injection well into an oil-bearing formation to mobilize and drive the oil through the formation to produce a production well is a widely used method of secondary recovery used for increase the amount of oil recovered from a formation beyond primary recovery. Recently, using water flooding of low salinity water has been used to increase the amount of oil recovered from a formation relative to the amount of oil recovered from a conventional higher salinity water flood. Low salinity water can be used in place of the higher salinity water conventionally used in a flood water in a secondary recovery, or low salinity water can be used after a conventional higher salinity water flood to increase from incrementally oil recovery through that initial water flood in a tertiary recovery process.
[004] Low salinity water used in flooding by low salinity water has a lower ionic strength than connate water present in the formation, which normally has an ionic strength of 0.15 M or less and which has a total solids content dissolved solutions ("TDS") from 200 parts per million ("ppm") to 10,000 ppm and a polyvalent cation content that is less than the multivalent cation content of connate water. Injecting low salinity water into a formation can reduce the ionic binding of oil to formation within the pores in the formation by double-layer expansion, which leads to a reduction in the adsorption capacity of the rock for hydrocarbons. This increases the mobility of oil in the formation by making the formation's pore surface wetter in and less wet in oil, allowing the mobile oil to be removed from the pores in which it resides and is to be routed to a production well for production from of training.
[005] In an improved oil recovery process utilizing flooding by water, oil and water, and typically gas as well, are produced from the formation together. Oil, water and gas are separated in an oil recovery separator from the water and gas produced. Free water is separated and removed from the oil by phase separation. At least a portion of the oil and a portion of the water, however, can be intimately mixed into an emulsion. The emulsion can be treated in a coalescent which helps to break the emulsion, causing the water in the emulsion (in a water-in-oil emulsion) or oil in the emulsion (in an oil-in-water emulsion) to coalesce and separate in phase. Phases have been separated, then can be retrieved separately.
[006] Improved processes for separating oil and water produced from an oil-bearing formation by an advanced low salinity flood oil recovery process are desirable. Invention Summary
[007] In one aspect, the present invention is directed to a process for producing oil from an oil-bearing formation, comprising: introducing an aqueous fluid having an ionic strength of at most 0.15 mol/1 and total dissolved solids content from 200 ppm to 10,000 ppm in the oil-bearing formation; produce oil and water from the formation after introducing the aqueous fluid into the formation; mix a brine solution with a total dissolved solids content of at least 10,000 ppm and a demulsifier with oil and water produced from the formation; eseparate the oil from the mixture of oil, water, brine and demulsifier.
[008] In another aspect, the present invention is directed to a process for the separation of oil and water produced from an oil-bearing formation in which an aqueous fluid having an ionic concentration of at most 0.15 and a total content of dissolved solids from 200 ppm to 10,000 ppm was introduced comprising the steps of: mixing a brine solution with a total dissolved solids content of more than 10,000 ppm and a demulsifier with at least a portion of the oil and produced water to starting from formation; eseparate the oil from the mixture of oil, water, brine and demulsifier.
[009] In another aspect, the present invention is directed to a process for the production of oil, which comprises introducing an aqueous fluid having an ionic strength of at most 0.15 M and a total dissolved solids content of between 200 ppm and 10,000 ppm for an oil-bearing formation; produce oil and water from the formation through a subsequent production well to introduce the aqueous fluid into the formation; introduce a demulsifier for the oil and water produced from the formation in or within the production well to form a mixture of produced oil, produced water, and demulsifier; mixing a brine solution having a total dissolved solids content of greater than 10,000 ppm, with at least a portion of the mixture of produced oil, produced water, and demulsifier; Separate the oil from the mixture of oil, water, demulsifier, and a brine solution. Brief Description of Drawings
[0010] Fig. 1 is a diagram of an ion filter that can be used in the process of the present invention.
[0011] Fig. 2 is a diagram of an ion filter that can be used in the process of the present invention.
[0012] Fig. 3 is a diagram of an ion filter that can be used in the process of the present invention.
[0013] Fig. 4 is a diagram of an oil production and separation system that can be used in the process of the present invention.
[0014] Fig. 5 is a diagram of an oil and water separation unit that can be used in the process of the present invention.
[0015] Fig. 6 is a diagram of an oil and water separation unit that can be used in the process of the present invention.
[0016] Fig. 7 is a diagram of an oil and water separation unit that can be used in the process of the present invention.
[0017] Fig. 8 is a diagram of an oil and water separation unit that can be used in the process of the present invention.
[0018] Fig. 9 is a diagram of an oil production and separation system that can be used in the process of the present invention.
[0019] Fig. 10 is a diagram of a well pattern for oil production that can be used in the process of the present invention.
[0020] Fig. 11 is a diagram of a well pattern for oil production that can be used in the process of the present invention.
[0021] Fig. 12 is a timeline graph for the separation of oil and water. Detailed Description of the Invention
[0022] It has been found that when using an oil recovery process improved by flooding by low salinity water, a problem will arise in the separation of oil produced from water that is produced together with the oil. In particular, it has been found that at least a portion of the oil and water produced from an oil-bearing formation forms a firm emulsion when a low salinity water flood improved oil recovery process is employed. The tight emulsion is significantly more difficult to break and separate oil/water emulsions formed using conventional higher salinity water flooding.
[0023] The present invention is directed to the recognition of that problem and application of a process to reduce or eliminate the oil/water tight emulsion. In one aspect, the present invention is directed to a process in which a brine solution and a demulsifier are mixed with a tight oil-water emulsion to increase the salinity of the oil/water mixture to loosen the oil-water emulsion from so that oil and water can be more easily separated. Oil and water are then separated and recovered. The oil and water tight emulsion can be produced from an oil-bearing formation in which an improved recovery of low salinity oil from the flood water is used. In another aspect, the present invention is directed to a process in which a fluid Low salinity aqueous fluid is introduced into an oil-bearing formation, where the low salinity aqueous fluid has an ionic strength of at most 0.15M and a total dissolved solids content from 200ppm to 10,000ppm. Oil and water are produced from the subsequent formation to the introduction of the low salinity aqueous fluid into the formation. A brine solution having a total dissolved solids content of at least 10,000 ppm is mixed with at least a portion of the oil and water produced from the formation to improve the separation of water and oil, and, in Then the oil is separated from the mixture of oil, water, and brine solution.
[0024] In another aspect, the present invention is directed to a process in which the low salinity aqueous fluid is introduced into an oil-bearing formation, where the low salinity aqueous fluid has an ionic strength of at most 0. 15M and a total dissolved solids content from 200ppm to 10000ppm; oil and water are produced from the formation, through a subsequent production well to introduce the low salinity aqueous fluid into the formation; and a demulsifier is introduced into the oil and produced water from formation in or within the production well, to form a mixture of produced oil, produced water, and demulsifier. A brine solution having a content greater than 10,000 ppm total dissolved solids is mixed with at least a portion of the mixture of produced oil, produced water, and demulsifier to improve the separation of water and oil, and oil it is separated from the mixture of produced oil, produced water, demulsifier, and brine solution.
[0025] The low salinity aqueous fluid supplied for introduction into the formation carrying oil has a TDS content of from 200 ppm to 10,000 ppm and has an ionic strength of at most 0.15M. The low salinity aqueous fluid can have a TDS content of from 500 ppm to 7000 ppm, or 1000 ppm from 5000 ppm, or 1500 ppm from 4,500 ppm. Low salinity aqueous fluid may have an ionic strength of at most 0.1 or at most 0.05 M, or at most 0.01 M, and may have an ionic strength of from 0.01 M to 0.15M, or from 0.02M to 0.125M, or from 0.03 to 0.1. Ionic strength, as used herein, is defined by the equation:
where I is the ionic strength, c is the molar concentration of ion i, z is the valence of ion i, and n is the number of ions in the measured solution.
[0026] The low salinity aqueous fluid may have an ionic strength that is less than the ionic strength of the connate water present in the oil-containing formation, and/or a polyvalent cation concentration that is less than the multivalent cation concentration of connate water present in the oil-bearing formation and/or a concentration of divalent cation that is less than the concentration of divalent cations of connate water present in the oil-bearing formation. The fraction of the ionic strength of low salinity aqueous fluid to the ionic strength of connate water may be less than i, or it may be less than 0.9, or it may be less than 0.5, or it may be less than that 0,i, or can be from 0.0i to, but not including, i, or from 0.05 to 0.9 or from 0.i to 0.8. The fraction of the polyvalent cation content of the low salinity aqueous fluid to the multivalent cation content of the connate water may be less than i, or it may be less than 0.9, or it may be less than 0.5, or it can be less than 0.i, or it can be from 0.0i to, but not including, i, or from 0.05 to 0.9 or from 0.i to 0.8. The fraction of the divalent ion content of low salinity aqueous fluid to the divalent ion content of connate water may be less than i, or less than 0.9, or less than 0.5, or less than 0 ,i, or from 0.0i to, but not including, i, or from 0.05 to 0.9 or from 0.ia to 0.8.
The low salinity aqueous fluid may have a relatively low multivalent cation content and/or a relatively low divalent cation content. The low salinity aqueous fluid may have a multivalent cation concentration of at most 200 ppm, or at most 100 ppm, or at most 75 ppm, or at most 50 ppm, or at most 25 ppm, or from 1ppm to 200ppm, or from 2ppm to 100ppm, or from 3ppm to 75ppm, or from 4ppm to 50ppm, or from 5ppm to 25ppm. The low salinity aqueous fluid may have a concentration of divalent cations of at most 150 ppm, or at most 100 ppm, or at most 75 ppm, or at most 50 ppm, or at most 25 ppm, or from 1 ppm at 100ppm, or from 2ppm to 75ppm, or from 3ppm to 50ppm, or from 4ppm to 25ppm, or from 5ppm to 20ppm.
[0028] Low salinity aqueous fluid can be supplied from a natural source. The low salinity aqueous fluid can be supplied from a natural source, such as an aquifer, a lake, water produced from the oil-bearing formation, or a river comprising water containing from 200 ppm to 10,000 ppm total. of dissolved solids. The low salinity aqueous fluid can be supplied by process water from a natural source, such as an aquifer, a lake, the water produced from the oil-bearing formation, or a river, where the water from the source natural has a TDS content between 0ppm to 200ppm and wherein the TDS content of the water can be adjusted to 200ppm to 10,000ppm by adding one or more salts, eg NaCl and/or CaCl2, to the water.
[0029] Alternatively, the low salinity aqueous fluid, or at least a portion thereof, may be provided by transforming a brine source water to produce the low salinity aqueous fluid. The brine source water to be processed may have a TDS content of greater than 10,000 ppm if the low salinity aqueous fluid produced by processing the brine source water is to have a TDS content of from 200 ppm to 10000 ppm , or the brine source water can have a TDS content of greater than 5000 ppm, if the low salinity aqueous fluid produced by processing the brine source water has a TDS content of from 200 ppm to 5000 ppm. The brine source water to be processed may have a TDS content of at least 5000 ppm, or at least 10,000 ppm, or at least 15,000 ppm, or at least 17,500 ppm, or at least 20,000 ppm, or at least 25,000 ppm, or at least 30,000 ppm, or at least 40,000 ppm, or at least 50,000 ppm, or from 10,000 ppm to 250,000 ppm, or from 15,000 ppm to 200,000 ppm, or from 17,500 ppm to 150,000 ppm , or from 20,000 ppm to 100,000 ppm, or from 25,000 ppm to 50,000 ppm. The brine source water to be processed can be selected from the group consisting of aquifer water, sea water, brackish water, the water produced from the formation bearing oil, water from a mixture of oil, water and a solution of brine formed in the separation of oil produced from produced water, the subsequent separation of oil from the mixture as described below, and mixtures thereof.
Referring now to Fig. 1, a brine source water having a TDS content of greater than 10,000 ppm, or having a TDS content of greater than 5000 ppm, as described above may be processed to produce at least a portion of the low salinity aqueous fluid for introduction into the oil-bearing formation by contacting the water from the saline source 111 with an ion filter 113. A portion of the water from the source 111 may be passed through the ion filter 113 to form treated water 115 and wherein the treated water may have a TDS content of less than 10,000 ppm, and more preferably from 200 ppm to 10,000 ppm, and more preferably between 200 ppm and 5,000 ppm. At least a portion of the treated water 115 can be used as at least a portion of the low salinity aqueous fluid that is introduced into the oil-bearing formation.
[0031] A portion of the source water may be excluded from passing through the ion filter 113 to form a retentate 117 having increased salinity relative to the source water. The retentate can have a TDS content of at least 15,000 ppm, or from 15,000 ppm to 250,000 ppm. At least a portion of the retentate 117 can be used as at least a portion of the brine solution used to separate the produced oil and water, as described in more detail below.
[0032] If the permeate has a TDS content of less than 200ppm, the permeate can be treated to adjust the TDS content to a range of from 200ppm to 5000ppm. A portion of the retentate 117 can be added to the permeate to adjust the TDS content to a range of from 200 ppm to 5000 ppm.
[0033] The ion filter 113 can be a membrane-based system utilizing ion separation membrane units selected from the group consisting of a nanofiltration membrane unit, a reverse osmosis membrane unit, and combinations thereof. A nanofiltration membrane unit can consist of one or more nanofiltration membranes or preferably effective to selectively remove multivalent ions, including divalent ions, from the source water so that the treated water can contain less than 80%, or less than 90%, or less than 95% multivalent ions than the source water fed to the nanofiltration membrane(s), and the retentate may contain a corresponding increase in multivalent ions relative to the water in the source. The one or more nanofiltration membranes of a nanofiltration membrane unit can also moderately reduce the monovalent ion content of feed source water to the nanofiltration membrane(s), where the treated water may contain less than 20% , or less than 30%, or less than 50%, or less than 70% of monovalent ions than the source water fed to the nanofiltration membrane(s), and the retentate may contain a corresponding increase of monovalent ions in relation to the source water. Nanofiltration membranes can be formed from charged polymeric materials (eg, carboxylic acid ester, sulfonic acid, amine, amide, or functional groups), including polyamides, cellulose acetate, piperazine, or substituted piperazine membranes in which a thin layer ion discrimination membrane is supported on a thicker porous material, which is sandwiched between the discriminating layer and a support material. Suitable commercially available nanofiltration membranes in sheet form or in spiral wound form, which can be used in a nanofiltration membrane unit in ion filter 13 include, but are not limited to, SEASOFT 8040DK, 8040DL, and SEASAL DS- 5 available from GE, Osmonics Inc., 5951 Clearwater drive, Minnetonka, MN 55343, United States; NF200 Series, and NF-55, NF-70, and NF-90 available from Dow FilmTec Corp., 5239 W. 73 St., Minneapolis, MN, 55345, United States; DS-5 and DS-51 available from Desalination Systems, Inc., 760 Shadowridge Dr., Vista, CA, 92083, United States; ESNA-400 available from Hydranautics, 401 Jones Road, Oceanside, CA 92508, United States; and TFCS available from Fluid Systems, Inc., 16619 Aldine Westfield Road, Houston, TX 77032, United States.
[0034] A reverse osmosis membrane unit useful in ion filter 113 may be comprised of one or more reverse osmosis membranes effective to remove substantially all ions, including monovalent ions, from the source water so that the treated water can contain less than 85%, or less than 90%, or less than 95%, or less than 98% of ions than the source water fed to the reverse osmosis membrane(s), and the retained may contain a corresponding increase in ions relative to the source water. Reverse osmosis membranes can be hollow fiber modules or spirally wound, and can be asymmetric membranes prepared from a single polymeric material, such as asymmetric cellulose acetate membranes, or thin-film composite membranes prepared from a single first and a second polymeric material, such as cross-linked aromatic polyamides in combination with a polysulfone. Suitable commercially available osmosis membranes that can be used in a reverse osmosis membrane unit in ion filter 113 include, but are not limited to, AG8040F and AG8040-400 available from GE Osmonics; SW30 LF Series and available from Dow FilmTec Corp.; DESAL-11 available from Desalination Systems, Inc.; ESPA available from Hydranautics; ULP available from Fluid Systems, Inc.; and ACM available from TriSep Corp., 93 S. La Patera Lane, Goleta, CA 93117, United States.
[0035] Typically, pressure should be applied through the ion filter 113 to overcome the osmotic pressure across the membrane when the source water of brine solution 111 is filtered to reduce the TDS content of the source water and produce the treated water 115 The pressure applied across the ion filter 113 may be at least 2.0 MPa, or at least 3.0 MPa, or at least 4.0 MPa, and may be at most 10.0 MPa, or, a maximum of 9.0 MPa, or a maximum of 8.0 MPa, and can range from 2.0 MPa to 10.0 MPa, or from 3.0 MPa to 9.0 MPa. The pressure applied through a nanofiltration membrane in the ion filter 113 may be in the lower part of the pressure range relative to the pressure applied through a reverse osmosis membrane. The pressure applied through a nanofiltration membrane unit of ion filter 113 can range from 2.0 MPa to 6.0 MPa, and pressure applied through a reverse osmosis membrane unit of ion filter 113 can range from 4, 0 MPa and 10.0 MPa. If the ion filter 113 is composed of membrane units - either nanofiltration, reverse osmosis, or both - combined in a series, the pressure applied across each membrane of the membrane unit may be less than the previous membrane unit of at least 0.5 MPa, as less pressure is needed to overcome the osmotic pressure of the permeate from an anterior membrane unit.
[0036] Referring now to Fig. 2, the ion filter 113 may consist of a first ionic membrane unit 119 and one or more second ionic membrane units 121 arranged in series, wherein each ionic membrane unit can be a nanofiltration membrane unit or a reverse osmosis membrane unit. Brine source water 111 having a TDS content greater than 10,000 ppm or greater than 5,000 ppm as described above may be contacted with the first ionic membrane unit 119 to pass at least a portion of the source water of brine via the first ionic membrane unit to form a permeate 123 having a reduced TDS content relative to brine source water, wherein the permeate may have a TDS content of at least 1000 ppm, or at least 2500 ppm, or at least 5000 ppm, or at least 7000 ppm, or at least 10,000 ppm. A portion of the brine source water may be excluded from passing through the first ionic membrane unit 119 to form a primary retentate 125 having increased salinity of the water relative to the source. Permeate 123 may be contacted with each of the second ionic membrane units 121 following passing at least a portion of the permeate through each of the second ionic membrane units to form treated water 115 having reduced salinity relative to permeate and brine solution source water, wherein the treated water may have a TDS content of less than 10,000 ppm and preferably between 200 ppm and 5,000 ppm. At least a portion of the treated water 115 can be used as at least a portion of the low salinity aqueous fluid that is introduced into the oil-bearing formation.
[0037] A portion of the permeate 123 may be excluded from passing through each of the one or more second ionic membrane units 121 to form one or more secondary retentates 127. The primary retentate 125, one or more of the secondary retentates 127 , or a combination of the primary retentate 125 and one or more of the secondary retentates 127 can be used as the retentate 117 of the ion filter 113, where the retentate 117 has an increased salinity relative to source water 111 and may have a TDS content from at least 15,000 ppm, or from 15,000 ppm to 250,000 ppm. At least a portion of the retentate 117 can be used as at least a portion of the brine solution used to separate the produced oil and water, as described in more detail below.
[0038] If the permeate has a TDS content of less than 200ppm, the permeate can be treated to adjust the TDS content to a range of from 200ppm to 5000ppm. A portion of the primary retentate or one or more of the second retentates can be added to the permeate to adjust the TDS content to a range of from 200ppm to 5000ppm.
[0039] Referring now to Fig. 3, the ion filter 113 can be constituted by a first ionic membrane unit 129 and a second ionic membrane unit 131 arranged in parallel, wherein the first ionic membrane unit can be consisting of one or more nanofiltration membranes or one or more reverse osmosis membranes, or a combination thereof, and the second ionic membrane unit may consist of one or more nanofiltration membranes, one or more reverse osmosis membranes, or a combination of them. A portion 133 of the brine source water 111, as described above, may be contacted with the first ionic membrane unit 129 and a portion of the brine source water portion 133 may be passed through the first ionic membrane unit 129 to form a first permeate 135 having reduced TDS content relative to brine source water 111. First permeate 135 may have a TDS content of less than 10,000 ppm, or less than 7000 ppm, or less than 5000 ppm, or from 1000 ppm to 5000 ppm. A portion of the water portion of the brine solution source 133 may be excluded from passing through the first ionic membrane unit 129 to form a first retentate 137 having a TDS content greater than the brine source water 111. Retained 137 may have a TDS content of less than 15,000 ppm, or at least 20,000 ppm, or at least 25,000 ppm, or at least 30,000 ppm, or at least 40,000 ppm, or at least 50,000 ppm. A separate portion 139 of the brine source water 111 may be contacted with the second ionic membrane unit 131, and a portion of the brine source water portion 139 may be passed through the second ionic membrane unit 131 to form a second permeate 141 having reduced TDS content relative to brine source water 111. The second permeate may have a TDS content of less than 10,000 ppm, or less than 7000 ppm, or less than 5000 ppm, or from 200 ppm at 5000 ppm. A portion of the water portion of the brine source 139 may be excluded from passing through the second ionic membrane unit 131 to form a second retentate 143 having a TDS content of at least 15,000 ppm, or at least 20,000 ppm, or at least 25,000 ppm, or at least 30,000 ppm, or at least 40,000 ppm, or at least 50,000 ppm. At least a portion of the first and second permeates 135 and 141 can be combined to form treated water 115 having a TDS content of less than 10,000 ppm, or less than 7000 ppm, or less than 5000 ppm, or from 200 ppm to 10,000 ppm, or from 500 ppm to 5000 ppm, wherein at least a portion of the treated water 115 can be used as the low salinity aqueous fluid introduced into the oil-bearing formation. The first retentate 137, a portion thereof, the second retentate 143, a portion thereof, a combination of the first retentate 137 and the second retentate 143, or a combination of portions thereof, may be used as at least a portion of the solution. of brine used to separate oil and produced water, as described in more detail below.
[0040] In one embodiment, the first ionic membrane unit 129 may consist of one or more nanofiltration membranes and the second ionic membrane unit 131 may consist of one or more reverse osmosis membranes. The second permeate 141 passed through the second ionic membrane unit 131 may have a TDS content of less than 200 ppm, as long as the one or more reverse osmosis membranes of the second ionic membrane unit 131 remove substantially all of the total dissolved solids to from brine source water 111. The first permeate 135 transmitted through the nanofiltration membranes may have sufficient monovalent ions therein having a TDS content of at least 200 ppm, or at least 500 ppm, or at least 1000 ppm, so that the combined first and second permeates have a TDS content of at least 200 ppm, but less than 10,000 ppm. If the combined first and second permeates have a TDS content of less than 200 ppm, a portion of the first retentate or second retentate may be added to the combined first and second permeates to adjust the TDS content to within a range of 200 ppm to 5,000 ppm.
[0041] In the method of the present invention, the low salinity aqueous fluid, which may be supplied from a natural source or may be supplied by processing source water having a TDS content greater than 10,000 ppm or greater than 5,000 ppm as described above, can be introduced into an oil-bearing formation. The oil-bearing formation may consist of a porous matrix material, oil, and connate water. The oil-bearing formation comprises oil that can be separated and produced from the formation, after the introduction of the low salinity aqueous fluid into the formation.
[0042] The forming porous matrix material can be made up of one or more porous matrix materials selected from the group consisting of a porous mineral matrix, a porous rock matrix, and a combination of a porous mineral matrix and a matrix of porous rock. The formation can comprise one or more minerals, having a net negative electrical surface charge that leads to negative zeta potential under the formation conditions (temperature, pressure, pH, and salinity). Increased levels of minerals that have a negative zeta potential in a formation have been correlated with increased oil recovery when using an aqueous fluid of low salinity as an oil recovery agent. "Formation conditions", when used here in the context of zeta potential, are defined as the temperature and pressure of the formation and the pH and salinity of the water in the formation. Forming temperatures can range from 5°C to 275°C, or from 50°C to 250°C; forming pressures can range from 1 MPa to 100 MPa; pH of water in formation can range from 4 to 9, or 5 to 8; and salinity of the formation water can range from a TDS content of 2,000 ppm to 300,000 ppm. "Zeta potential" can be calculated from electrophoretic mobility measurements in which an electric current is passed through electrodes through an aqueous suspension consisting essentially of colloidal mineral-forming particles and determining the direction and speed of colloidal motion. The zeta potential of one or more forming minerals can range from -0.1 to -50 mV, or from -20 to -50 mV. The training may comprise at least 0.1%, or at least 1%, or at least 10%, or at least 25%, or from 1% to 60%, or from 5% to 50%, or 10% to 30% of at least one mineral with a negative zeta potential. X-ray diffraction measurements, surface charge titrations and sequence of potential measurements in rock formation terrain can be used to determine the amount of such minerals in the formation.
[0043] The porous matrix material of mineral and/or rock of the formation may consist of sandstone and/or a selected carbonate of dolomite, limestone, and mixtures thereof - wherein the limestone may be microcrystalline or crystalline limestone. If the formation is composed of a porous rock carbonate, the formation may contain little chalk or chalk may be absent from the formation since oil-containing formations that contain significant amounts of chalk may not be particularly susceptible to low salinity oil recovery using flooding by Water.
[0044] Minerals that can form the porous mineral matrix material with a negative zeta potential can be clays or transition metal compounds. Clays that have a negative zeta potential that can form at least a portion of the mineral porous matrix material include smectite clays, smectite/ilite clays, montmorillonite clays, illite clays, illite/mica clays, pyrophyllite clays, glauconite clays and kaolinite clays. Transition metal composite minerals that have a negative zeta potential that can form at least a portion of the porous mineral matrix material include carbonates and oxides, for example, iron oxide, siderite, and plagioclase feldspars.
[0045] The porous matrix material can be a consolidated matrix material in which at least a majority, and preferably substantially all, of the rock and/or mineral forming the matrix material is consolidated such that the rock and /or minerals form a mass in which substantially all of the rock and/or mineral is immobile when oil, low salinity aqueous fluid, or other fluid passes therethrough. Preferably, at least 95% by weight or at least 97% by weight, or at least 99% by weight of the rock and/or mineral is immobile when the oil, low salinity aqueous fluid, or other fluid passes through it. , so that any amount of rock or mineral material dislodged by the passage of oil, low salinity aqueous fluid, or other fluid is insufficient to make the formation impervious to the flow of oil, the low salinity aqueous fluid, or other fluid through training. Alternatively, the porous matrix material may be an unconsolidated matrix material in which at least a majority, or substantially all, of the rock and/or mineral forming the matrix material is consolidated. The formation, whether formed from a consolidated mineral matrix, an unconsolidated mineral matrix, or a combination thereof, can have a permeability of 0.00001 to 15 Darcy, or from 0.001 to 1 Darcy.
[0046] The formation carrying oil may be an underground formation. The underground formation can consist of one or more of the porous matrix materials described above, where the porous matrix material can be located below an overhead, at a depth ranging from 50 meters to 6,000 meters, or from 100 meters to 4,000 meters, or from 200 meters to 2,000 meters under the earth's surface. The underground formation can be an underwater formation.
[0047] The oil contained in the formation bearing oil may have a viscosity under formation conditions (in particular, at temperatures within the formation temperature range) of at least 1 MPa (1 cP), or at least 10 MPas ( 10 cP), or at least 100 MPas (100 cP), or at least 1000 MPas (1000 cP). The oil contained in the formation carrying oil may have a viscosity under formation temperature conditions from 1 to 100,000 MPas (1 to 100,000 cP), or from 1 to 10,000 MPas (1 to 10000 cP) or from 1 to 5000 MPas (1 to 5000 cP), or from 1 to 1000 (1 to 1000 cP) MPas.
[0048] Oil in formation carrying oil can be located in pores within the porous matrix of formation material. The oil in the oil-bearing formation can be immobilized in pores within the porous matrix of forming material, for example, by capillary forces, by interaction of oil with pore surfaces, by oil viscosity, or by interfacial tension between the oil and water in the formation.
[0049] The oil-bearing formation may also consist of water, which may be located in pores within the porous matrix material. The water in the formation can be connate water, water from a secondary or tertiary oil recovery process flood water, or a mixture thereof.
[0050] Connate water in the oil-bearing formation may have a TDS content of at least 500 ppm, or at least 1000 ppm, or at least 2500 ppm, or at least 5000 ppm, or at least 10,000 ppm, or at least 25,000ppm, or from 500ppm to 250,000ppm, or 1000ppm from 200,000ppm, or 2000ppm from 100,000ppm, or 2500ppm from 50,000ppm, or 5000ppm from 45,000ppm. Connate water in the oil-bearing formation may have a multivalent ion content of at least 200 ppm, or at least 250 ppm, or at least 500 ppm, and may have a multivalent ion content of from 200 ppm to 40,000 ppm, or 250 to from ppm to 20,000 ppm, from 500 ppm to 15,000 ppm. Connate water in the oil-bearing formation may have a divalent ion content of at least 150 ppm, or at least 200 ppm, or at least 250 ppm, or at least 500 ppm, from 150 ppm to 35,000 ppm, or 200 ppm from from to 20,000 ppm, from 250 ppm to 15,000 ppm.
[0051] The water in the oil-bearing formation can be positioned to immobilize oil within the pores. Introducing the low salinity aqueous fluid into the formation can mobilize at least a portion of the forming oil for production and recovery from the formation, releasing at least a portion of the oil from pores within the formation. The introduction of the low salinity aqueous fluid into the formation can make at least a portion of the formation surface wetter in water and less wet in oil relative to the formation surface prior to the introduction of the low salinity aqueous fluid into the formation and contact. of the low salinity aqueous fluid with the formation, which can mobilize the oil for production from the formation.
[0052] The formation carrying oil 103 must be susceptible to the formation of an oil production by injection of an aqueous fluid comprising low salinity water for the formation and subsequent production and recovery of oil from the formation. Formations bearing oil susceptible to oil production by oil recovery processes enhanced by low salinity water flooding may be oil wet or mixed wet but not water wet, where a substantial portion of the pore surface in the formation is wet with oil instead of water in an oil-wet or mixed wet formation. Preferably, the formation has an Amott-Harvey wetting index greater than -0.3, and more preferably greater than 0, or more preferably greater than 0.3, or from -0.3 to 1 ,0 as measured by the Amott-Harvey wetting test, and has a contact angle of less than 110°, or less than 70°, or 0° to 110°. The formation preferably also contains a substantial amount of oil-in-place, a portion of which can be recovered by mobilization using the low salinity aqueous fluid, therefore the formation preferably has a lower initial water saturation (SWi) than 0.3.
[0053] Determining the suitability of a formation for improved oil recovery by low salinity aqueous fluid can be done by conducting conventional core flux studies in core plugs extracted from the formation, where the low salinity of water it is used as the injector and where the core plugs are saturated with oil from formation and with fresh water or water with a salinity corresponding to the salinity of fresh forming water at a comparable initial water saturation.
Referring now to Fig. 4, a system 200 for practicing a method of the present invention is shown. The system includes a first well 201 and a second well 203 that extend into a formation carrying oil 205 as described above. The oil-bearing formation 205 can be comprised of one or more forming portions 207, 209, and 211 of matrices formed from porous materials, such as described above, located beneath an overflow 213. A low salinity aqueous fluid as described above is provided. Low salinity aqueous fluid may be supplied from an aqueous fluid storage facility 215 fluidly operatively coupled to a first injection/production facility 217 via pipeline 219. The first injection/production facility 217 may be operatively fluidly coupled to the first well 201, which can be located extending from the first injection/production facility 217 to the formation carrying oil 205. The low salinity aqueous fluid can flow from the first injection/production facility 217 through of the first well to be introduced into the formation 205, for example, in the formation portion 209, wherein the first injection/production facility 217 and the first well, or the first well itself, includes a mechanism for introducing the fluid. low salinity aqueous for formation. Alternatively, the low salinity aqueous fluid may flow from the aqueous fluid storage facility 215 directly to the first well 201 for injection into the formation 205, where the first well comprises a mechanism for introducing the low salinity aqueous fluid for training. The mechanism for introducing the low salinity aqueous fluid into the formation 205 through the first well 201 located in the first injection/production facility 217, the first well 201, or both - may be constituted by a pump 221 for transporting the aqueous fluid from low salinity for the perforations or openings in the first well through which the low salinity aqueous fluid can be introduced into the formation.
[0055] The low salinity aqueous fluid can be introduced into the formation 205, for example, by injecting the low salinity aqueous fluid into the formation through the first well 201 by pumping the low salinity aqueous fluid through the first well and into training. The pressure at which low salinity aqueous fluid is introduced into the formation can range from the instantaneous pressure in the formation to the fracture pressure of the formation or exceed the fracture pressure of the formation. The pressure at which low salinity aqueous fluid can be injected into the formation can range from 20% to 95%, or 40% to 90%, of the formation's fracture pressure. Alternatively, the low salinity aqueous fluid can be injected into the formation at a pressure of at least the fracture pressure of the formation, wherein the low salinity aqueous fluid is injected under fracture forming conditions.
[0056] The volume of low salinity aqueous fluid introduced into formation 205 through the first well 201 may vary from 0.001 to 5 pore volumes, or 0.01 to 2 pore volumes, or from 0.1 to 1 pore volume pores, or from 0.2 to 0.9 pore volumes, where the term "pore volume" refers to the formation volume that can be swept by the low salinity aqueous fluid between the first well 201 and the second well 203. Pore volume can readily be determined by methods known to a person skilled in the art, for example, by modeling studies or by water injection, having contained therein a tracer by forming 205 from first well 201 to second well 203 .
[0057] As the low salinity aqueous fluid is introduced into formation 205, the low salinity aqueous fluid spreads into the formation as shown by arrows 223. After introduction to formation 205, the low salinity aqueous fluids they come in contact with the surface of the formation's porous matrix material, and may change the surface to be wetter in water and less wet in oil. Introducing the low salinity aqueous fluid into the formation can mobilize oil in the formation for production from the formation. The low salinity aqueous fluid can mobilize the oil in the formation, for example, by reducing the capillary forces that hold oil in pores in the formation, by reducing the wetting of the oil on pore surfaces in the formation, and/or through the reduction of interfacial tension between water and oil in the formation pores.
[0058] The mobilized oil and low salinity aqueous fluid can be pushed through the formation 205 from the first well 201 to the second well 203 by additionally introducing lower salinity aqueous fluid or by introducing an oil-immiscible formulation into the formation subsequent to the introduction of the low salinity aqueous fluid into the formation. The oil-immiscible formulation may be introduced into formation 205 through the first well 201 after completion of the introduction of the low salinity aqueous fluid to the formation otherwise to force or displace the oil and low salinity aqueous fluid into the second well 203 for production.
[0059] The oil-immiscible formulation can be configured to displace the oil, as well as the low salinity aqueous fluid, through formation 205. Suitable oil-immiscible formulations are immiscible on first contact or miscible on multiple contact with oil on the formation 205. The oil-immiscible formulation may be selected from the group consisting of an aqueous polymer fluid, water in liquid or gas form, carbon dioxide at a pressure below the minimum miscibility pressure, nitrogen at a pressure below the minimum miscibility pressure, air, and mixtures of two or more of the above forms.
Polymers suitable for use in an aqueous polymer fluid may include, but are not limited to, polyacrylamides, partially hydrolyzed polyacrylamides, polyacrylates, ethylenic copolymers, biopolymers, carboxymethyl cellulose, polyvinyl alcohols, polystyrene sulfonates, polyvinylpyrrolidones, AMPS (2-acrylamide-2-methyl propane sulfonate), combinations thereof, or the like. Examples of ethylenic copolymers include copolymers of acrylic acid and acrylamide, acrylic acid and lauryl acrylate, lauryl acrylate and acrylamide. Examples of biopolymers include xanthan gum, and guar gum. In some embodiments, polymers can be cross-linked IN SITU in formation 205. In other embodiments, polymers can be generated IN SITU in formation 205.
[0061] The oil-immiscible formulation can be stored and supplied for introduction into formation 205, an oil-immiscible formulation storage facility 225 that can be fluidly operatively coupled to the first injection/production facility 217 through the pipeline 227. The first injection/production facility 217 may be operatively fluidly coupled to the first well 201 to deliver the oil-immiscible formulation to the first well, for introduction of formation 205. Alternatively, the immiscible formulation storage facility in oil 225 can be fluidly operatively coupled to the first well 201 directly to provide the oil-immiscible formulation to the first well for introduction into formation 205. The first injection/production facility 217 and the first well 201, or the first well itself , may comprise a mechanism for introducing the oil-immiscible formulation into formation 205 through first well 201 The mechanism for introducing the oil-immiscible formulation into formation 205 through the first well 201 may be a pump or a compressor to supply the oil-immiscible formulation with perforations or openings in the first well through which the immiscible formulation into oil can be injected into the formation. The mechanism for introducing the oil-immiscible formulation into the formation 205 through the first well 201 may be the pump 221 used to inject the low salinity aqueous fluid into the formation through the first well 201.
[0062] The oil-immiscible formulation can be introduced into the formation 205, for example, by injecting the forming oil-immiscible formulation through the first well 201 pumping the oil-immiscible formulation through the first well and into the formation. The pressure at which the oil-immiscible formulation can be injected into formation 205 through the first well 201 can be up to or greater than the formation's fracture pressure, or 20% to 99%, or 30% to 95 %, or 40% to 90% of the formation fracture pressure, or greater than the formation fracture pressure.
[0063] The amount of oil-immiscible formulation introduced into formation 205 through the first well 201, after the introduction of the oil recovery formulation into the formation through the first well may vary from 0.001 to 5 pore volumes, or from 0.01 to 2 pore volumes, or from 0.1 to 1 pore volume, or from 0.2 to 0.6 pore volumes, where the term "pore volume" refers to the formation volume that can be swept for oil-immiscible formulation between the first well and the second well. The amount of oil-immiscible formulation introduced into formation 205 should be sufficient to drive the mobilized oil and low salinity aqueous fluid through at least a portion of the formation. If the oil-immiscible formulation is in the gaseous phase, the volume of oil-immiscible formulation introduced into formation 205 follows the introduction of low salinity aqueous fluid into the formation relative to the volume of low salinity aqueous fluid introduced into the The formation immediately prior to introduction of the oil-immiscible formulation may be at least 10 or at least 20, or at least 50 volumes of gas-phase oil-immiscible formulation per volume of low salinity aqueous fluid introduced into the formation immediately prior to introduction of the formulation immiscible in gaseous oil.
[0064] If the formulation is oil-immiscible in liquid phase, the oil-immiscible formulation may have a viscosity of at least the same magnitude as the viscosity of mobilized oil under forming temperature conditions to allow the oil-immiscible formulation when driving the oil mobilized through formation 205 to the second well 203. The oil-immiscible formulation may have a viscosity of at least 0.8 (0.8 cP) or at least 10 MPas (10 cP) MPas, or at least 50 MPas (50 cP), or at least 100 MPas (100 cP), or at least 500 MPas (500 cP), or at least 1000 MPas (1000 cP), or at least 10,000 MPas (10,000 cP) under conditions of forming temperature or at 25°C. If the oil-immiscible formulation is in the liquid phase, preferably the oil-immiscible formulation may have a viscosity at least an order of magnitude greater than the viscosity of mobilized oil under forming temperature conditions so that the immiscible formulation in oil can drive the mobilized oil through formation in the plug flow, minimizing and inhibiting fingering of the mobilized oil through the oil-immiscible formulation driving plug.
[0065] The low salinity aqueous fluid and the oil immiscible formulation can be introduced into the formation through the first well 201 in alternating portions. For example, low salinity aqueous fluid may be introduced into formation 205 through first well 201 for a first period of time, after which the oil-immiscible formulation may be introduced into formation through first well for a second period of time. time subsequent to the first time period, after which the low salinity aqueous fluid can be introduced into the formation through the first well for a third time period subsequent to the second time period, after which the oil-immiscible formulation can be introduced in formation through the first well for a four time period subsequent to the third time period. Like many alternating portions of low salinity aqueous fluid, the oil-immiscible formulation can be introduced into the formation through the first well as desired.
[0066] The oil can be mobilized for production from the formation 205 through the second well 203 by introducing the low salinity aqueous fluid and optionally the oil-immiscible formulation in the formation through the first well 201, where the oil mobilized is conducted through the formation of the first well 201 to the production of the second well 203, as indicated by arrows 229. At least a portion of the low salinity aqueous fluid may pass through the formation 205 from the first well 201 to the second well 203 for production from formation, together with the mobilized oil. Water other than the low salinity aqueous fluid and/or gas may also be mobilized for production from formation 205 via second well 203 by introducing the low salinity aqueous fluid and, optionally, the oil-immiscible formulation in formation through the first well 201.
[0067] After the introduction of the low salinity aqueous fluid and, optionally, the oil-immiscible formulation into formation 205 through the first well 201, the oil can be recovered and produced from the formation, through the second well 203. mechanism can be located in the second well for the recovery and production of oil from the subsequent formation 205 of introducing the low salinity aqueous fluid into the formation. The mechanism for oil recovery and production from the formation may also recover and produce at least a portion of the low salinity aqueous fluid, other water, and/or gas from the subsequent formation of introducing the aqueous fluid. low salinity for training. The mechanism located in the second well 203 for the recovery and production of oil, low salinity aqueous fluid, other water, and/or gas can be constituted by a pump 233, which can be located in the second injection/production facility 231 and/or in the second well 203. The pump 233 can extract the oil, at least a portion of the low salinity aqueous fluid, the other water, and/or gas from the formation 205 through perforations in the second well 203 to supplying the oil, in at least a portion of the low salinity aqueous fluid, other water, and/or gas, to the second injection/production facility 231.
[0068] Alternatively, the mechanism for the recovery and production of oil, at least a portion of the low salinity aqueous fluid, other water, and/or gas from formation 205 may be constituted by a compressor 234 which can be located in the second injection/production facility 231. Compressor 234 can be fluidly operatively coupled to a gas storage tank 241 through duct 236, and can compress gas from the gas storage tank for injection into the formation 205 by means of second well 203. The compressor can compress the gas to a pressure sufficient to drive the production of oil, low salinity aqueous fluid, other water, and/or gas from the formation, through second well 203 , where the appropriate pressure can be determined by conventional methods known to those skilled in the art. Compressed gas can be injected into the formation from a different position in the second well 203 than the position of the well in which oil, low salinity aqueous fluid, other water, and/or gas are produced from the In the formation, for example, compressed gas can be injected into the formation in the forming portion 211 while oil, low salinity aqueous fluid, other water, and/or gas are produced from the formation in the forming portion 209.
[0069] Oil, at least a portion of the low salinity aqueous fluid, other water, and/or gas can be removed from formation 205, as shown by arrows 229 and the second well 203 was produced for the second injection facility / production 231. The oil can be separated from the gas and an aqueous mixture consisting of the produced part of the low salinity aqueous fluid and other formation water produced from the formation, e.g., tap water, mobile water, or water from a flood of oil recovery. The oil produced can be separated from the aqueous mixture produced and gas produced in a separation unit 235 located in the second injection/production facility 231 and, in one embodiment, operatively fluidly coupled to the mechanism 233 for recovery and the production of oil, aqueous mixture components, and/or gas from formation.
[0070] A brine solution having a TDS content greater than 10,000 ppm, or from 15,000 ppm to 250,000 ppm can be supplied from a 247 brine solution storage facility to the 235 separation unit through the pipeline 273 for mixing with the produced oil and the produced aqueous mixture, and optionally with the produced gas. The brine solution may have a TDS content of at least 15,000 ppm, or at least 20,000 ppm, or at least 25,000 ppm, or at least 30,000 ppm, or at least 40,000 ppm, or at least 50,000 ppm ppm, or from greater than 10,000 ppm to 250,000 ppm, or from 15,000 ppm to 200,000 ppm, or from 20,000 ppm to 150,000 ppm, or from 30,000 ppm to 100,000 ppm. The brine solution can be selected from sea water, brackish water or production water produced from formation and separated from oil and/or gas produced from formation. Alternatively, the brine solution can be composed of at least a portion of a retentate 117, a primary retentate 125 and/or a secondary retentate 127, or a first retentate 137 and/or a second retentate 143 (as shown in Figures 1 to 3) produced by contacting a brine source water with an ion filter as described above. An ion filter 113 as described above may be fluidly operatively coupled to the brine solution storage unit 247 through conduit 275 to provide the retentate 117, 125, 127, 137, and/or 143 as at least a portion. of the brine solution to the brine solution storage facility 247.
[0071] A demulsifier may also be supplied to the separation plant 235 from a demulsifier storage facility 271 which can be fluidly operatively coupled to the separation unit via duct 240. The demulsifier can be supplied to the facility of separation 235 for mixing with the produced oil, the produced water, and the brine solution, and optionally with produced gas, to facilitate the separation of the produced oil and the produced water.
[0072] The demulsifier can be selected from the group consisting of amyl resins; butyl resins; nonyl resins; base or acid catalyzed phenol-formaldehyde resins; phenol-acrylate polyglycol anhydride resins; urethanes; polyamines; polyesteramines; sulfonates; diepoxides; polyols; polyol esters and esters including fatty acid triol esters, adipate triol esters, triol fumarate esters; ethoxylated and/or propoxylated compounds of amyl resins, butyl resins, nonyl resins, acid or base catalyzed phenol-formaldehyde resins, fatty acids, polyamines, diepoxides, and polyols; and combinations thereof which can be dispersed in a carrier solvent selected from the group consisting of xylene, toluene, heavy aromatic naphtha, isopropanol, methanol, 2-ethoxyhexanol, diesel, and combinations thereof. A demulsifier suitable for separating the oil and water produced from the formation 205 can be selected by performing a bottle test, a conventional test known to those skilled in the art for selecting an effective demulsifier to separate crude oil and Water. Commercially available demulsifiers include EB-Series from National Chemical Supply, 4151 SW 47th Ave., Davie, FL, 33314, United States, and Tretolite demulsifiers from Baker Petrolite Corporation, 12645 W. Airport Blvd., Sugar Land, TX 77478, United Members.
Referring now to Fig. 5, a separation unit 235 that can be used in the method of the present invention is shown. The separation unit 235 may consist of a 2-phase separator 301 and a water ejection vessel 303. The two-phase separator may be a conventional two-phase separator for separating a gas phase from a liquid phase, wherein the 2-phase separator may be a vertical, horizontal, or spherical separator, and may be a high pressure separator (5.2 MPa to 34.4 MPa; 750 to 5,000 psi), a medium pressure separator (1 .6 MPa to 5.2 MPa; 230 to 750 psi), or a low pressure separator (0.07 MPa to 1.6 MPa; 10 to 230 psi). Produced oil, produced water, and produced gas 305 can be supplied from the second well to the 2-phase separator 301. The gas can be separated from the produced oil and produced water in the 2-phase separator 301 by phase separation, and the separated gas can be withdrawn from the 2-phase separator by duct 243. As shown in Fig. 4, the separated gas can be supplied from the separator 235 to a gas storage facility 241, which can be fluidly connected. operatively to the separator by a duct 243. Referring again to Fig. 5, the produced oil and produced water can be separated from the gas in the 2-phase separator 301 by phase separation, and the produced oil separated and blended. Produced water can be supplied from the two-phase separator to the water ejection vessel 303, which can be fluidly operatively connected to the 2-phase separator by duct 307.
[0074] The oil produced and the water produced can be separated in the water ejection vessel 303 by density separation and demulsification with the brine solution and the demulsifier. The water ejection vessel 303 may be a conventional water ejection vessel.
[0075] As described above, a brine solution can be supplied from a brine solution storage facility 247 (Fig. 4) to separation unit 235 by duct 273, where it can be supplied to a solution of brine to the water ejection vessel 303 of the separation unit. Also, as described above, the demulsifier can be supplied from a demulsifier storage facility 271 (Fig. 4) to the separation unit 235 by pipeline 240, where the demulsifier can be supplied to the water ejection vessel 303 of the separation unit. If desired or necessary, additional emulsion breaking steps can be carried out in the water ejection vessel 303 after forming the brine, oil and water solution mixture to destabilize the emulsion and the oil separated from the water. For example, the mixture of brine, oil, and water solution can be heated to destabilize the emulsion, or the mixture can be electrostatically dehydrated.
[0076] The demulsifier and brine solution may be supplied to the water ejection vessel 303 in sufficient amounts to facilitate rapid demulsification of any oil-in-water or water-in-oil emulsions present in the water ejection vessel. water to promote quick clean separation of oil and water in the water ejection vessel. The brine solution can be supplied to the water ejection vessel 303 in an amount sufficient to increase the TDS content of the produced water to greater than that of the aqueous phase produced from production well 203, by at least 5,000 ppm , or at least 10,000ppm, or at least 15,000ppm, or at least 20,000ppm, or at least 25,000ppm, or at least 30,000ppm, or provided greater than 10,000ppm and 100,000ppm, from 15,000ppm ppm and 50,000 ppm, or from 20,000 ppm and 40,000 ppm, or from 50,000 ppm and 250,000 ppm. Alternatively, the brine solution can be added to the produced oil and produced water mixture in the water ejection vessel 303 such that the brine solution is from % by volume to 40% by volume of the produced oil and water mixture. produced, or from 5% by volume to 33% by volume of produced oil and produced water mixture, or from 10% by volume to 25% by volume of produced oil and produced water mixture. The demulsifier can be added to the produced oil, produced water and a mixture of a brine solution so that the demulsifier is present in an amount of 2ppm to 200ppm, or from 10ppm to 100ppm. Alternatively, a demulsifier solution can be added to the produced oil, produced water mixture, and brine solution so that the demulsifier solution is 0.05% by volume to 5% by volume, or between 0.1% by volume of 2% by volume of the mixture of the produced oil, the produced water, and a brine solution, where the demulsifying solution may contain from 0.1% by weight to 5% by weight, or between 0.5% by weight up to 2.5% by weight, or from 1% by weight by weight to 2% of the demulsifying compound(s).
[0077] The inclusion of the brine solution with a mixture of produced oil, produced water, and demulsifier can significantly decrease the time required for an oil and water emulsion to separate into distinct phases of oil and water relative to the time required for a mixture of produced oil, produced water, and demulsifier without the brine solution to separate into distinct phases. The inclusion of the brine solution with a mixture of produced oil, produced water, and demulsifier can shorten the time needed to separate an emulsion of oil and water into distinct phases by at least 2 times, or at least 3 times, or at least 4 times, or at least 5 times, or at least 10 times with respect thereto, without mixing with a brine solution.
[0078] Consequently, the volume of the water ejection vessel can be at least 2 times, or at least 3 times, or at least 4 times, or at least 5 times less when using the brine solution, relatively to the volume of a water ejection vessel needed to separate and demulsify produced oil, produced water, and a demulsifier without the brine solution.
[0079] Produced oil can be separated from the water ejection vessel 303, and, as shown in Fig. 4, supplied from the separation unit 235 to an oil storage tank 237. The water ejection vessel 303 (Fig. 5) of separation unit 235 can be fluidly connected operatively to oil storage tank 237 by pipeline 239 for supplying the separated oil produced from water ejection vessel 303 to the oil storage tank 237.
[0080] Produced water may be separated from the water ejection vessel through line 309. Produced water may be supplied to an ion filter as described above to produce a treated water and a brine solution. Treated water can be supplied to the aqueous fluid storage facility 215 for reintroduction into the formation as described above. The brine solution can be supplied to a brine solution storage facility 247 for use to demulsify additional produced oil and produced water.
[0081] As shown in Fig. 6, the separation unit 235 can be additionally constituted by a free water ejection vessel 311 in addition to the 2-phase separator 301 and the water ejection vessel 303. The water ejection vessel book 311 can be a conventional free water ejection vessel. Gas 243 can be separated from produced oil and produced water in the 2-phase separator as described above, and produced oil and produced water can be supplied to free water ejection vessel 311. Oil 313 and water 315 which are already phase-separated can be separated and removed from free water ejection vessel 311. Oil and water that are present in an emulsion 317 can be passed from free water ejection vessel 311 to water ejection vessel 303. brine solution 273 and demulsifier 240 can be mixed with the emulsion in water ejection vessel 303 to separate the oil and water phase of the emulsion. If desired or necessary, additional emulsion breaking steps can be carried out in water ejection vessel 303 after forming the brine, demulsifier, oil and water solution mixture to destabilize the emulsion and the oil separated from the water. For example, a mixture of a solution of brine, demulsifier, oil, and water can be heated to destabilize the emulsion, or the mixture can be electrostatically dehydrated. Oil 339 separated from the emulsion may be separated from water ejection vessel 303 and combined with oil 313 separated from free water ejection vessel 311 and provided for storage in oil storage tank 237 via the duct 239 (Fig. 4). The water 318 separated from the emulsion in the water ejection vessel 303 can be combined with water 315 separated from the free water ejection vessel 311. The water combination 309 can be supplied to an ion filter as described above for separation in a low salinity treated water and a brine solution. Low salinity treated water can be supplied from the ion filter to the aqueous fluid storage facility 215 for re-introduction into the formation as described above. The brine solution can be supplied from the ion filter to the brine solution storage unit 247 for use for demulsifying the additional produced oil and produced water.
[0082] Alternatively, as shown in Fig. 7, the separation unit 235 may consist of a 3-phase separator 401. The 3-phase separator 401 may be a conventional three-phase separator for separating gas, oil and Water. Produced oil, produced water, and produced gas 305 can be supplied from the production well to the 3-phase separator 401. The gas, oil, and water can be separated by phase separation in the 3-phase separator 401. separated gas can be withdrawn from the phase 3 separator by duct 243. As shown in Fig. 4, the separated gas can be supplied from the separator 235 to a gas storage facility 241 which is fluidly operatively connected to the separator by duct 243. Referring again to Fig. 7, a brine solution 273 and demulsifier 240 can be supplied to the three-phase separator to demulsify an oil and water emulsion present in the three-phase separator and produce a liquid oil phase and a liquid water phase. If desired or necessary, additional emulsion breaking steps can be carried out in the 3-phase separator after formation of the mixture of brine, demulsifier, oil and water solution to destabilize the emulsion and the oil separated from the water. For example, a mixture of a solution of brine, demulsifier, oil, and water can be heated to destabilize the emulsion, or the mixture can be electrostatically dehydrated. The liquid oil phase can be separated from the 3-phase separator through duct 239 which can be fluidly operatively coupled to oil storage tank 237 (Fig. 4). The liquid water phase can be separated from the 3-phase separator by a 309 duct, which can be fluidly operatively connected to an ion filter as described above for separation into a low salinity treated water and a brine solution. . Low salinity treated water can be supplied from the ion filter to the aqueous fluid storage unit 215 (Fig. 4) for re-introduction into the formation. The brine solution can be supplied to a brine solution storage facility 247 for use in demulsifying additional produced oil and produced water.
[0083] Alternatively, as shown in Fig. 8, the separation unit 235 may be constituted by a 2-phase separator 301, a mixing tank 505, and a water ejection vessel 303, where the 2-phase separator 301 is a mechanism for separating gas from the produced oil and produced water, the mixing tank 505 is a mechanism for contacting the brine solution and the demulsifier with the produced oil and the produced water, and the water ejection vessel 303 it is a mechanism to separate produced oil from produced water. Produced oil, produced water, and gas can be supplied to separation unit 235 from the second well through pipeline 305, where produced oil, produced water, and gas can be supplied to the separator of 2 stages 301. The 2-stage separator 301 can separate gas from produced oil and produced water as described above. Produced oil and produced water can be supplied from 2-stage separator 301 to mixing tank 505 through pipeline 507. Mixing tank 505 can be any conventional mechanism for mixing liquids, eg a tank mixing with mechanical agitation. The brine solution can be supplied to the mix tank 505 from a brine solution storage facility 247 (Fig. 4) by a pipeline 273, and the demulsifier can be supplied from a demulsifier storage facility 271 (Fig. 4) to the mixing tank by pipeline 240. The brine solution, demulsifier, produced oil, and produced water can be mixed in the mixing tank 505, and then supplied from the mixing tank to the water ejection vessel 303 through the pipeline 509. The produced oil can be separated from the produced water in the water ejection vessel 303 as described above, wherein the separated produced oil 239 can be supplied to the oil storage tank 237 , and the produced water 309 can be supplied to an ion filter as described above.
[0084] Referring again to fig. 4, in an embodiment of a method of the present invention, the first well 201 can be used to inject the low salinity aqueous fluid and, optionally, the oil-immiscible formulation into formation 205 and the second well 203 can be used to produce and separate oil, water, and, optionally, gas from the formation, as described above for a first period of time, and the second well 203 can be used to inject the low salinity aqueous fluid and, optionally, the formulation. immiscible in oil in formation 205 to mobilize the oil in the formation and drive the mobilized oil through the formation to the first well and the first well 201 can be used to produce and separate the oil, water and gas from the formation for a second period of time, where the second time period is subsequent to the first time period. The second injection/production facility 231 may comprise a mechanism such as a pump 251 which is fluidly operatively coupled to the aqueous fluid storage facility 215 by duct 253 and which is operatively fluidly coupled to the second well 203 for introducing the low salinity aqueous fluid to formation 205 via the second well. Pump 251 or a compressor may also be operatively fluidly coupled to oil-immiscible formulation storage facility 225 by line 255 to introduce oil-immiscible formulation into formation 205 via second well 203 for subsequent introduction of the aqueous fluid of low salinity for formation through the second well. First injection/production facility 217 may comprise a mechanism such as pump 257 or compressor 258 for producing oil, water and gas from formation 205 by means of first well 201. First injection/production facility 217 may also include a separation unit 259 for the separation of produced oil, produced water, and produced gas fluidly connected to mechanism 257 by duct 260, wherein separation unit 259 may be similar to separation unit 235 such as as described above. The brine solution storage facility 247 can be fluidly operatively connected to the separation unit 259 via duct 272 to supply a brine solution to the separation unit 259, and the demulsifying storage facility 271 can be fluidly connected to the separation unit 259. fluid operatively connected to separation unit 259 through conduit 262 to supply demulsifier to separation unit 259. Separation unit 259 can be operatively fluidly coupled to liquid storage tank 237 through conduit 261 for oil storage produced and separated in the liquid storage tank; the gas storage tank 241 by a gas storage duct 265 produced in the gas storage tank; and an ion filter to produce a low salinity treated water and a brine solution from the separated produced water.
[0085] The first well 201 can be used to introduce the low salinity aqueous fluid and, optionally, thereafter, the oil-immiscible formulation into formation 205 and the second well 203 can be used to produce and separate the oil, water and gas from training for a first period of time; then the second well 203 can be used to introduce the low salinity aqueous fluid and optionally thereafter the oil-immiscible formulation into formation 205 and the first well 201 can be used to produce and separate the oil, water and gas from training for a second period of time; wherein the first and second time periods comprise a cycle. Multiple cycles can be performed that include alternating the first well 201 and the second well 203 between the introduction of the low salinity aqueous fluid and, optionally, thereafter, the oil-immiscible formulation in formation 205, and the production and separation of oil, water and gas from the formation, where one well is introducing and the other is producing and separating for the first period of time, and then they are switched for a second period of time. A cycle can be from about 12 hours to about a year, or from about 3 days to about 6 months, or from about 5 days to about 3 months. Low salinity aqueous fluid can be introduced into the formation at the beginning of a cycle and the oil-immiscible formulation can be introduced at the end of the cycle. In some embodiments, the start of a cycle can be the first 10% to about 80% of a cycle, or the first 20% to about 60% of a cycle, the first 25% to about 40% of a cycle. one cycle, and the end can be the remainder of the cycle.
[0086] Referring now to Fig. 9, in an alternative embodiment of a process of the present invention, the demulsifier can be introduced into the production well, which can be either the first well 201 or the second well 203 as described above, and produced together with oil and water. Demulsifier does not need to be added to each of the 235 or 259 separation units when it is introduced and produced from the production well. The process of this embodiment of the invention may be as described above, except that the demulsifier is introduced into the production well and may not need to be added to any separating unit 235 or 259 to demulsify produced oil and water. When oil and water are produced from the first well 201, demulsifier can be supplied from the demulsifier storage facility 271 through pipeline 279 to a pumping mechanism located in the first well 201 for injection into the first well 201. Demulsifier can be injected into the first well 201 through an injection line attached to the outside of the injection and production tube or into the first well to be dispensed immediately downstream of the wellhead, or by pumping the demulsifier to the circular casing crown of production of tubes from the first well to be dispensed immediately downstream of the wellhead, or by injecting the demulsifier into a production manifold within the first well. When oil and water are produced from the second well 203, demulsifier can be supplied from the demulsifier storage facility 271 through pipeline 277 to a pumping mechanism located in the second well 203 for injection into the second well. Demulsifier can be injected into the second well 203 through an injection line attached to the outside of the production injection tube or into the second well to be dispensed immediately downstream of the wellhead, or by pumping the demulsifier to the circular shell casing of production of tubes from the second well to be dispensed immediately downstream of the wellhead, or by injecting the demulsifier into a production manifold within the second well.
[0087] The demulsifier can be a demulsifier solution as described above, containing from 0.1% by weight to 5% by weight, or between 0.5% by weight to 2.5% by weight, or from 1% by weight weight, to 2% by weight of the demulsifying compound(s) as described above. The demulsifying solution can be injected into the production well, in an amount sufficient to provide between 0.05% by volume and 5% by volume, Or between 0.1% by volume and 2% by volume of the demulsifying solution in a mixture of demulsifier solution, oil, and water that is produced from the production well.
[0088] The produced demulsifier can be supplied with the mixture of produced oil and produced water to the separation unit 235 or 259 to assist in the separation of the oil produced from the produced water. Brine solution can be added to the mixture of produced oil, produced water, and demulsifier in separation unit 235 or 259 to induce a rapid separation of the produced oil and the produced water into separate phases, as described above. If desired, additional demulsifier can be added to the mixture of produced oil, produced water, produced demulsifier, and a brine solution in separation unit 235 or 259 to aid in separating the produced oil from the produced water.
[0089] Referring now to Figure 10 an array of wells 600 is illustrated. Arrangement 600 includes a first well group 602 (denoted by horizontal lines) and a second well group 604 (denoted by diagonal lines). In some embodiments of the method of the present invention, the first well of the above-described method may include several first wells described as the first group of well 602 in array 600, and the second well of the above-described method may include several second wells described as the second group of well 604 in the 600 array.
[0090] Each well in the first well group 602 can have a horizontal distance 630 from an adjacent well in the first well group 602. The horizontal distance 630 can be from about 5 to about 5,000 meters, or about 7 to about 1000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters. Each well in the first well group 602 can be a vertical distance 632 from an adjacent well in the first well group 602. The vertical distance 632 can be from about 5 to about 5,000 meters, or about 7 to about 1,000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.
[0091] Each well in the second well group 604 can be a horizontal distance 636 from an adjacent well in the second well group 604. The horizontal distance 636 can be from about 5 to about 5,000 meters, or about 7 to about 1,000 meters, or from about 10 to about 500 meters, or from about 20 to about 250 meters, or from about 30 to about 200 meters, or about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters. Each well in the second well group 604 can be a vertical distance 638 from an adjacent well in the second well group 604. The vertical distance 638 can be from about 5 to about 5,000 meters, or from about 7 to about 1000 meters, or from about 10 to about 500 meters, or about 20 to about 250 meters, or about 30 to about 200 meters, or about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.
[0092] Each well in the first well group 602 may be a distance 634 from adjacent wells in the second well group 604. Each well in the second well group 604 may be a distance 634 from adjacent wells in the first well group 602. The distance 634 can be from about 5 to about 5,000 meters, or about 7 to about 1,000 meters, or about 10 to about 500 meters, or about 20 to about 250 meters, or about 30 to about 200 meters, or from about 50 to about 150 meters, or from about 90 to about 120 meters, or about 100 meters.
[0093] Each well in the first well group 602 can be surrounded by four wells in the second well group 604. Each well in the second well group 604 can be surrounded by four wells in the first well group 602.
[0094] In some embodiments, the well array 600 may have from about 10 to about 1000 wells, for example, from about 5 to about 500 wells of the first well group 602, and from about 5 to about 500 wells of the second group 604.
[0095] In some embodiments, the arrangement of wells 600 can be seen as a top view with the first group of wells 602 and also the second group of wells 604, being vertical wells spaced apart over a piece of land. In some embodiments, the arrangement of wells 600 can be viewed as a side view in well section of the formation with the first group of wells 602 and also the second group of wells 604 being horizontal wells spaced within the formation.
[0096] Referring now to Figure 11, an arrangement of wells 700 is illustrated. Array 700 includes a first well group 702 (indicated by horizontal lines) and a second well group 704 (denoted by diagonal lines). Array 700 may be an array of wells as described above with respect to array 600 of Figure 10. In some embodiments of the method of the present invention, the first well of the above-described method may include several first wells described as the first group of well 702 in array 700, and the second well of the above-described method may include several second wells described as the second group of wells 704 in array 700.
[0097] The low salinity aqueous fluid and, optionally, subsequently the oil-immiscible formulation can be injected into the first well group 702 and oil, water and gas can be produced and separated from the second well group 704. As illustrated, the low salinity aqueous fluid, optionally the oil immiscible formulation, can have an injection profile 706, and the oil, water and gas can be produced from the second well group 704 having a recovery profile 708.
[0098] The low salinity aqueous fluid, and optionally subsequently the oil-immiscible formulation, can be injected into the second well group 704 and also oil, water and gas can be produced from the first well group 702. How well illustrated, the low salinity aqueous fluid, optionally the oil-immiscible formulation can have an injection profile 708, and the oil, water and gas can be produced from the first well group 702 having a recovery profile 706.
[0099] The first group of well 702 can also be used to inject the aqueous fluid of low salinity and, optionally, subsequently, the oil-immiscible formulation, and the second group of well 704 can also be used for the production of oil, water and gas from formation for a first period of time; then, the second set of wells 704 can be used to inject the low salinity aqueous fluid and optionally subsequently the oil-immiscible formulation, and the first set of wells 702 can also be used for the production of oil, water and gas from the formation for a second time period, where the first and second time periods comprise a cycle. In some embodiments, multiple cycles may be performed that include alternating the first and second groups of well 702 and 704 between injecting the low salinity aqueous fluid and, optionally, thereafter, the oil-immiscible formulation, and production oil, water , and gas from the formation, where one well group is injecting and the other is producing for a first period of time, and then they are switched to a second period of time.
[00100] To facilitate a better understanding of the present invention, the following example of certain aspects of some embodiments is given. In no way should the following example be read to limit or define the scope of the invention. EXAMPLE
[00101] The separation effect of a brine solution from low salinity water has been determined. 200 ml of a light crude oil, from an oil-bearing formation was emulsified with 200 ml of water from the formation, where the water had a total dissolved solids content of 6042 ppm and an ionic strength of 0.11m. The resulting emulsion was separated into two 150 ml portions. 75 ml of low salinity water having a TDS content of 6042 ppm and an ionic strength of 0.11 m was added to one of the emulsion portions and 75 ml of a brine solution having a TDS content of 77.479 ppm and an ionic strength of 1.54 m was added to the other portion of the emulsion. The portion of the emulsion with the lowest salinity water was separated into two samples and the portion of the emulsion with the brine solution was separated into two samples. 2 ml of a 1% solution of DROP emulsifier in toluene was added to an emulsion with water samples of low salinity and to one of the emulsion with samples in brine solution. Each of the samples was then mixed by shaking. After shaking, each sample was monitored to determine the time required for separation of the oil phase from the aqueous phase. The results are shown in Fig. 12. As shown in Fig. 12, the sample containing the brine solution and the demulsifier reached final phase separation approximately 5 times faster than the sample containing the formation of low salinity water and the demulsifier, while the samples containing the low salinity water formation and the brine solution without demulsifier could not separate into separate phases.
[00102] The present invention is well adapted to achieve the aforementioned purposes and advantages, as well as those that are inherent to it. The particular embodiments described above are only illustrative, as the present invention may be modified and practiced in different, but equivalent ways evident to those skilled in the art having the benefit of the teachings herein. In addition, no limitations are intended on the construction or design details presented herein, except as described in the claims below. Although systems and methods are described in terms of "comprising", "containing", or "including" various components or steps, compositions and methods may also "consist essentially of" or "consist of" various components and steps. Whenever a numerical range, with a lower limit and an upper limit, is disclosed, any number and any included range fall within the specifically disclosed range. In particular, each range of values (in the form of "from aab", or, equivalently, "from a-b") described herein is to be understood as defining each number and variety encompassed within the wider range of values. . Where a numerical range has only a specific lower limit, only a specific upper limit, or a specific upper limit and a lower limit is disclosed, the range may also include any numerical value "over" the given lower limit and/or the limit. specified top. Furthermore, the terms of the claims have their normal, ordinary meaning, unless expressly and clearly defined by the patent holder. Furthermore, the indefinite articles "a" or "an" as used in the claims are defined herein to mean one or more than one of the elements they introduce.

权利要求:
Claims (10)
[0001]
1. A process for producing oil, comprising: introducing an aqueous fluid into a formation (205) bearing oil; and produce oil and water from the subsequent formation (205) for the introduction of the aqueous fluid into the formation (205); characterized by: passing a saline source water (111), having a total dissolved solids content greater than 5,000 ppm, through an ion filter (113) to produce the treated water (115) having reduced salinity relative to the source water (111) while excluding at least a portion of the source water (111) from passing through the ion filter (113 ) to form a retentate (117) having increased salinity relative to source water (111); using at least a part of the treated water (115) having reduced salinity as at least part of the aqueous fluid, the aqueous fluid having an ionic strength of a maximum of 0.15 M and a total dissolved solids content of between 200 ppm and 10000 ppm; mix a demulsifier and a brine solution having a total dissolved solids content of greater than 10,000 ppm, with at least one portion of oil and water produced from the training (205); and separating the oil from the mixture of oil, water, demulsifier, and a brine solution, wherein at least a portion of the retentate (117) is used as at least a portion of the brine solution.
[0002]
2. Process according to claim 1, characterized in that the brine solution has a total dissolved solids content of at least 15,000 ppm, or at least 20,000 ppm, or at least 25,000 ppm, or at least 30,000 ppm , or at least 40,000 ppm, or at least 50,000 ppm.
[0003]
A process according to any one of claims 1 or 2, characterized in that it further comprises the step of introducing a drive fluid into the subsequent formation (205) to introduce the aqueous fluid into the formation (205).
[0004]
4. Process according to any one of claims 1 to 3, characterized in that the formation (205) carrying oil further comprises connate water having a divalent ion concentration, in which the aqueous fluid has a divalent ion concentration, and wherein the aqueous fluid divalent ion concentration is less than the connate water divalent ion concentration.
[0005]
5. Process according to any one of claims 1 to 4, characterized in that the water produced from the formation (205) comprises water that is emulsified with at least a portion of the oil produced from the formation (205) and free water that is separable from oil produced from demulsification absent from formation (205), and oil produced from formation (205) comprises oil that is emulsified with at least a portion of the water produced from formation and oil free water that can be separated from the water produced from the demulsification absent in the formation, further comprising the step of separating the free water and the free oil from the emulsified oil and emulsified water before mixing the brine solution with the oil and the water produced to from formation (205).
[0006]
6. Process according to any one of claims 1 to 5, characterized in that the saline source water (111) has a total content of dissolved solids greater than 10,000 ppm.
[0007]
7. Process according to any one of claims 1 to 6, characterized in that the ion filter (113) is comprised of a first ion filter (119) and a second ion filter (121); and that the process further comprises the steps of: contacting a portion of the saline source water (111) with a first ionic filter (119); passing a portion of the saline source water (111) through the first ionic filter (119) to forming a first permeate (123) having low salinity relative to the saline source water (111) while excluding at least a portion of the saline source water (111) in contact with the first ion filter (119) from passing through the first ionic filter (119) to form a first retainer (125) having increased salinity relative to the saline source water (111); contacting a portion of the saline source water (111) with the second ionic filter (121); from the saline source water (111) through the second ion filter (121) to form a second permeate having low salinity relative to the saline source water (111) while excluding at least a portion of the saline source water (111) in contact with the second ion filter (121) to pass through the second ionic filter (121) to form a second retentate (127) having increased salinity relative to saline source water (111); using the first permeate and second permeate (123) as at least a portion of the injected aqueous fluid in forming (205); using the first retentate (125), the second retentate (127), or a mixture of the first retentate (125) and the second retentate (127) as at least a portion of the brine solution that is mixed with oil and water produced from the formation (205).
[0008]
8. Process according to claim 7, characterized in that the first ion filter (119) is a nanofiltration membrane and the second ion filter (121) is a reverse osmosis membrane.
[0009]
9. Process according to any one of claims 1 to 8, characterized in that the formation (205) bearing oil is an underground sandstone formation comprising a mineral with a negative zeta potential.
[0010]
10. Process according to any one of claims 1 to 9, characterized in that the formation (205) bearing oil is an underground carbonate formation comprised of microcrystalline limestone, dolomite or a mixture thereof.

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法律状态:
2018-11-21| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|

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2020-01-14| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|

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2021-03-09| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|

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2021-05-25| B16A| Patent or certificate of addition of invention granted [chapter 16.1 patent gazette]|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 07/08/2013, OBSERVADAS AS CONDICOES LEGAIS. |

优先权:

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申请号 | 申请日 | 专利标题

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US201261681232P| true| 2012-08-09|2012-08-09|

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US61/681,232|2012-08-09|

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PCT/US2013/053896|WO2014025847A1|2012-08-09|2013-08-07|Process for producing and separating oil|

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