systems for oil production and separation

专利摘要:
SYSTEMS FOR OIL PRODUCTION AND SEPARATION. The present invention relates to systems for producing and separating oil. The system comprises an oil-bearing formation; an aqueous fluid of low salinity that has an ionic strength of less than 0.15M and has a total dissolved solids content of 200 PPM up to 10,000 PPM; a brine solution that has a total dissolved solids content greater than 10,000 PPM; and, a demulsifier. The system further comprises a mechanism for introducing the low salinity aqueous fluid into the oil-bearing formation, a mechanism for producing oil and water from the formation subsequent to the introduction of the low salinity aqueous fluid into the formation, and a mechanism for bringing into contact the brine solution and the demulsifier with the oil and water produced from the formation and for the separation of the oil produced from the water produced.
公开号:BR112015002730B1
申请号:R112015002730-0
申请日:2013-08-07
公开日:2021-05-04
发明作者:Albert Joseph Hendrik Janssen；Bartholomeus Marinus Josephus Maria Suijkerbuijk
申请人:Shell Internationale Research Maatschappij B.V.；
IPC主号:

专利说明:

technical field
[001] The present invention relates to a system for producing hydrocarbons from a hydrocarbon-bearing formation. In particular, the present invention relates to a system for producing hydrocarbons and water from a hydrocarbon-bearing formation and separating hydrocarbons from water. Fundamentals of Invention
[002] Only a portion of oil present in an oil-bearing formation is recoverable as a result of the formation's natural pressure. The oil recovered from this “primary” recovery ranges from 5% to 35% of the oil in the formation. Higher oil recovery methods have been developed to increase the volume of oil that can be recovered from an oil-bearing formation above and beyond that recovered in primary recovery.
[003] Continuous water injection, in which water is injected through an injection well into an oil-bearing formation to mobilize and compel oil through the formation for production by a production well, is a widely used method of secondary recovery , used to increase the volume of oil recovered from a formation beyond primary recovery. Recently, continuous water injection using water with low salinity has been used to increase the volume of oil recovered from a formation in relation to the processing volume in a conventional continuous injection of water with higher salinity. Low salinity water can be used in place of higher salinity water conventionally used in a continuous water injection in a secondary recovery, or low salinity water can be used after a conventional continuous injection of higher salinity water to incrementally increase recovery of oil above that of the initial continuous water injection in a tertiary recovery process.
[004] Low salinity water used in continuous injection of low salinity water has a lower ionic intensity than connate water present in the formation, typically having an ionic intensity of 0.15 M or less, and having a total solids content dissolved products (“TDS”) of 200 parts per million (“PPM”) at 1,000 PPM and a multivalent cation content less than the multivalent cation content of connate water. Injection of low salinity water into a formation can reduce the ionic binding of oil to formation within pores in the formation by double layer expansion, leading to a reduction in the rock's adsorption capacity for hydrocarbons. This increases the mobility of oil in the formation by making the formation's pore surface more water-wetted and less oil-wetted, allowing the mobile oil to be removed from the pores in which it resides and be compelled to a production well for production of the formation.
[005] In an improved oil recovery process using continuous injection of water, oil and water, and typically gas, are also produced together from the formation. Oil, water and gas are separated in a separator to recover oil 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 coalescer which helps to break the emulsion by 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 the phases. Separated phases can then be retrieved separately.
[006] Improved systems and processes for separating oil and water produced from an oil-bearing formation by low salinity hoist enhanced oil recovery process are desirable. Invention Summary
[007] In one aspect, the present invention relates to a system, comprising: an oil-bearing formation; a low salinity aqueous fluid having an ionic strength less than 0.15 M and having a total dissolved solids content of 200 PPM to 1000 PPM; a brine solution having a total dissolved solids content greater than 1,000 PPM; a demulsifier; a mechanism for introducing the low salinity aqueous fluid into the oil-bearing formation; a mechanism for producing oil and water from the oil-bearing formation subsequent to the introduction of the low salinity aqueous fluid into the formation; and a mechanism for contacting the brine solution and the demulsifier with the oil and water produced from the oil-bearing formation and for separating the produced oil from the produced water.
[008] In another aspect, the present invention relates to a system, comprising: an oil-bearing formation; a low salinity aqueous fluid having an ionic strength less than 0.15 M and having a total dissolved solids content of 200 PPM to 1000 PPM; a brine solution having a total dissolved solids content greater than 1,000 PPM; a demulsifier; a mechanism for introducing the low salinity aqueous fluid into the oil-bearing formation; a mechanism for producing oil and water from the oil-bearing formation subsequent to the introduction of the low salinity aqueous fluid into the formation; a mechanism for contacting the brine solution and the demulsifier with the oil and water produced from the oil-bearing formation and a mechanism for separating the produced oil from the produced water after contacting the produced oil and the produced water with the brine solution and the demulsifier .
[009] In another aspect, the present invention relates to a system, comprising: an oil-bearing formation; a low salinity aqueous fluid having an ionic strength less than 0.15M and having a total dissolved solids content of 200 PPM to 1000 PPM; a brine solution having a total dissolved solids content greater than 1,000 PPM; a demulsifier; a mechanism for introducing the low salinity aqueous fluid into the oil-bearing formation; a mechanism comprising a production well for producing oil and water from the oil-bearing formation subsequent to the introduction of low salinity aqueous fluid into the formation; a mechanism to introduce the demulsifier into the production well and mix it with the produced oil and produced water in the produced well; a mechanism for contacting the brine solution with the mixture of produced oil, produced water and demulsifier; and a mechanism for separating the produced oil from the mixture of produced oil, produced water, brine solution and demulsifier. Brief description of drawings
[0010] Figure 1 is a diagram of an ion filter that can be used in the system of the present invention.
[0011] Figure 2 is a diagram of an ion filter that can be used in the system of the present invention.
[0012] Figure 3 is a diagram of an ion filter that can be used in the system of the present invention.
[0013] Figure 4 is a diagram of an oil production and separation system according to the present invention.
[0014] Figure 5 is a diagram of an oil and water separation unit that can be used in the system of the present invention.
[0015] Figure 6 is a diagram of an oil and water separation unit that can be used in the system of the present invention.
[0016] Figure 7 is a diagram of an oil and water separation unit that can be used in the system of the present invention.
[0017] Figure 8 is a diagram of an oil and water separation unit that can be used in the system of the present invention.
[0018] Figure 9 is a diagram of an oil production and separation system according to the present invention.
[0019] Figure 10 is a well pattern diagram for oil production that can be used in the system of the present invention.
[0020] Figure 11 is a well pattern diagram for oil production that can be used in the system of the present invention.
[0021] Figure 12 is a chronological chart for oil and water separation. Detailed description of the invention
[0022] It was found that when using an enhanced oil recovery process through continuous injection of low salinity water, a problem arises in the separation of oil produced from water that was produced along with the oil. In particular, it has been found that at least a portion of the oil and water produced by an oil-bearing formation form a cohesive emulsion when employing an enhanced oil recovery process through continuous injection of low salinity water. Cohesive emulsion is significantly more difficult to break down and separate than oil/water emulsions formed using conventional continuous injection of higher salinity water.
[0023] The present invention relates to the recognition of this problem and application of a system to reduce or eliminate the cohesive oil/water emulsion. In one aspect, the present invention relates to a system comprising an oil-bearing formation, a low salinity aqueous fluid having a concentration of at most 0.15M and a total dissolved solids content (hereinafter, "TDS" ) from 200 PPM to 1000 PPM, a brine solution having a TDS content greater than 1000 PPM, and a demulsifier. The system further comprises a mechanism for introducing the low salinity aqueous fluid into the driving force and a mechanism for producing oil and water from the formation subsequent to the introduction of the aqueous fluid into the formation. The system further comprises a mechanism for contacting the brine solution and the demulsifier with the oil and water produced from the formation produced water and a mechanism for separating the produced oil from the produced water upon contact with the brine solution and the demulsifier.
[0024] In another aspect, the present invention relates to a system comprising an oil-bearing formation, an aqueous fluid of low salinity having an ionic concentration of at most 0.15 M and a TDS content of 200 PPM to 1,000 PPM, a brine solution having a TDS content greater than 1,000 PPM, and a demulsifier. The system further comprises a mechanism for introducing the low salinity aqueous fluid into the oil-bearing formation, a mechanism comprising a production well for producing oil and water from the formation subsequent to the introduction of the low salinity aqueous fluid into the formation, and a mechanism for introduction of demulsifier into produced oil and produced water in or within the production well to form a mixture of produced oil, produced water, demulsifier and brine solution.
[0025] The low salinity aqueous fluid provided for introduction into the oil-bearing formation has a TDS content of 200 PPM to 1000 PPM and an ionic strength of at most 0.15 M. The low salinity aqueous fluid may have a TDS content from 5500 PPM to 7,000 PPM, or from 1,000 PPM to 5,000 PPM, or from 1,500 PPM to 4,500 PPM. The low salinity aqueous fluid may have an ionic strength of 0.01 M to 0.15 M, or 0.02 M to 0.125 M, or 0.03 M to 0.1 M. 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 intensity lower than the ionic intensity of the connate water present in the Fo, and/or a multivalent cationic concentration lower than that of the connate water present in the oil-bearing formation, and/ or a divalent cation concentration less than the divalent cation concentration of the connate water present in the oil-bearing formation. The fraction of the ionic intensity of the low salinity aqueous fluid in relation to the ionic intensity of the connate water may be less than 1, or it may be less than 0.9, or less than 0.5, or less than 0, 1, or between 0.01 to, but not inclusive, 1, or from 0.05 to 0.9, or from 0.1 to 0.8. The fraction with multivalent cation content of the low salinity aqueous fluid, in relation to the multivalent cationic content of the conate water, may be less than 1, or it may be less than 0.9, less than 0.5, or less than 0.1, or between 0.01 to, but not inclusive, 1, or 0.05 to 0.9, or 0.1 to 0.8. The fraction of the divalent ion content of the low salinity aqueous fluid in relation to the divalent ion content of the conate water may be less than 1, or it may be less than 0.9, less than 0.5, or less than 0.1, or between 0.01 to, but not inclusive, 1, or from 0.05 to 0.9, or from 0.1 to 0.8.
The low salinity aqueous fluid may have a relatively low multivalent cation content and/or a relatively low divalent cation content. This low salinity aqueous fluid may have a multivalent cationic 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 at 1 PPM to 200 PPM, or from 2 PPM to 100 PPM, or from 3 PPM to 75 PPM, or from 4 PPM to 50 PPM, or from 5 PPM to 25 PPM. Low salinity aqueous fluid may have a divalent cationic concentration of no more than 1500 PPM, or a maximum of 100 PPM, or a maximum of 75 PPM, or a maximum of 50 PPM, or a maximum of 25 PPM, or from 1 PPM to 100 PPM, or from 2 PPM to 75 PPM, or from 3 PPM to 50 PPM, or from 4 PPM to 25 PPM, or from 5 PPM to 20 PPM.
[0028] The low salinity aqueous fluid can be provided from a natural source. The low salinity aqueous fluid of the oil-bearing formation, or a river comprising water containing 200 PPM to 10,000 PPM of total dissolved solids. The low salinity aqueous fluid may be provided by process water from a natural source, such as an aquifer, lake, or river, or from produced water from an oil-bearing formation in which the water from the natural source or the carrier formation of oil has a TDS content of 0 PPM to 200 PPM and where the TDS content of water can be adjusted to 200 PPM to 10,000 PPM by adding one or more salts, eg NaCl and/or CaCh, to the water;
[0029] Alternatively, the low salinity aqueous fluid, or at least a portion thereof, may be provided by processing a saline spring water to produce the low salinity aqueous fluid. The saline spring water to be processed may have a TDS content greater than 10,000 PPM, if the low salinity aqueous fluid produced by the saline spring water processing should have a TDS content of 200 PPM to 10,000 PPM, or the water from saline fountain can have a saline spring water content must have a TDS content of at least 5,000 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 saline source water to be processed can be selected from the group consisting of aquifer water, sea water, brackish water, produced water from oil-bearing formation, water from an oil mixture, water and a brine solution formed in the separation of oil produced from produced water subsequent to the separation of oil from the mixture, as described below, and mixtures thereof.
[0030] Referring now to Figure 1, saline spring water having a TDS content greater than 10,000 PPM, or a TDS content greater than 5,000 PPM, as described above, can be processed to produce at least a portion of the fluid low salinity aqueous for introduction into the oil-bearing formation by contacting the saline spring water 111 with an ion filter 113, where the mechanism for processing the saline spring water may comprise an ion filter. A portion of the source water 111 may be passed through the ion filter 113 to form treated water 115 with reduced salinity relative to the source water 111, where the treated water may have a TDS content of less than 10,000 PPM and, more preferably, from 200 PPM to 10,000 PPM, more preferably from 200 PPM to 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 greater 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 oil and water produced, as described in more detail below. The system may further comprise a mechanism for producing the brine solution, where the mechanism for producing this solution may comprise an ion filter 113.
[0032] If the permeate has a TDS content less than 200 PPM, the permeate can be treated to adjust the TDS content to a range of 200 PPM to 5,000 PPM. A portion of the retentate 117 can be added to the permeate to adjust the TDS content to a range of 200 PPM to 5,000 PPM.
[0033] The ion filter 113 of the system of the present invention may be a membrane-based system using 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 be comprised of one or more nanofiltration membranes effective to preferentially or 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 supplied to the nanofiltration membrane(s), and the retentate may contain a corresponding increase in multivalent ions relative to the source water . The one or more nanofiltration membranes of a nanofiltration membrane unit can also moderately reduce the monovalent ion content of the source water supplied 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 supplied to the nanofiltration membrane(s), and the retentate may contain a corresponding increase in monovalent ions with respect to spring water. Nanofiltration membranes can be formed from charged polymeric materials (eg, having carboxylic acid, sulfonic acid, amine, or starch functional groups) including polyamides, cellulose acetate, piperazine, or substituted piperazine membranes, on which a thin layer of Ion discriminating membrane is supported on a thicker porous material, which is sandwiched between the discriminating layer and a reinforcing material. Suitable commercially available nanofiltration membranes in sheet form or spiral form that 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. by GE Osmonics, Cutting Insert., 5951 Clearwater Drive, Minnetonka, MN 55343, United States; NF200 series, and NF-55, NF-70 and NF-90 series available from Dow FilmTec Corp., 5239 W. 73rd Street, Minneapolis, MN, 55345, United States; DS-5 and DS-51 by Desalination Systems, Inc., 760 Shadowridge Dr., Oceanside, 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 mentioned than 90%, or less than 95%, or less than 98%, than the source water supplied to the reverse osmosis membrane(s), and the retentate may contain a corresponding ion increase in relation to source water. Reverse osmosis membranes can be spiral-wound or hollow fiber modules, 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 first and second polymeric material, such as cross-linked aromatic polyamides in combination with a polysulfone. Suitable commercially available reverse 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, from GE Osmonics; SW30 and LF series, from Dow FilmTec Corp.; DESAL-11, available from Desalination Systems, Inc.; ESPA, made available by Hydronautics; ULP™ from Fluid Systems, Inc.; and ARCO MEDIAL, available from TriSep Corp., 93 S. La Patera Lane, Goleta, CA 93117, United States.
[0035] Typically, pressure has to be applied through the ion filter 113 to overcome the osmotic pressure across the membrane when the saline source water 111 is filtered, to reduce the TDS content of the source water and produce treated water 115. The pressure applied through ion filter 113 can be at least 2.0 MPa, or at least 3.0 MPa, or at least 4.0 MPa, and can be at most 10.0 MPa, or at most 9, 0 MPa, or at most 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 unit in the ion filter 113 may be in the lower portion of the pressure range relative to the pressure applied through a reverse osmosis membrane. The pressure applied through an ion filter 113 nanofiltration membrane unit can range from 2.0 MPa to 6.) MPa, and the pressure applied through a reverse osmosis membrane. The pressure applied through a nanofiltration membrane unit on the ion filter 113 can range from 2.0 MPa to 6.0 MPa, and the pressure applied through a reverse osmosis membrane unit on the ion filter 113 can range from 4 .0 MPa to 10.0 MPa. If the ion filter 113 is comprised 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 per at least 0.5 MPa, since less pressure is needed to overcome the osmotic pressure of the permeate of a preceding membrane unit.
[0036] Referring now to Figure 2, the ion filter 113 can be comprised of a first ionic membrane unit 119 and one or more second ionic membrane units arranged in series, where each ionic membrane unit can be a membrane unit of nanofiltration or a reverse osmosis membrane unit. The saline spring water 111 having a TDS content greater than 10,000 PPM or greater than 5000 PPM, as described above, can be contacted with the first ionic membrane unit 119 to pass at least a portion of the saline spring water through the first ionic membrane unit to form a permeate 123 having a reduced TDS content relative to saline source water, where the permeate may have a TDS content of at least 1000 PPM, or at least 2500 PPM, or at least 5,000 PPM, or at least 7,000 PPM, or at least 10,000 PPM. A portion of the saline source water may be excluded from passing through the first ionic membrane unit 119 to form a primary retentate 125 having greater salinity relative to the source water. Permeate 123 may be contacted with each of the second ionic membrane units 121 in sequence to pass 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 saline source water, where the treated water may have a TDS content of less than 10,000 PPM and preferably from 200 PPM to 5,000 PPM. At least a portion of the treated water 115 can be used as at least a portion of low salinity aqueous fluid that is introduced into the oil-bearing formation. A portion of the permeate 123 may be excluded from passing through one or each of the 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 retentate primary 125 and one or more of the secondary retentates 127 may be used as retentate 117 of ion filter 113, where retentate 117 has a higher salinity relative to source water 111 and may 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 oil and water produced, as described in more detail below.
[0037] If the permeate has a TDS content less than 200 PPM, the permeate can be treated to adjust the TDS content to a range of 200 PPM to 5,000 PPM. A portion of the primary retentate or one or more secondary retentates can be added to the permeate to adjust the TDS content to a range of 200 PPM and 5,000 PPM.
[0038] Referring now to figure 3, the ion filter 113 can be comprised of a first ionic membrane unit 129 and a second ionic membrane unit 131 arranged in parallel, where the first ionic membrane unit can be comprised of one or more nanofiltration membranes or one or more reverse osmosis membranes, or a combination thereof, and the second ionic membrane unit may be comprised of one or more nanofiltration membranes, one or more reverse osmosis membranes, or a combination the same. A portion 133 of the saline source water 111, as described above, may be contacted with the first ionic membrane unit 129 and a portion of the saline source water 133 may be passed through the first ionic membrane unit 129 to form a first permeate 135 having TDS content reduced to less than 10,000 PPM, or less than 7,000 PPM, or mentioned than 5,000 PPM, or from 1,000 PPM to 5,000 PPM. A portion of the saline spring water portion 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 saline spring water 111.0. The first retentate 137 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. A separate portion 139 of the saline source water 111 may be contacted with the second ionic membrane unit 131, and a portion of the saline source water portion 139 may be passed through the second ionic membrane unit 131 to form a second permeate 141 having a reduced TDS content relative to salt spring water 111.0 second permeate may have a TDS content of less than 10,000 PPM, or less than 7,000 PPM, or less than 5,000 PPM, or from 200 PPM to 5,000 PPM. A portion of the saline source water portion 139 may be excluded from baking 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 7,000 PPM, or less than 5,000 PPM, or 200 PPM to 10,000 PPM, or from 500 PPM to 5,000 PPM, where 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 brine solution used. to separate the oil and water produced, as described in more detail below.
[0039] 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, provided that one or more reverse osmosis membranes from the second ionic membrane unit 131 remove substantially all of the total dissolved solids from the water. salt source 111.0 first permeate 135 passed through nanofiltration membranes may have sufficient monovalent ions to have a TDS content of at least 200 PPM, or at least 500 PPM, or at least 1,000 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 can 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
[0040] In the system of the present invention, the aqueous fluid of low salinity, which can be provided from a natural source or by processing source water having a TDS content greater than 10,000 PPM, or greater than 5,000 PPM, as described above, is introduced into the oil-bearing formation. The oil-bearing formation of the system of the present invention can be comprised 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 introducing the low salinity aqueous fluid into the formation.
[0041] The porous matrix material of the formation may be comprised 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 rock matrix porous. The formation can comprise one or more minerals having a negative surface net electrical charge leading to negative zeta potentials under formation conditions (temperature, pressure, pH, and salinity). Higher levels of minerals having a negative zeta potential in a formation have been correlated with greater oil recovery when using an aqueous fluid of low salinity as an oil recovery agent. "Formation condition", when used in the context of zeta potential here, is defined as the temperature and pressure of the formation and the pH and salinity of water in the formation. Formation 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 formation water salinity 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 electrical current is passed via 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 ROM 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 from 10% to 30% of at least one mineral having a negative zeta potential. X-ray diffaction measurements, surface charge titrations, and streaming potential measurements in crushed rock formation can be used to determine the amount of such minerals in the formation.
[0042] The porous matrix material of rock and/or mineral of the formation can be comprised of sandstone and/or a carbonate selected among dolomite, limestone and its mixtures - where the limestone can be microcrystalline or crystalline limestone. If the formation is comprised of prose carbonate rock, the formation may contain some gypsum, or it may be absent from the formation, as oil-bearing formations containing significant amounts of gypsum may not be particularly susceptible to oil recovery using oil injections. low salinity water.
[0043] Minerals that can form the porous mineral matrix material having a negative zeta potential can be clays or transition metal compounds. Clays with a negative zeta potential that can form at least a portion of the porous mineral matrix material include smectite clays, smectite/ilite clays, montmorillonite clays, illite clays, illite/mica clays, pyrophyllite clays, clays of glauconite and kaolinite clays, transition metal composite minerals having a negative zeta potential that can form at least a portion of the mineral's porous matrix material include carbonates and oxides, for example, iron oxide, siderite, and plagioclastic feldspars.
[0044] The porous matrix material can be a consolidated matrix material in which at least a major part and preferably all of the rock and/or mineral that forms the matrix material is consolidated, so that the rock and/ or mineral forms a mass in which substantially all of the rock and/or mineral is immobile when oil, low salinity aqueous fluid, or other fluid is passed through it. Preferably, at least 95% by weight, or at least 97% by weight, or at least 99% by weight of the rock and/or mineral becomes immobile when oil, low salinity aqueous fluid or other fluid is passed through it. so that no amount and material of rock or mineral displaced by the passage of oil, low salinity aqueous fluid, or other fluid is insufficient to make the formation impervious to the flow of oil, low salinity aqueous fluid, or other fluid through the formation. Alternatively, the porous matrix material may be an unconsolidated matrix material in which at least most, or substantially all of the rock and/or mineral forming the matrix material is unconsolidated. The formation, if formed from a consolidated mineral matrix, an unconsolidated mineral matrix, or combinations thereof, may have a permeability of 0.00001 to 15 Darcy, or from 0.001 to 1 Darcy.
[0045] The oil-bearing formation can be an underground formation. The underground formation may be comprised of one or more of the porous matrix materials described above, where the porous matrix material may be located under a waste rock at a depth ranging from 50 meters to 6,000 meters, or from 100 meters to 4,000 meters, or 200 meters to 2000 meters below the ground surface. The underground formation can be an underwater formation.
[0046] The oil contained in the oil-bearing formation may have a viscosity under formation conditions (in particular, at temperatures within the temperature range of the formation) of at least 1 mPa.s (1 cP), or at least 10 mPa .s(10 cP), or at least 100 mPa.s(100 cP), or at least 1000 mPa.s(1000 cP). The oil contained in the oil-bearing formation can have a viscosity under conditions according to the emitting device at the formation temperature of 1 to 100,000 mPa.s (1 to 100,000 cP), or from 1 to 10,000 mPa.s (1 to 10,000 cP), or from 1 to 5,000 mPa.s (1 to 5,000 cP), or from 1 to 1,000 mPa.s (1 to 1,000 cP).
[0047] The oil in the oil-bearing formation can be located in pores within the porous matrix material of the formation. The oil in the oil-bearing formation can be immobilized in pores within the porous matrix material of the formation, 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.
[0048] The oil-bearing formation can also be comprised of water, which can be located in the pores within the porous matrix material. The water in the formation can be tap water, water from a continuous injection from a secondary or tertiary oil recovery process, or a mixture thereof. The tap water in the oil-bearing formation may have a TDS content of at least 500 PPM, or at least 1,000 PPM, or at least 2,500 PPM, or at least 5,000 PPM, or at least 10,000 PPM, or at least 25,000 PPM, or from 500 PPM to 250,000 PPM, or from 1,000 PPM to 200,000 PPM, or from 2,000 PPM to 100,000 PPM, or from 2,500 PPM to 50,000 PPM, or from 5,000 PPM to 45,000 PPM. 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 200 PPM to 40,000 PPM, or 250 PPM PPM to 20,000 PPM, or 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 from 150 PPM to 35,000 PPM, or from 200 PPM to 20,000 PPM, or of 250 PPM to 15,000 PPM.
[0049] The water in the oil-bearing formation can be positioned to immobilize oil within the pores. Introducing low salinity aqueous fluid into the formation can mobilize at least a portion of the oil in the formation for formation and recovery by releasing at least a portion of the oil from the pores within the formation. Introducing the low salinity aqueous fluid into the formation can make at least a portion of the formation surface more water-wet and less oil-wetted relative to the formation surface prior to introducing the low salinity aqueous fluid into the formation and contact. low salinity aqueous fluid with the formation, which can mobilize the oil to produce the formation.
[0050] The oil-bearing formation 103 must be a formation susceptible to the production of oil by injection of an aqueous fluid comprising water of low salinity in the formation and subsequent production and recovery of oil from the formation. Oil-bearing formations susceptible to oil production by improved oil recovery processes by continuous injection of low salinity water can be oil wetted or wetted by mixing, but not wetted by water, where a substantial portion of the pore surface in the formation is wetted with oil instead of water in an oil-wet or wet-mix formation. Preferably, the formation has an Amott-Harvey wettability 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, measured by the Amott-Harvey wettability test, and has a contact angle less than 110°, or less than 70°, or 0° to 110°. The formation also preferably contains a substantial amount of oil content in the reservoir, a portion of which can be recovered by mobilization using the low salinity aqueous fluid, provided the formation preferably has an initial water saturation (Swi ) less than 0.3.
[0051] Determining the suitability of a formation for oil recovery enhanced by low salinity aqueous fluid can be done by conducting conventional flow studies in drill cores over core plugs extracted from the formation, where low salinity water is used as the injector, and where core plugs are saturated with oil from the formation and with fresh water or water having a salinity matched to the salt water salinity of the formation and a comparable initial water saturation.
[0052] Referring now to Figure 4, a system 200 of the present invention is shown. The system includes a first well 201 and a second well 203 extending into an oil-bearing formation 205 as described above. The oil-bearing formation 205 may be comprised of one or more forming portions 207, 209 and 211 formed from matrices of porous material, as described above, located under a sterile 213. A low salinity aqueous fluid as described above is provided. The low salinity aqueous fluid may be provided from an aqueous fluid storage facility 215 fluidly operatively coupled to a first injection/production facility 217 via conduit 219. The first injection/production facility 217 may be fluidly operatively coupled to the first well 201, which can be located extending from the first injection/production facility 217 to the oil-bearing formation 205. The low salinity aqueous fluid can flow from the first injection/production facility 217 through the first well to be introduced into the formation 205 , for example, in the formation portion 209, where the first injection/production facility 217 and the first well, of the first well itself, include a mechanism for introducing the low salinity aqueous fluid into the 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 into the formation. The mechanism for introducing the low salinity aqueous fluid into formation 205 via the first well 201 - located in the first injection/production facility 217, the first well, or both - may be comprised of a pump 221 for discharging the low water fluid salinity for perforations or openings in the first PCO through which low salinity aqueous fluid can be introduced into the formation.
[0053] 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 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, where the low salinity aqueous fluid is injected under formation-filling conditions.
[0054] The volume of low salinity aqueous fluid introduced into formation 205 via the first well 201 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 pore, or from 0.2 to 0.9 pore volume, where the term "pore volume" roughly refers to the volume of the formation that can be swept by the low salinity aqueous fluid between orifice well 201 and second well 203 Pore volume can be readily determined by methods known to one skilled in the art, for example, by modeling studies or by injecting water having a tracer contained therein by forming 205 from the first PCO 201 to the second well 203.
[0055] As the aqueous fluid of low salinity is introduced into formation 203, it spreads into the formation. As shown by arrows 223. Upon introduction into formation 205, the low salinity aqueous fluid contacts the surface of the porous matrix material of the formation, and may change the surface to be more water-wet and less oil-wet. Introducing low salinity aqueous fluid into the formation can mobilize oil into the formation to produce the formation. The low salinity aqueous fluid can mobilize the oil in the formation, for example, by reducing the capillary forces that trap oil in the pores in the formation, by reducing the wettability of oil on pore surfaces in the formation, and/or by reducing tension interfacial between oil and water in the formation pores.
[0056] The mobilized oil and the low salinity aqueous fluid can be pushed through the formation 205, from the first well 201 to the second well 203, by additionally introducing more low salinity aqueous fluid or by introducing an oil-immiscible formulation in 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 introducing low salinity aqueous fluid into the formation, to force or otherwise displace the oil and low salinity aqueous fluid into towards the second well 203 for production.
[0057] The oil-immiscible formulation may be configured to displace oil as well as low salinity aqueous fluid through formation 205. The system of the present invention may comprise an oil-immiscible formulation and a mechanism for introducing this formulation in training. Suitable oil-immiscible formulations are not miscible on first contact or miscible by multiple contacts with oil in formation 205. The oil-immiscible formulation may be selected from the group consisting of an aqueous polymeric fluid form of water in gas or liquid, carbon dioxide to a pressure below its minimum miscibility pressure, nitrogen at a pressure below its minimum miscibility pressure, air, and mixtures of two or more of the foregoing.
[0058] Suitable polymers for use in an aqueous polymer fluid may include, but not limited to, polyacrylamides, partially hydrolyzed polyacrylamides, polyacrylates, ethylenic copolymers, biopolymers, carboxymethylcellulose, polyvinyl alcohols, polystyrene sulfonates, polyvinylpyrrolidones, AMPS (2- acrylamenide-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.
[0059] The oil-immiscible formulation can be stored, and provided for introduction into formation 205 from an oil-immiscible formulation storage facility 225 via conduit 227. The first injection/production facility 217 can be fluidly operatively coupled to the first well 201 to provide the oil-immiscible formulation to the first well for introduction into formation 205. Alternatively, the oil-immiscible formulation storage facility can be fluidly operatively coupled to the first well 201 directly, to provide the oil-immiscible formulation to the first well 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 via the first well 201 may be comprised of a pump or a compressor to dispatch the oil-immiscible formulation to drilling or drilling. in the first well, through which the oil-immiscible formulation can be injected into the formation. The mechanism for introducing the oil-immiscible formulation into the formation 205 via the first well 201 may be the pump 221 used to inject the low salinity aqueous fluid into the formation via the first well 201.
[0060] The oil-immiscible formulation can be introduced into formation 205, for example, by injecting the oil-immiscible formulation into the formation through the first well 201 by pumping the oil-immiscible formulation through the first well in the formation. The pressure at which the oil-immiscible formulation can be injected into formation 205 through first well 201 can be up to or exceed 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.
[0061] Amount of oil-immiscible formulation introduced into formation 205 via the first well 201 following the introduction of the oil recovery formulation into the formation through the first well may range from 0.001 to 5 pore volumes, or from 0.01 to 2 pore volumes, where the term “pore volume” refers to the volume of formation that can be swept away by the 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 gas phase, the volume of oil-immiscible formulation introduced into the formation 205 following the introduction of the low salinity aqueous fluid into the formation relative to the volume of low salinity aqueous fluid introduced into the formation immediately prior to the introduction of the oil-immiscible formulation may be at least 10 or at least 20, or at least 50 volumes of oil-immiscible formulation in gas phase per volume of low salinity aqueous fluid introduced into the formation immediately prior to introduction of the oil-immiscible formulation in the gas phase.
[0062] If the oil-immiscible formulation is in the liquid phase, the oil-immiscible formulation may have a viscosity of at least the same magnitude as the viscosity of the mobilized oil at the formation temperature conditions to enable the oil-immiscible formulation to drive the oil mobilized through formation 205 to second well 203. The oil-immiscible formulation may have a viscosity of at least 0.8 mPa.s (0.8 cP), or at least 10 mPa.s (10 cP), or at least 50 mPa.s (50 cP), or at least 100 mPa.s (100 cP), or at least 500 mPa.s (500 cP), or at least 1000 mPa.s (1000 cP) at the temperature conditions of training or the 25/. If the oil-immiscible formulation is in the liquid phase, the oil-immiscible formulation preferably can have a viscosity at least an order of magnitude greater than the viscosity of the oil mobilized through piston flow formation, minimizing and inhibiting the indication of the mobilized oil through the piston
[0063] The low salinity aqueous fluid and the oil immiscible formulation can be introduced into the formation through the first well 201 in alternating flow portions. For example, low salinity aqueous fluid may be introduced into formation 205 through first well 201 for a first period of time, at which time the oil-immiscible formulation may be introduced into formation through first well for a second period of 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 into the formation through the first well for a fourth period of time subsequent to the third period of time. As many flowing portions of the low salinity aqueous fluid and oil-immiscible formulation as desired can be introduced into the formation through the first well.
[0064] 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 non-oil miscible formulation in the formation through the first well 201. Mobilized oil is driven along the formation from the first well 201 for production from 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 the formation together with the mobilized oil. Water in addition to the low salinity aqueous fluid and/or gas can also be mobilized for production from formation 205 via second well 203 by introducing the low salinity aqueous fluid and, optionally, the non-oil miscible formulation into the formation by middle of the first well 201.
[0065] After the introduction of the low salinity aqueous fluid and, optionally, the non-oil miscible formulation into the formation 205 through the first well 201, the oil can be recovered and produced from the formation through the second well 203. A mechanism may be located in the second well for oil recovery and production from the formation 205 subsequent to the introduction of the low salinity aqueous fluid into the formation. The mechanism for oil recovery and production from the formation may further recover and produce at least a portion of the low salinity aqueous fluid, other water, and/or gas from the formation subsequent to the introduction of the low salinity aqueous fluid into the formation. . The mechanism located in the second well 203 for recovery and production of oil, low salinity aqueous fluid, other water, and/or gas may be comprised of a pump 233, which may be located in a second injection/production facility 231 and /or within the second well 203. The pump 233 can extract the oil, at least a portion of the low salinity aqueous fluid, other water, and/or gas from the formation 205 through perforations in the second well 203 to dispatch the oil, at least a portion of the low salinity aqueous fluid, other water, and/or gas, for the second injection/production facility 231.
[0066] Alternatively, the mechanism for recovery and production of oil, at least a portion of the low salinity aqueous fluid, other water, and/or gas from formation 205, can be comprised of a compressor 234 that can be located in the second injection/production plant 231. Compressor 234 can be fluidically and operatively coupled with a gas storage tank 241 by means of a pipe 236, and can compress the gas from the gas storage tank for injection into formation 205 by means of the 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 formation gas through the second well 203, with 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, from the position in the well in which oil, low salinity aqueous fluid, other water, and/or gas are produced from the formation, for example, compressed gas can be injected into forming portion 211 while oil, low salinity aqueous fluid, other water, and/or gas are produced from forming into forming portion 209.
[0067] The oil, at least a portion of the low salinity aqueous fluid, other water, and/or gas can be extracted from formation 205, as shown by arrows 229, and produced for the second well 203 for the second installation of injection/production 231. The oil may be separated from the gas and an aqueous mixture comprised of the produced portion of the low salinity aqueous fluid and other formation water produced from the formation, e.g., tap water, mobile water, or water of oil injection recovery. The oil produced can be separated from the aqueous mixture produced and the gas produced in a separation unit unit 235 located in the second injection/production facility 231 and, in one embodiment, operatively and fluidly coupled, by means of a tube 305 , with mechanism 233, for recovery and production of oil, aqueous mixture components, and/or formation gas.
[0068] A brine solution with a TDS content of more than 10,000 PPM, or 15,000 PPM up to 250,000 PPM can be provided, from a 247 brine solution storage facility to the 235 separation unit, by means of tube 273 for mixing with the produced oil and the produced aqueous mixture, and, optionally, with the produced gas. The brine solution can have a TDS content of at least 15,000PPM, or at least 20,000PPM, or at least 25,000PPM, or at least 30,000PPM, or at least 40,000PPM, or at least 50,000PPM, or more than 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 seawater, brackish water, or production water, produced from the formation and separated from the oil and/or gas produced from the formation. Alternatively, the brine solution may be comprised 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- 3) produced by contacting a saline source water with an ion filter as described above. An ion filter 113, as described above, may be fluidically and operatively connected to the brine solution storage facility 247, via tube 275, to provide retentate 117, 125, 127, 137, and/or 143 to at least a portion of the brine solution to the brine solution storage facility 247.
[0069] A demulsifier can also be provided for the separation plant 235 from the demulsifier storage facility 271, which can be fluidically and operatively connected with the separation unit by means of tube 240. The demulsifier can be provided for the 235 separation plant for mixing with the produced oil, the produced water, and the brine solution, and optionally with the produced gas, to facilitate the separation of the produced oil and the produced water.
[0070] The demulsifier can be selected from the group consisting of amyl resins; butyl resins; nonyl resins; acid or base catalyzed phenol-formaldehyde resins; phenol-acrylate anhydride polyglycol resins; urethanes; polyamines; polyesteramines; sulfonates; diepoxide polyols; polyol esters and esters including fatty acid triol esters, adipate triol esters, and triol fumarate esters; ethoxylated and/or propylated 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 oxylene, toluene, heavy aromatic naphtha, isopropanol, methanol, 2-ethoxyhexanol, diesel, and combinations thereof. A demulsifier suitable for separating oil and water produced from formation 205 can be selected by conducting a bottle test, a conventional test known to those skilled in the art for selecting a demulsifier effective to separate crude oil from water. Commercially available demulsifiers include National Chemical Supply's EB series, 4151 SW 47th Ave., Davie, FL, 33314, United States, and Tretolite demulsifiers from Baker Petrolite Corporation, 12645 W. Airport Blvd., Sugar Land, TX 77478, U.S.
[0071] The separation unit 235 can be comprised of a mechanism for contacting the brine solution and the demulsifier with the oil produced and the water produced, and a mechanism for separating the oil produced from the water produced after it has entered into contact with the brine solution and the demulsifier. The separation unit may further comprise a mechanism for separating gas from produced oil and produced water. Alternatively, the separation unit 235 can be comprised of a mechanism for contacting the brine solution and the demulsifier, with the oil produced with the produced water, and separating the produced oil from the produced water.
[0072] Referring now to Fig. 5, the separation unit 235 that can be used in the system of the present invention is shown. The separation unit 235 can be comprised of a 2-phase separator 301 and a water suppression container 303, the 2-phase separator being the mechanism for separating the gas from the produced oil and the produced water and the suppression container of water is the mechanism to bring the brine solution and the demulsifier into contact with the produced oil and the produced water and separate the produced oil from the produced water. The 2-phase separator can be a conventional 2-phase separator for separating a gas phase from a liquid phase, the 2-phase separator can be a vertical, horizontal, or spherical separator, and it can be a high-grade separator. pressure (5.2 MPa-34.4 MPa; 750-5,000 psi), a medium pressure separator (1.6 MPa-5.2 MPa; 230-750 psi), or a low pressure separator (0.07 MPa-1.6 MPa; 10-230 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 separation of phase, and the separated gas can be removed from the 2-phase separator by pipe 243. As shown in Fig. 4, the separated gas can be provided from the separator 235 to a gas storage facility 241 which can be fluidically and operationally connected with the separator by tube 243. Referring back to Fig. 5, the produced oil and the produced water can be separated from the gas in the 2-phase separator 301 by phase separation, and the separated produced oil and the water mixture produced can be provided from the 2-phase separator to the water suppression vessel 303, which can be fluidically and operatively connected with the 2-phase separator by the tube 307.
[0073] The produced oil and the produced water can be separated in the water suppression vessel 303 by density separation and demulsification, with the brine solution and the demulsifier. Water suppression vessel 303 may be a conventional water suppression vessel. As described above, the brine solution can be supplied from a brine solution storage facility 247 (Fig. 4) to the separation unit 235 by tube 273, and the brine solution can be provided to the container. of water suppression 303 of the separation unit. Furthermore, as described above, the demulsifier can be provided from a demulsifier storage facility 271 (Fig. 4) to the separation unit 235 by tube 240, the demulsifier can be provided to the demulsifier container. water 303 from the separation unit. If desired, or necessary, additional emulsion breaking steps may be conducted in water suppression vessel 303 after formation of the solution mixture of brine, oil, and water to further destabilize the emulsion and separate the oil from the water. For example, a mixture of brine, oil, and water solution can be heated to destabilize the emulsion, or the mixture can be electrostatically dehydrated.
[0074] The demulsifier and brine solution may be provided to the water suppression vessel 303 in sufficient amounts to facilitate a rapid demulsification of any oil-in-water or water-in-oil emulsions present in the suppression vessel of water to promote a quick and clean separation of oil and water in the water suppression vessel. The brine solution can be provided to the water suppression 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 the production well 203, or to at least 5,000 PPM, or at least 10,000 PPM, or at least 15,000 PPM, or at least 20,000 PPM, or at least 25,000 PPM, or at least 30,000 PPM, or more than 10,000 PPM to 100,000 PPM, or from 15,000 PPM to 50,000 PPM, or from 20,000PPM to 40,000 PPM, or from 50,000 PPM to 250,000 PPM. Alternatively, the brine solution can be added to the mixture of produced oil and produced water in the water suppression vessel 303 so that the brine solution is from 2% by volume to 40% by volume of the mixture of produced oil and water produced, or from 5% by volume to 33% by volume of the mixture of produced oil and produced water, or from 10% by volume to 25% by volume of the mixture of produced oil and produced water. The demulsifier can be added to the blend of produced oil, produced water, and brine solution so that the demulsifier is present in an amount of 2 PPM to 200 PPM, or 10 PPM to 100 PPM. Alternatively, a demulsifying solution can be added to the mixture of produced oil, produced water, and brine solution, so that the demulsifying solution is from 0.05% by volume to 5% by volume, or from 0.1% by volume up to 2% by volume of the mixture of produced oil, produced water, and brine solution, the demulsifying solution may contain from 0.1% by weight to 5% by weight, or from 0.5% by weight to 2. 5% by weight, or from 1% by weight to 2% by weight of the demulsifying compound(s).
[0075] The inclusion of the brine solution with a mixture of the produced oil, produced water, and demulsifier can significantly reduce the time required for an oil and water emulsion to separate into separate oil and water phases in relation to the time required for the 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 the produced oil, produced water, and demulsifier can reduce the time required 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 over the same mixture without the brine solution. Consequently, the volume of the water suppression container can be at least 2 times, or at least 3 times, or at least 4 times, or at least 5 times smaller when using the brine solution, relative to the volume of a container. of water suppression required to separate and demulsify the produced oil, the produced water, and a demulsifier without the brine solution.
[0076] The oil produced can be separated from the water suppression vessel 303, and, as shown in Fig. 4, provided from the separation unit 235 to an oil storage tank 237. water 303 (Fig. 5) of separation unit 235 can be fluidically and operatively connected with oil storage tank 237 by pipe 239 for provision of separate produced oil, from water suppression container 303 to storage tank of oil 237.
[0077] The produced water can be separated from the water suppression vessel by means of tube 309. The produced water can be provided to an ion filter, as described above, to produce the treated water and the brine solution. Treated water may be provided to the aqueous fluid storage facility 215 for reintroduction into the formation as described above. The brine solution may be provided to the brine solution storage facility 247, for use to further demulsify the produced oil and produced water.
[0078] As shown in Fig. 6, the separation unit 235 can be further comprised of a free water suppression vessel 311 in addition to the 2-stage separator 301 and the water suppression vessel 303. The water suppression vessel Free 311 can be a conventional free water suppression container. The gas 243 can be separated from the produced oil and the produced water in the 2-stage separator as described above, and the produced oil and the produced water can be provided to the free water suppression vessel 311. Oil 313 and water 315 that have already been phase separated can be separated and removed from the free water suppression vessel 311.0 Oil and water are present in an emulsion 317 can be passed from a free water suppression vessel 311 to the water suppression vessel 303. Brine solution 273 and demulsifier 240 can be mixed with the emulsion in water suppression vessel 303 for phase separation of oil and water in the emulsion. If desired or necessary, additional emulsion breaking steps may be conducted in water suppression vessel 303 after formation of the solution mixture of brine, demulsifier, oil, and water, to further destabilize the emulsion and separate the oil from the water. For example, the mixture of brine solution, 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 free water suppression vessel 311 and provided for storage in oil storage tank 237 via pipe 239 (Fig. 4). The water 318 separated from the emulsion in the water suppression vessel 303 can be combined with the water 315, separated from the water suppression vessel 311. The combined water 309 can be provided 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 provided from the ion filter to the aqueous fluid storage facility 215 for reintroduction into the formation as described above. The brine solution can be provided from the ion filter to the brine solution storage facility 247 for use to further demulsify the oil and water produced.
[0079] Alternatively, as shown in Fig. 7, the separation unit 235 can be comprised of a 3-phase separator 401, the 3-phase separator being a unique mechanism for separating the gas from the produced oil and the produced water , contacting the brine solution and the demulsifier with the produced oil and the produced water, and separating the produced oil from the produced water. The 3-phase separator 401 can be a conventional 3-phase separator to separate 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 separator of 3-phase separator 401. The separated gas can be removed from the 3-phase separator by pipe 243. As shown in Fig. 4, the separated gas can be provided from separator 235 to the gas storage facility 241, which is fluidic and operatively connected with the separator by tube 243. Referring back to Fig. 7, the brine solution 273 and the demulsifier 240 may be provided to the 3-phase separator to demulsify an oil-water emulsion present in the 3rd-separator. phases and produce a liquid oil phase and a liquid water phase. If desired or necessary, additional emulsion breaking steps can be conducted in the 3-phase separator after formation of the mixture of brine, demulsifier, oil, and water solution, to further destabilize the emulsion and separate oil from water. For example, the mixture of brine solution, 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 by means of tube 239, which can be fluidically and operatively connected with oil storage tank 237 (Fig. 4). The liquid water phase can be separated from the 3-phase separator by tube 309, which can be fluidically and operatively connected with an ion filter, as described above, for separation into 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 (Fig. 4) for reintroduction into the formation. The brine solution may be provided to the brine solution storage facility 247 for use to further demulsify produced oil and produced water.
[0080] Alternatively, as shown in Fig. 8, the separation unit 235 may be comprised of a 2-stage separator 301, a mixing tank 505, and a water suppression vessel 303; the 2-phase separator 301 being a mechanism for separating the gas from the oil produced and the water produced, the mixing tank 505 is a mechanism for contacting the brine solution and the demulsifier with the oil produced and the produced water, and the water suppression vessel 303 is a mechanism for separating the produced oil from the produced water. Produced oil, produced water, and gas can be supplied to the separation unit 235 from the second well by means of pipe 305; whereby produced oil, produced water, and gas can be supplied to the 2-stage separator 301. The 2-stage separator 301 can separate the gas from the 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 by means of pipe 507. Mixing tank 505 can be any conventional mechanism for mixing liquids, e.g. mixture stirred mechanically. The brine solution can be supplied to the mixing tank 505 from the brine solution storage facility 247 (Fig. 4) by pipe 273, and the demulsifier can be provided from the demulsifier storage facility 271 (Fig. 4) to the mixing tank by pipe 240. The brine solution, the demulsifier, the produced oil, and the produced water can be mixed in the mixing tank 505, and then provided from the mixing tank to the mixing vessel. water suppression 303 by means of pipe 509. The produced oil can be separated from the produced water in the water suppression vessel 303 as described above, and the separated produced oil 239 can be provided to the oil storage tank 237, and produced water 309 can be provided to an ion filter as described above.
[0081] Referring again to Fig. 4, in an embodiment of a system of the present invention, the first well 201 includes a mechanism for injecting the low salinity aqueous fluid and optionally the non-oil miscible formulation in the formation 205 and the second well 203 includes one or more mechanisms for producing and separating oil, water, and optionally gas, from the formation, as described above, for a first period of time, and the second well 203 includes a mechanism to inject the low salinity aqueous fluid and optionally the immiscible oil formulation into formation 205, to mobilize the oil in the formation and drive the mobilized oil along the formation to the first well, and the first well 201 includes one or more mechanisms for producing and separating oil, water, and gas from formation for a second time period, with the second time period subsequent to the first time period. The second injection/production facility 231 may comprise a mechanism, such as a pump 251, which is fluidically and operatively coupled with the aqueous fluid storage facility 215 by tube 253 and which is fluidically and operatively coupled with the second well 203 for introduce the low salinity aqueous fluid into formation 205 through the second well. The pump 251 or a compressor may further be fluidically and operatively coupled with the non-oil miscible formulation storage facility 225 by tube 255, to introduce the non-oil miscible formulation into the formation 205, via the second well 203 subsequent to the introduction of the low salinity aqueous fluid in the formation through the second well. The first injection/production facility 217 may comprise a mechanism, such as a pump 257 or a compressor 258, for producing oil, water, and gas from the formation 205 by means of the first well 201. production 217 may further include a separation unit 259 for separating produced oil, produced water, and produced gas fluidically and operatively connected with mechanism 257 by tube 260; the separation unit 259 may be similar to the separation unit 235 as described above. The brine solution storage facility 247 may be fluidically and operatively connected with the separation unit 259 by pipe 272 to provide the brine solution to the separation unit 259; and the demulsifier storage facility 271 may be fluidically and operatively connected with the separation unit 259 by tube 262 to provide the demulsifier to the separation unit 259. The separation unit 259 may be fluidically and operatively coupled with: the tank liquid storage 237 by pipe 261, for storing the oil produced and separated in the liquid storage tank; the gas storage tank 241 by the tube 265, for storing the gas produced in the gas storage tank; and an ion filter for producing a low salinity treated water and a brine solution from the separated produced water.
[0082] The first well 201 can be used to introduce the low salinity aqueous fluid and, optionally and subsequently, the non-oil miscible formulation in formation 205 and the second well 203 can be used for production and separation of oil, water, and formation gas for a first period of time; then the second well 203 can be used for introducing the low salinity aqueous fluid and, optionally and subsequently, the immiscible oil formulation in formation 205, and the first well 201 can be used for production and separation of oil, water, and gas from formation in a second period of time; the first and second time periods comprising a cycle. Multiple cycles may be conducted which may include alternating the first well 201 and the second well 203, between the introduction of the low salinity aqueous fluid and optionally and subsequently the non-oil miscible formulation in formation 205, and the production and separation of oil, water, and gas from formation; where one well is introducing and the other is producing and separating in the first period of time, and then they are exchanged in a second period of time. A cycle can be from about 12 hours to about 1 year, or from about 3 days to about 6 months, or from about 5 days to about 3 months. The low salinity aqueous fluid can be introduced into the formation at the beginning of a cycle and the non-oil miscible formulation can be introduced at the end of the cycle. In some embodiments, the start of a cycle may be from the first 10% to about 80% of the cycle, or from the first 20% to about 60% of a cycle, from the first 25% to about 40% of a cycle. cycle, and the end may be the remainder of the cycle.
[0083] Referring now to Fig. 9, in an alternative embodiment of the system 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 per described above, and produced together with oil and water. The demulsifier does not need to be added to either the 235 or 259 separation units when it is introduced into and produced from the production well. The system of this embodiment of the invention may be as described above, except that the system includes a mechanism for introducing a demulsifier into the production well. When oil and water are produced from the first well 201, the demulsifier can be provided from the demulsifier storage facility 271 through tube 279, to a pumping mechanism located in the first well 201, for injection into the first well . The demulsifier can be injected into the first well 201 by means of an injection line attached to the outside of the production tube or injection into the first well to be dispatched immediately downstream of the wellhead, or by pumping the demulsifier to the annulus between the casing and production piping of the first well to be dispatched 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, the demulsifier can be provided from the demulsifier storage facility 271 via tube 277 to a pumping mechanism located in the second well, 203 for injection into the second well . The demulsifier can be injected into the second well 203 through an injection line attached to the outside of the production and injection piping in the second well, to be dispatched immediately downstream of the wellhead or by pumping the demulsifier into the annulus between the casing and the production pipeline of the second well to be dispatched immediately downstream of the wellhead, or by injecting the demulsifier into the production manifold inside the second well.
[0084] The demulsifier can be a demulsifying solution as described above, containing from 0.1% by weight to 5% by weight, or from 0.5% by weight to 2.5% by weight, or from 1% by weight up 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 from 0.05% by volume to 5% by volume, or from 0.1% by volume to 2% by volume of the demulsifying solution in a solution mixture demulsifier, oil, and water that is produced from the production well.
[0085] The produced demulsifier can be provided with the mixture of produced oil and produced water to separation unit 235 or 259 to aid in the separation of produced oil from produced water. The 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 produced oil and produced water into separate phases using the system as described above. If desired, additional demulsifier may be added to the mixture of produced oil, produced water, produced demulsifier, and brine solution in separation unit 235 or 259, as described above, to aid in the separation of produced oil from produced water.
[0086] Referring now to Figure 10 a series of wells 600 is illustrated. The 600 series includes a first group of 602 wells (denoted by the horizontal lines) and a second group of 604 wells (denoted by the diagonal lines). In some embodiments of the system of the present invention, the first well of the above-described system may include multiple first wells depicted as the first group of wells 602 in the 600 series, and the second well of the above-described system may include multiple second wells depicted as the second group of 604 wells in the 600 series.
[0087] Each well in the first group of wells 602 can be the horizontal distance 630 from the adjacent well in the first group of wells 602. The horizontal distance 630 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 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 group of wells 602 can be a vertical distance 632 from an adjacent well in the first group of wells 602. The vertical distance 632 can be from about 5 to about 5,000 meters, or from about 7 to about of 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.
[0088] Each well in the second group of wells 604 can be the horizontal distance 636 from an adjacent well in the second group of wells 604. The horizontal distance 636 can be from about 5 to about 5,000 meters, or about 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 to about 200 meters, or from about 50 to about from 150 meters, or from about 90 to about 120 meters, or from about 100 meters.
[0089] Each well in the second group of wells 604 can be a vertical distance 638 from an adjacent well in the second group of wells 604. The vertical distance 638 can be from about 5 to about 5,000 meters, or about 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 from about 100 meters.
[0090] Each well in the first group of wells 602 may be distance 634 from adjacent wells in the second group of wells 604. Each well in the second group of wells 604 may be distance 634 from adjacent wells in the first group of wells wells 602. The distance 634 can be from about 5 to about 5,000 meters, or from 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 from about 100 meters.
[0091] Each well in the first group of wells 602 may be surrounded by four wells in the second group of wells 604. Each well in the second group of wells 604 may be surrounded by four wells in the first group of wells 602.
[0092] In some embodiments, the series of wells 600 may have from about 10 to about 1,000 wells, for example, from about 5 to about 500 wells in the first group of wells 602, and from about 5 up to about 500 wells in the second group of wells 604.
[0093] In some embodiments, the series of wells 600 can be seen as a top view, the first group of wells being 602 and the second group of wells 604 being vertical wells spaced apart in a piece of soil. In some embodiments, the series of wells 600 may be viewed as a cross-sectional side view of the formation, with the first group of wells 602 and the second group of wells 604 being spaced apart horizontal wells within the formation.
[0094] Referring now to Figure 11, a series of 700 wells is illustrated. The 700 series includes a first group of wells 702 (denoted by horizontal lines) and a second group of 704 wells (denoted by diagonal lines). The 700 series may be a series of wells, as described above, with respect to the 600 series in Figure 10. In some embodiments of the system of the present invention, the first well of the system described above may include multiple first wells depicted as the first group of wells 702 in the 700 series, and the second well of the system described above may include multiple second wells depicted as the second well group 704 in the 700 series.
[0095] The low salinity aqueous fluid and optionally and subsequently the non-oil miscible formulation can be injected into the first group of wells 702 and the oil, water, and gas can be produced and separated from the second group of wells 704 As illustrated, the low salinity aqueous fluid, and optionally the non-oil miscible formulation, can have an injection profile 706, and the oil, water, and gas can be produced from the second group of wells 704 that have a recovery profile 708.
[0096] The low salinity aqueous fluid and, optionally and subsequently the non-oil miscible formulation, can be injected into the second group of wells 704; and oil, water, and gas can be produced from the first group of wells 702. As illustrated, the low salinity aqueous fluid, and optionally the non-oil miscible formulation, can have an injection profile 708; and oil, water, and gas can be produced from the first group of wells 702, which has a recovery profile 706.
[0097] The first group of wells 702 can be used to inject the low salinity aqueous fluid and optionally and subsequently the non-oil miscible formulation, and the second group of wells 704 can be used to produce oil, water, and gas from formation in a first period of time; then the second group of wells 704 can be used to inject the low salinity aqueous fluid and, optionally and subsequently, the non-oil miscible formulation; and the first group of wells 702 can be used to produce oil, water, and gas from the formation in a second time period, the first and second time periods comprising a cycle. In some embodiments, multiple cycles may be conducted, which include alternating the first and second group of wells 702 and 704 between injecting the low salinity aqueous fluid and optionally and subsequently, the non-oil miscible formulation, and the production of oil, water, and gas from formation; where one group of wells is injecting and the other is producing in a first period of time, and then they are exchanged in a second period of time.
[0098] To facilitate a better understanding of the present invention, the following example of certain aspects of some embodiments is provided. In no way should this example be understood as limiting, or defining, the scope of the invention. Example
[0099] The effect of separating a brine solution on low salinity water was determined. 200 ml of a light crude oil from an oil-bearing formation was emulsified with 200 ml of water from the formation, the water having a total dissolved solids content of 6,042 PPM and an ionic strength of 0.11M. The resulting emulsion was separated into two 150ml portions. 75 ml of low salinity water with a TDS content of 6,042 PPM and an ionic strength of 0.1 IM was added to one of the emulsion portions and 75 ml of a brine solution with a TDS content of 77,479 PPM and a ionic strengths of 1.54 M were added to the other portion of the emulsion. The emulsion portion with the low salinity water was separated into two samples, and the emulsion portion with the brine solution was separated into two samples. 2 ml of a 1% solution of the DROP emulsifier in toluene was added to one of the emulsion samples with low salt water and to an emulsion sample with 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 water phase. The results are shown in Fig. 12. As shown in Fig. 12, the sample containing the brine solution and the demulsifier reached the final stage of separation approximately 5 times faster than the sample containing the low salinity forming water and the demulsifier, whereas the samples containing water from low salinity formation and the brine solution without the demulsifier failed to separate into two separate phases.
[00100] The present invention is well adapted to achieve the aforementioned purposes and advantages, as well as those that are inherent thereto. The embodiments presented above are illustrative only, as the present invention may be modified and practiced in different, but equivalent, ways that will be apparent to those skilled in the art to benefit from the teachings presented herein. Furthermore, no limitation is intended for the construction or design details shown herein, other than as described in the claims below. While 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 numeric range, with a lower limit and an upper limit, is displayed, any number and any range that falls within the range are specifically displayed. In particular, each range of values (in the form, "from a to b" or, equivalently, "from a-b") presented here is to be understood as showing each number and range included within the wider range of values. Where a numeric range that has only a specific lower limit, only a specific upper limit, or a specific upper limit and a specific lower limit, the range may also include any numeric value "around" the specified lower limit and/or the upper limit specified. Furthermore, the terms in the claims have their clear, common meaning, unless explicitly and clearly defined otherwise by the patent holder. Furthermore, the indefinite articles "a" or "an" as used in the claims are defined herein to mean one or more of the elements they introduce.

权利要求:
Claims (14)
[0001]
1. System for oil production and separation, comprising: an oil-bearing formation (205); a low salinity aqueous fluid having an ionic strength of less than 0.15M and a total dissolved solids content of 200ppm to 10,000ppm; a brine solution having a total dissolved solids content of more than 10,000 ppm; a demulsifier; a mechanism for introducing the low salinity aqueous fluid into the oil-bearing formation (205); a mechanism for producing oil and water from the oil-bearing formation (205) subsequent to the introduction of the low salinity aqueous fluid into the oil-bearing formation (205); and, a mechanism for contacting the brine solution and the demulsifier with the oil and water produced from the oil-bearing formation (205) and for separating the produced oil from the produced water, characterized by: a saline source water (111) having a total dissolved solids content of at least 10,000 ppm, an ion filter (113) for processing the saline source water (111) to produce a treated water (115) and a retentate (117), wherein the ion filter (113) is comprised of two or more ionic membranes selected from the group consisting of one or more nanofiltration membrane units, one or more reverse osmosis membrane units and combinations thereof, wherein at least two of the two or more ionic membranes are arranged in series, the treated water (115) used as at least a portion of the low salinity aqueous fluid, and the retentate (117) used as at least a portion of the brine solution is a product of the ion filter ( 113).
[0002]
2. System according to claim 1, characterized in that the mechanism for introducing the low salinity aqueous fluid into the oil-bearing formation (205) is comprised of a first well (201) and a pump (221).
[0003]
3. System according to any one of claims 1 or 2, characterized in that the mechanism for producing oil and water from the oil-bearing formation (205) is comprised of a second well (203) and a pump ( 233) or a compressor (234).
[0004]
4. System according to any one of claims 1 to 3, characterized in that the oil-bearing formation (205) comprises one or more minerals having a negative zeta potential.
[0005]
5. System according to any one of claims 1 to 4, characterized in that the oil-bearing formation (205) has an Amott-Harvey wettability index of -0.3 to 1.0 and an initial water saturation less than 0.3.
[0006]
6. System according to any one of claims 1 to 5, characterized in that the oil-bearing formation (205) comprises connate water.
[0007]
7. System according to any one of claims 1 to 6, characterized in that the connate water has an ionic strength greater than the ionic strength of the aqueous fluid of low salinity.
[0008]
8. System according to any one of claims 1 to 7, characterized in that the oil-bearing formation (205) comprises sandstone or carbonate selected from limestone, dolomite and combinations thereof.
[0009]
9. System according to any one of claims 1 to 8, characterized in that the mechanism for contacting the brine solution, the demulsifier, the produced oil and the produced water and for separating the produced oil from the produced water comprises a water suppression container (303).
[0010]
10. System for oil production and separation, comprising: an oil-bearing formation (205); a low salinity aqueous fluid having an ionic concentration of less than 0.15M and a total dissolved solids content of 200ppm to 10,000ppm; a brine solution having a total dissolved solids content of more than 10,000 ppm; a demulsifier; a mechanism for introducing the low salinity aqueous fluid into the oil-bearing formation (205); a mechanism for producing oil and water from the oil-bearing formation (205) subsequent to the introduction of the low salinity aqueous fluid into the oil-bearing formation (205); and, a mechanism for contacting the brine solution and the demulsifier with the oil and water produced from the oil-bearing formation (205); and a mechanism to separate the produced oil from the produced water after contacting the produced oil and the produced water with the brine solution and the demulsifier, characterized by: a saline source water (111) with a total dissolved solids content of 10,000 ppm, an ion filter (113) for processing the saline spring water (111) to produce a treated water (115) and a retentate (117), wherein the ion filter (113) comprises two or more ionic membranes selected from the group consisting of one or more nanofiltration membrane units, one or more reverse osmosis membrane units and combinations thereof, wherein at least two of the two or more ionic membranes are arranged in series, treated water (115) used as at least a portion of the low salinity aqueous fluid, and the retentate (117) used as at least a portion of the brine solution is a product of the ion filter (113).
[0011]
11. System according to claim 10, characterized in that the mechanism for contacting the brine solution and the demulsifier with the oil and water produced from the oil-bearing formation (205) comprises a mixing tank .
[0012]
12. System according to any one of claims 10 or 11, characterized in that the mechanism for separating the oil produced from the water produced after contacting the oil produced and the water produced with the brine solution and the demulsifier comprises a water suppression container (303).
[0013]
13. System for oil production and separation, comprising: an oil-bearing formation (205); a low salinity aqueous fluid having an ionic strength of less than 0.15M and a total dissolved solids content of 200ppm to 10,000ppm; a brine solution having a total dissolved solids content of more than 10,000 ppm; a demulsifier; a mechanism for introducing the low salinity aqueous fluid into the oil-bearing formation (205); a mechanism comprising a production well for producing oil and water from the oil-bearing formation (205) subsequent to the introduction of the low salinity aqueous fluid into the oil-bearing formation (205); a mechanism for introducing the demulsifier into the production well and for mixing the demulsifier with the produced oil and produced water in the produced well; a mechanism for contacting the brine solution with the mixture of produced oil, produced water and demulsifier; and a mechanism for separating the produced oil from the mixture of produced oil, produced water, brine solution and demulsifier, characterized by: a saline source water (111) having a total dissolved solids content of at least 10,000 ppm, an ion filter (113) for processing the saline source water (111) to produce a treated water (115) and a retentate (117), wherein the ion filter (113) comprises two or more ionic membranes selected from the group consisting of one or more. plus nanofiltration membrane units, one or more reverse osmosis membrane units and combinations thereof, wherein at least two of the two or more ionic membranes are arranged in series, the treated water (115) used as at least a portion of the low salinity aqueous fluid, and the retentate (117) used as at least a portion of the brine solution is a product of the ion filter (113).
[0014]
14. System according to claim 13, characterized in that it further comprises: an oil-immiscible formulation; a mechanism for introducing the oil-immiscible formulation into the oil-bearing formation (205) subsequent to the introduction of the low salinity aqueous fluid into the oil-bearing formation (205).

类似技术:

---

公开号 | 公开日 | 专利标题

---

BR112015002730B1|2021-05-04|systems for oil production and separation

---

US9540574B2|2017-01-10|Process for producing and separating oil

---

US9657216B2|2017-05-23|Process for reducing viscosity of polymer-containing fluid produced in the recovery of oil

---

US20150107840A1|2015-04-23|Process for recovery of oil from an oil-bearing formation

---

US8939211B2|2015-01-27|Hydrocarbon recovery process

---

US20140196902A1|2014-07-17|Method, system, and composition for producing oil

---

US20140182850A1|2014-07-03|Process for producing oil

---

WO2015108900A1|2015-07-23|Process and composition for producing oil

---

OA17253A|2016-04-20|System for producing and separating oil.

---

OA17198A|2016-04-05|Process for producing and separating oil.

---

WO2015138429A1|2015-09-17|Oil recovery formulation, process for producing an oil recovery formulation, and process for producing oil utilizing an oil recovery formulation

---

OA17805A|2018-01-09|Process for recovery of oil from an oilbearing formation.

同族专利:

---

公开号 | 公开日

---

DK2882932T3|2018-06-14|

---

RU2643241C2|2018-01-31|

---

EP2882932A1|2015-06-17|

---

NO2948523T3|2018-08-04|

---

BR112015002730A2|2017-07-04|

---

EP2882932A4|2016-11-02|

---

CN104541022B|2017-09-08|

---

RU2015108029A|2016-09-27|

---

CN104541022A|2015-04-22|

---

WO2014025863A1|2014-02-13|

---

EP2882932B1|2018-03-07|

---

US20140041856A1|2014-02-13|

---

MY171783A|2019-10-29|

引用文献:

---

公开号 | 申请日 | 公开日 | 申请人 | 专利标题

---

---

US4029570A|1976-03-29|1977-06-14|Cities Service Company|Process for recovering crude oil from an underground reservoir|

---

RU2060354C1|1993-05-06|1996-05-20|Северный научно-исследовательский и проектный институт газа|System of closed circulating water supply in operation of oil and gas well|

---

US6491824B1|1996-12-05|2002-12-10|Bj Services Company|Method for processing returns from oil and gas wells that have been treated with introduced fluids|

---

US20020189807A1|2001-06-19|2002-12-19|Chevron U.S.A. Inc. A Corporation Of Pennsylvania|Method and system for oil and water separation utilizing a hydrostatic pressure head for disposal of water|

---

GB2396169B|2002-12-12|2005-03-16|Schlumberger Holdings|Downhole separation of oil and water|

---

CA2547503C|2003-11-26|2012-03-13|Aquatech International Corporation|Method for production of high pressure steam from produced water|

---

RU2378032C2|2004-07-27|2010-01-10|Шелл Интернэшнл Рисерч Маатсхаппий Б.В.|Plant to separate mix of oil, water and gas|

---

WO2007138327A1|2006-06-01|2007-12-06|Natco Uk Limited|Method of providing a supply of water of controlled salinity and water treatment system|

---

JO2982B1|2006-10-13|2016-03-15|Exxonmobil Upstream Res Co|Optimized well spacing for in situ shale oil development|

---

TW201013961A|2008-07-16|2010-04-01|Applied Materials Inc|Hybrid heterojunction solar cell fabrication using a metal layer mask|

---

US9010440B2|2009-02-11|2015-04-21|Weatherford/Lamb, Inc.|Method and apparatus for centrifugal separation|

---

CN102325959B|2009-02-23|2014-10-29|埃克森美孚上游研究公司|Water treatment following shale oil production by in situ heating|

---

US20120055668A1|2009-05-11|2012-03-08|Wu Yong K|Solvents and compositions for treating hydrocarbon-bearing formations|

---

EP2613863A1|2010-09-10|2013-07-17|Shell Internationale Research Maatschappij B.V.|Improvements relating to hydrocarbons recovery|

---

US20120090833A1|2010-10-15|2012-04-19|Shell Oil Company|Water injection systems and methods|

---

WO2012082617A2|2010-12-14|2012-06-21|Aquatech International Corporation|Method for recycling deoiled water using counterflow falling-film evaporators|AU2014306078B2|2013-08-05|2018-10-18|Gradiant Corporation|Water treatment systems and associated methods|

---

CN105683095B|2013-09-23|2019-09-17|格雷迪安特公司|Desalination system and correlation technique|

---

US10174597B2|2014-12-23|2019-01-08|Shell Oil Company|Subsurface injection of reject stream|

---

US10167218B2|2015-02-11|2019-01-01|Gradiant Corporation|Production of ultra-high-density brines|

---

US10308526B2|2015-02-11|2019-06-04|Gradiant Corporation|Methods and systems for producing treated brines for desalination|

---

US10711177B2|2015-03-20|2020-07-14|Chevron U.S.A. Inc.|Engineering formation wettability characteristics|

---

WO2016153934A1|2015-03-20|2016-09-29|Chevron U.S.A. Inc.|Engineering formation wettability characteristics|

---

US10865341B2|2015-03-20|2020-12-15|Chevron U.S.A. Inc.|Engineering formation wettability characteristics|

---

AU2016298326A1|2015-07-29|2018-03-08|Gradiant Corporation|Osmotic desalination methods and associated systems|

---

WO2017030937A1|2015-08-14|2017-02-23|Gradiant Corporation|Production of multivalent ion-rich process streams using multi-stage osmotic separation|

---

US10301198B2|2015-08-14|2019-05-28|Gradiant Corporation|Selective retention of multivalent ions|

---

BR102015033000B1|2015-12-30|2019-05-07|General Electric Company|SUBMARINE GAS / LIQUID-SEPARATION SYSTEM AND METHOD|

---

WO2017147113A1|2016-02-22|2017-08-31|Gradiant Corporation|Hybrid desalination systems and associated methods|

---

BR102016016758A2|2016-07-20|2018-05-29|Petróleo Brasileiro S.A. - Petrobras|HYBRID PROCESSED WATER AND SEA WATER TREATMENT SYSTEM AND PROCESS FOR REJECTION IN SUBMARINE OIL RESERVOIR|

---

US20220008920A1|2020-07-09|2022-01-13|Saudi Arabian Oil Company|In-situ salinity and ionic concentration control for calcite coated microfluidic cell|

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

---

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

---

2021-02-17| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|

---

2021-05-04| 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:

---

申请号 | 申请日 | 专利标题

---

US201261681236P| true| 2012-08-09|2012-08-09|

---

US61/681,236|2012-08-09|

---

PCT/US2013/053917|WO2014025863A1|2012-08-09|2013-08-07|System for producing and separating oil|

---