WO2014194031A1

WO2014194031A1 - Process for enhancing oil recovery from an oil-bearing formation

Info

Publication number: WO2014194031A1
Application number: PCT/US2014/039923
Authority: WO
Inventors: Diederik Willem VAN BATENBURG; Diederik Michiel BOERSMA; Koenraad ELEWAUT
Original assignee: Shell Oil Company; Shell Internationale Research Maatschappij B.V.
Priority date: 2013-05-31
Filing date: 2014-05-29
Publication date: 2014-12-04
Also published as: EP3004533A1; EA201592230A1; CN105247165A; US20140352958A1; CA2910988A1

Abstract

A process for recovering oil from an oil-bearing formation is provided. A first oil recovery fluid is introduced into a formation through a first well for a first time period and oil is produced from a second well. A second oil recovery fluid different from the first oil recovery fluid is introduced into the formation through the second well for a second time period after the first time period, and oil is produced from a third well, where the second well is located on a fluid flow path extending between the first and third well.

Description

PROCESS FOR ENHANCING OIL RECOVERY FROM AN OIL-BEARING

FORMATION

Field of the Invention

The present invention is directed to process for enhancing oil recovery from bearing formation.

Background of the Invention

In the recovery of oil from a subterranean oil-bearing formation, it is possible to recover only a portion of the oil in the formation using primary recovery methods that utilize the natural formation pressure to produce the oil. A portion of the oil that cannot be produced from the formation using primary recovery methods may be produced by improved or enhanced oil recovery (EOR) methods.

In a secondary oil recovery process, water or brine is injected into an injection well extending into the oil-bearing formation after primary recovery is complete. The water or brine mobilizes oil in the formation, pushing the mobilized oil from the injection well to a production well located at a distance from the injection well. The mobilized oil, along with formation water, and the water injected into the formation may be produced at the production well.

Secondary oil recovery, while effective to produce some of the oil left in the formation after primary recovery is complete, often leaves a significant portion of residual oil in the formation. Oil may be trapped in pores in the rock of the formation or oil may adhere to rock surfaces in the formation rather than being pushed through the formation by the injected water. The residual oil may be left trapped in the formation after the injected water has passed through the formation— potentially significantly reducing the quantity of oil produced from the formation if only primary and secondary recovery processes are utilized to recover oil from the formation.

A portion of the residual oil in place in the formation after a secondary oil recovery waterflood may be produced by injecting an oil recovery formulation into the formation that is different from the water or brine injected into the formation in the secondary oil recovery waterflood— which is known as tertiary oil recovery. The tertiary oil recovery formulation may mobilize the oil, for example, by liberating oil trapped in the pores of the rock of the formation, or by changing the adherence of the oil to rock surfaces in the formation, or by lowering interfacial tension between the residual oil and water in the formation, or by changing the physical characteristics, for example viscosity, of the residual oil. Examples of such tertiary oil recovery formulations include low ionic strength water, water soluble polymer formulations, alkaline-surfactant-polymer formulations, oil miscible solvents such as dimethyl ether, and oil miscible gases such as carbon dioxide and low molecular weight hydrocarbons.

Secondary and tertiary oil recovery may be conducted using conventional injector- producer well configurations. Some conventional injector-producer well configurations utilized for secondary and tertiary oil recovery are selected so that the injected water or oil recovery formulation pushes oil in the formation across the formation from the injection well to the producer well. Large arrays of such injector-producer wells may be utilized to produce oil from a single formation. For example, from 10 to 1000 injector-producer well pairs arranged in a direct fluid path from the injection well to the producer well may be utilized to produce oil from a single formation.

Application of tertiary oil recovery processes, however, may be limited when using certain conventional injector-producer well configurations. In certain conventional injector-producer well configurations, for example in offshore applications, the injection wells and the production wells are placed apart at large distances, for example 1 km or more due to the large capital expense outlays required for well drilling. The oil is mobilized and driven across the formation in a pattern or line drive geometry in a secondary oil recovery process. The distance between the injection wells and the production wells may render tertiary oil recovery technically and commercially impractical due to the long waiting time required for oil mobilized by the tertiary oil recovery formulation to arrive in the production well after a long waiting time for oil mobilized by secondary oil recovery to arrive in the production well. Furthermore, some of these injector-producer well configurations have been developed with peripheral water injectors that inject water below the oil/water contact in the formation, where the injected water may inhibit or prevent contact of the tertiary oil recovery formulation with the oil, causing the loss of the tertiary oil recovery formulation.

What is needed is a tertiary enhanced oil recovery process for recovering residual oil in an oil-bearing formation where injection wells and production wells are placed apart at a substantial distance. Summary of the invention

The present invention is directed to a process for recovering oil from an oil-bearing formation, comprising:

for a first time period, injecting a first oil recovery fluid into the oil-bearing formation through a first well extending into the formation and producing oil from the formation through a second well extending into the formation;

for a second time period, injecting the first oil recovery fluid into the formation through the first well, injecting a second oil recovery formulation into the formation through the second well, and producing oil from the formation through a third well extending into the formation, where the second well is located on a fluid flow path within the formation between the first well and the third well, where the second oil recovery fluid is different than the first oil recovery fluid, and wherein the second time period is after the first time period, and the second time period commences, at the earliest, upon initial production of a mixture comprising oil and the first oil recovery fluid from the formation through the second well.

Additional advantages and other features of the present disclosure will be set forth in part in the description which follows and in part will become apparent to those having ordinary skill in the art upon examination of the following or may be learned from the practice of the disclosure. The advantages of the disclosure may be realized and obtained as particularly pointed out in the appended claims.

As will be realized, the present disclosure is capable of other and different embodiments, and its several details are capable of modifications in various obvious respects, all without departing from the disclosure. Accordingly, the drawings and description are to be regarded as illustrative in nature, and not as restrictive.

Brief Description of the Drawings

The drawing figures depict one or more implementations in accordance with the present teachings, by way of example only, not by way of limitation. In the figures, like reference numerals refer to the same or similar elements.

Fig. 1 is an illustration of a step of a process of the present invention in a first time period of the process in a petroleum production system with vertically disposed wells. Fig. 2 is an illustration of a step of a process of the present invention in a first time period of the process in a petroleum production system with wells having horizontally disposed sections.

Fig. 3. is a diagram of a well pattern for production of petroleum in accordance with a process of the present invention.

Fig. 4 is an illustration of a step of a process of the present invention in a second time period of the process in a petroleum production system with vertically disposed wells. Fig. 5 is an illustration of a step of a process of the present invention in a second time period of the process in a petroleum production system with wells having horizontally disposed sections.

Fig. 6 is an illustration of a step of a process of the present invention in a second time period of the process in a petroleum production system with vertically disposed wells. Fig. 7 is an illustration of a step of a process of the present invention in a second time period of the process in a petroleum production system with wells having horizontally disposed sections.

Fig. 8 is an illustration of a step of a process of the present invention in a second time period of the process in a petroleum production system with vertically disposed wells wherein oil is produced from a first well and a third well.

Fig. 9 is an illustration of a step of a process of the present invention in a second time period of the process in a petroleum production system with vertically disposed wells. Fig. 10 is an illustration of a step of a process of the present invention in a second time period of the process in a petroleum production system with wells having horizontally disposed sections.

Detailed Description of the Invention

The present invention is directed to an enhanced oil recovery process in which an enhanced oil recovery formulation— the second oil recovery fluid— is injected into an oil- bearing formation through a second well located between a first well and a third well during a second time period after an improved oil recovery formulation— the first oil recovery fluid— is initially injected into the formation through the first well during a first time period. The second oil recovery fluid is different than the first oil recovery fluid. Oil is produced from the second well during at least a portion of the first time period, and oil is produced from the third well during a least a portion of the second time period, and, optionally, during at least a portion of the first time period. The second time period commences, at the earliest, upon initial production of a mixture comprising oil and the first oil recovery fluid from the formation through the second well. When the first well and the third well are located at a substantial distance from each other, injection of the second oil recovery fluid through the second well after the first time period enables the second oil recovery fluid to mobilize residual oil for recovery that was not mobilized by the first oil recovery fluid. The time period for production from the third well of the oil mobilized by injection of the second oil recovery fluid through the second well is reduced substantially relative to the time period for production of such oil from the third well that would be required if the second oil recovery fluid were injected only through the first well, for example, the time period for production may be reduced by years to decades. When peripheral water injectors are utilized to enhance production of oil by injecting water below an oil/water contact in the formation, injection of the second oil recovery fluid into a formation through the second well rather than the first initial injection well reduces the risk of losing the second oil recovery fluid without mobilizing residual oil for recovery.

Referring now to Fig. 1, a first well 101, a second well 103, and a third well 105 are shown extending from surfaces 107 through an overburden 109 into an oil-bearing formation 111. The surfaces 107 may be a platforms located on the sea 113 if the oil- bearing formation 111 is located offshore, or may be the earth's surface (not shown) if the oil-bearing formation 111 is located onshore.

The first well 101 may be a conventional well for injecting a fluid into an oil- bearing formation; the second well 103 may be a conventional well for injecting a fluid into an oil-bearing formation and for producing fluids including oil from the formation, and the third well 105 may be a conventional well for producing a fluids including oil from an oil-bearing formation. In some embodiments of the process of the present invention the first well 101 may be a conventional well for producing fluids including oil from the formation as well as a conventional well for injecting fluids into an oil-bearing formation. The second well 103 is located on a fluid flow path within the formation between the first well 101 and the third well 105. In an embodiment of the process of the present invention, the process may be conducted offshore, and the second well 103 may be a sidetrack well moved into position between the first well 101 and the third well 105, where the second, sidetrack, well 103 is positioned within the formation 111 on a fluid flow path between the first and third wells. As shown in Fig. 1, the first well 101, the second well 103, and the third well 105 may be primarily vertically or transversely oriented wells within the formation relative to the surface of the sea 113 or the earth's surface, where each of the vertically or transversely oriented wells 101, 103, and 105 are located a horizontal distance from each other within the formation 111. In another embodiment, as shown in Fig. 2, a portion 201 of the injection well 101, a portion 203 of the intermediate well 103, and a portion 205 of the production well 105 are substantially horizontally oriented within the formation relative to the surface of the sea (not shown) or the earth's surface 114, where each of the substantially horizontally oriented portions 201, 203, and 205 of the wells 101, 103, and 105 are located a vertical distance from each other within the formation 111.

Referring now to Figure 3 an array of wells 300 is illustrated. Array 300 includes a first well group 301 (denoted by vertical lines), a second well group 303 (denoted by horizontal lines), and a third well group 305 (denoted by diagonal lines). The first well described above may include multiple first wells depicted as the first well group 301 in the array 300, the second well described above may include multiple second wells depicted as the second well group 303 in the array 300, and the third well described above may include multiple third wells depicted as the third well group 305 in the array 300.

In some embodiments, the array of wells 300 may be seen as a top view with the first well group 301, the second well group 305, and the third well group 307 being vertically disposed wells spaced on a piece of land. In some embodiments, the array of wells 300 may be seen as a cross-sectional side view of the formation showing horizontally disposed portions of the first wells of the first well group 301, the second wells of the second well group 30, and the third wells of the third well group 305, respectively, spaced within the formation.

Each first well in the first well group 301 may be a distance 311 from an adjacent first well in the first well group where the distance 311 may be from about 100 to about 10000 meters, or from about 250 to about 5000 meters, or from about 500 to about 1000 meters. Each first well in the first well group 301 may be a distance 313 from an adjacent first well in the first well group. The distance 313 may be from about 5 to about 10000 meters, or from about 10 to about 2500 meters, or from about 15 to about 1000 meters.

Each second well in the second well group 303 may be a distance 315 from an adjacent second well in the second well group. The distance 315 may be from about 100 to about 10000 meters, or from about 250 to about 5000 meters, or from about 500 to about 1000 meters. Each second well in the second well group 303 may be a distance 317 from an adjacent second well in the second well group. The distance 317 may be from about 5 to about 10000 meters, or from about 10 to about 2500 meters, or from about 15 to about 1000 meters.

Each third well in the third well group 305 may be a distance 319 from an adjacent third well in the third well group. The distance 319 may be from about 100 to about 10000 meters, or from about 250 to about 5000 meters, or from about 500 to about 1000 meters. Each third well in the third well group 305 may be a distance 321 from an adjacent production well in the third well group. The distance 321 may be from about 5 to about 10000 meters, or from about 10 to about 2500 meters, or from about 15 to about 1000 meters.

Each first well in the first well group 301 may be a distance 323 from an adjacent second well in the second well group 303. Each second well in the second well group 303 may be a distance 323 from an adjacent first well in the first well group 301. The distance 323 may be from about 3 to about 5000 meters, or from about 5 to about 2500 meters, or from about 10 to about 1000 meters, where the distance 323 may be less than the distance 311 and/or distance 313.

Each second well in the second well group 303 may be a distance 325 from an adjacent third well in the third well group 305. Each third well in the third well group 305 may be a distance 325 from an adjacent second well in the second well group 303. The distance 325 may be from about 3 to about 5000 meters, or from about 5 to about 2500 meters, or from about 10 to about 1000 meters.

Each first well in the first well group 301 may be a distance 327 from the nearest third well in the third well group 305. Each third well in the third well group 305 may be a distance 327 from the nearest first well in the first well group 301. The distance 327 may be from about 4 to about 7500 meters, or from about 5 to about 5000 meters, or from about 10 to about 2500 meters, where the distance 327 is greater than the distance 323.

In some embodiments, the array of wells 300 may have from 15 to 1500 wells, for example from 5 to 500 first wells in the first well group 301, from 5 to 500 second wells in the second well group 303, and from 5 to 500 third wells in the third well group 305.

The oil-bearing formation may be comprised of a porous matrix material, oil, and water. The oil-bearing formation comprises oil that may be separated and produced from the formation after introduction of the first oil recovery fluid, and after introduction of the second oil recovery fluid into the formation following introduction of the first oil recovery fluid into the formation. The formation preferably contains a substantial amount of oil-in- place, a significant portion of which may be recovered from the formation by mobilization using the first oil recovery fluid and the second oil recovery fluid and subsequent production of the mobilized oil.

The oil-bearing formation may also be comprised of water, which may be located in pores within the porous matrix material. The water in the formation may be connate water.

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 porous rock matrix. The rock and/or mineral porous matrix material of the formation may be comprised of sandstone, shale, and/or a carbonate selected from dolomite, limestone, and mixtures thereof— where the limestone may be microcrystalline or crystalline limestone. The formation may have a permeability of from 0.0001 to 15 Darcies, or from 0.001 to 1 Darcy.

Oil in the oil-bearing formation may be located in pores within the porous matrix material of the formation. The oil in the oil-bearing formation may be immobilized in the pores within the porous matrix material of the formation, for example, by capillary forces, by interaction of the oil with the pore surfaces, by the viscosity of the oil, or by interfacial tension between the oil and water in the formation.

The oil-bearing formation should be a formation susceptible to production of oil by injection of the first oil recovery fluid and the second oil recovery fluid into the formation and subsequent production and recovery of oil from the formation. Determination of the suitability of a formation for oil recovery may be made by conducting conventional core flow studies on core plugs extracted from the formation utilizing the first and second oil recovery fluids in sequence as injectants, where the core plugs are saturated with oil from the formation and with connate water or water having a salinity matched to the formation connate water salinity at a comparable initial water saturation prior to injecting the first and second oil recovery fluids.

Referring again to Fig. 1, in the process of the present invention a first oil recovery fluid is introduced into the oil-bearing formation 111 for a first time period, for example by injecting the first oil recovery fluid into the formation through the first well 101 by pumping the first oil recovery fluid through the first well and into the formation. The first time period and injection of the first oil recovery fluid into the formation 111 may commence after primary recovery of oil from the formation is complete, e.g. , after little or no further oil may be recovered from the formation due to the natural pressure of the formation.

The pressure at which the first oil recovery fluid is introduced into the formation

111 through the first well 101 may range from the instantaneous pressure in the formation up to the fracture pressure of the formation or exceeding the fracture pressure of the formation. The pressure at which the first oil recovery fluid may be injected into the formation may range from 20% to 95%, or from 40% to 90%, of the fracture pressure of the formation. Alternatively, the first oil recovery fluid may be injected into the formation at a pressure of at least the fracture pressure of the formation, where the first oil recovery fluid may be injected under formation fracturing conditions.

The volume of the first oil recovery fluid introduced into the formation 111 via the first well 101 may range from 0.5 to 20 pore volumes between the first well 101 and the third well 105, or from 1 to 10 pore volumes between the first well and the third well, or from 2 to 5 pore volumes between the first well and the third well, where the term "pore volume between the first well and the third well" refers to the volume of the formation that may be swept by the first oil recovery fluid between the first well 101 and the third well 105. The pore volume between the first well and the third well may be readily be determined by methods known to a person skilled in the art, for example by modelling studies or by injecting water having a tracer contained therein through the formation 111 from the first well 101 to the third well 105.

The first oil recovery fluid may be water or brine. The first oil recovery fluid may be water or brine such as used in water flooding in conventional secondary oil recovery processes, where injection of the first oil recovery fluid may be a water flood for improved oil recovery from the formation. The water or brine used as the first oil recovery fluid may be provided from seawater, brackish water, an aquifer, a lake, a river, or water produced from the formation. The water or brine used as the first oil recovery fluid may contain, or may be conditioned to contain, less than 100 mg/1 sulfate anion (SO₄ ² ) to inhibit souring of the formation by sulfate-consuming bacteria. The first oil recovery fluid water or brine may be conditioned to contain less than 100 mg/1 sulfate by conventional methods for removing sulfate anions from water, for example, by nanofilitration, by reverse osmosis, by forward osmosis, or by ion exchange. The water or brine used as the first oil recovery fluid may contain, or may be conditioned to contain, a total dissolved solids (TDS) content of at least 200 parts per million (ppm) to avoid destabilization of the formation induced by swelling of clays within the formation. Fresh water having a TDS content of less than 200 ppm may be conditioned to contain a TDS of at least 200 ppm by adding sodium chloride or calcium chloride to the water. Brine used as the first oil recovery fluid preferably contains, or may be conditioned to contain, a TDS content of less than 50,000 ppm. Brine having a TDS content of more than 50,000 ppm may be conditioned to contain a TDS content of less than 50,000 ppm by conventional desalination methods, for example, thermal desalination, nanofiltration, reverse osmosis, forward osmosis, and ion exchange.

As the first oil recovery fluid is introduced into the formation 111 during the first time period, the first oil recovery fluid spreads into the formation as shown by arrow 115. Upon introduction to the formation 111 and during the first time period, the first oil recovery fluid contacts oil within the formation, mobilizes at least a portion of the contacted oil, and pushes at least a portion of the mobilized oil 117 across the formation to the second well 103. At least a portion of the mobilized oil 117 is then produced from the formation through the second well 103. A portion 119 of the mobilized oil may be pushed across the formation to the third well by introduction of the first oil recovery fluid into the formation, and the mobilized portion of oil 119 may be produced through the third well 105 during the first time period.

Referring to Fig. 2, when the wells are horizontally disposed in the formation, the first oil recovery fluid may be introduced into the formation through the horizontally disposed portion 201 of the first well 101, and the first oil recovery fluid may spread into the formation 111 as shown by arrows 215. The first oil recovery fluid contacts oil within the formation, mobilizes at least a portion of the contacted oil, and pushes at least a portion of the mobilized oil 217 downward to the horizontally disposed portion 203 of the second well 103. At least a portion of the mobilized oil 217 is then produced from the formation through the second well 103. A portion 219 of the mobilized oil also may be pushed downward to the horizontally disposed portion 205 of the third well 105 by introduction of the first oil recovery fluid into the formation. The mobilized portion of the oil 219 may be produced through the horizontally disposed portion 205 of the third well 105 during the first time period.

Referring now to Figs. 1 and 2, the first time period extends until, at the earliest, a portion of the first oil recovery fluid is produced through the second well 103 along with oil from the formation. The first recovery fluid may be produced through the second well 103 in a mixture comprised of oil, formation water, and first oil recovery fluid. The first time period may extend until, at the earliest, the mixture comprising oil, formation water, and the first oil recovery fluid produced through the second well 103 has a weight ratio of first oil recovery fluid plus formation water to oil of at least 1 : 1 , or at least 2:1.

Referring now to Figs. 4 and 5, after the first time period, a second oil recovery fluid is injected into the formation 111 through the second well 103 and oil is produced from the formation through the third well 105 for a second time period. The first oil recovery fluid may injected into the first well 101 for at least a portion, or all, of the second time period.

The second time period commences after the first time period. The second time period may commence immediately upon completion of the first time period, or may commence some time after the completion of the first time period. The second time period commences, at the earliest, upon initial production of a mixture comprising oil and the first oil recovery fluid through the second well 103. The second time period may commence, at the earliest, upon production of a mixture comprising oil, formation water, and the first oil recovery formulation where the mixture has a weight ratio of the first oil recovery fluid plus the formation water to oil of at least 1: 1, or at least 2:1. The second time period may end upon cessation of injection of the second oil recovery fluid into the formation 111 through the second well 103.

The second oil recovery fluid may be a fluid effective to mobilize residual oil left in the formation after introduction of the first oil recovery fluid into the formation and contact of oil with the first oil recovery fluid in the formation. The second oil recovery fluid may be effective to enable mobilization and production of a significant amount of residual oil in addition to oil mobilized and produced by introducing the first oil recovery fluid into the formation. After passage of the first oil recovery fluid through the formation, the second oil recovery fluid may mobilize the residual oil by liberating residual oil trapped in the pores of the rock of the formation , or by changing the adherence of the residual oil to rock surfaces in the formation, or by lowering interfacial tension between the residual oil and water in the formation, or by changing the physical characteristics of the residual oil, for example viscosity. The second oil recovery fluid is different from the first oil recovery fluid, and may be selected from the group consisting of a low salinity aqueous fluid having an ionic strength of at most 0.15M and a TDS content of from 200 ppm to 10000 ppm, an aqueous solution of a surfactant or combination of surfactants, an alkaline-surfactant- polymer formulation, an aqueous solution of water soluble polymer, dimethyl ether, and mixtures thereof.

The second oil recovery fluid may be a low salinity aqueous fluid having an ionic strength of at most 0.15M and a TDS content of from 200 ppm to 10000 ppm. The low salinity aqueous fluid may have a TDS content of from 500 ppm to 7000 ppm, or from 1000 ppm to 5000 ppm, or from 1500 ppm to 4500 ppm. The low salinity aqueous fluid may have an ionic strength of at most 0.1M or at most 0.05M, or at most 0.01M, and may have an ionic strength of from 0.01M to 0.15M, or from 0.02M to 0.125M, or from 0.03M to O.lM. Ionic strength, as used herein, is defined by the equation

where / is the ionic strength, c is the molar concentration of ion i, z is the valency of ion i, and n is the number of ions in the measured solution.

The low salinity aqueous fluid may have an ionic strength that is less than the ionic strength of connate water present in the oil-bearing formation, and/or a multivalent cation concentration that is less than the multivalent cation concentration of connate water present in the oil-bearing formation, and/or a divalent cation concentration that is less than the divalent cation concentration of connate water present in the oil-bearing formation. The fraction of the ionic strength of the low salinity aqueous fluid to the ionic strength of the connate water may be less than 1, or may be less than 0.9, or may be less than 0.5, or may be less than 0.1, or may be from 0.01 up to, but not including, 1, or from 0.05 to 0.9, or from 0.1 to 0.8. The fraction of the multivalent cation content of the low salinity aqueous fluid to the multivalent cation content of the connate water may be less than 1 , or may be less than 0.9, or may be less than 0.5, or may be less than 0.1, or may be from 0.01 up to, but not including, 1, or from 0.05 to 0.9, or from 0.1 to 0.8. The fraction of the divalent ion content of the low salinity aqueous fluid to the divalent ion content of the connate water may be less than 1, or less than 0.9, or less than 0.5, or less than 0.1, or from 0.01 up to, but not including, 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. The low salinity aqueous fluid may have a multivalent cation concentration of at most 200 ppm, or at most 100 ppm, or at most 75 ppm, or at most 50 ppm, or at most 25 ppm, or from 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. The low salinity aqueous fluid may have a divalent cation concentration of at most 150 ppm, or at most 100 ppm, or at most 75 ppm, or at most 50 ppm, or at most 25 ppm, or from 1 ppm 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.

The low salinity aqueous fluid may be provided from a natural source or may be provided by processing source water having a TDS content of greater than 10000 ppm, or, if desired to use a low salinity aqueous fluid having a TDS content of 5,000 ppm or less by processing a source water having a TDS content of greater than 5,000 ppm, to produce the aqueous fluid. The aqueous fluid may be provided from a natural source such as an aquifer, a lake, or a river comprising water containing from 200 ppm to 10000 ppm total dissolved solids.

The low salinity aqueous fluid, or at least a portion thereof, may be provided by processing a saline source water having a TDS content of greater than 10000 ppm to produce the aqueous fluid, and the system may further comprise a saline source water having a TDS content of greater than 10000 ppm and a mechanism for processing a saline source water having a TDS content of greater than 10000 ppm to produce the low salinity aqueous fluid. The saline source water may have a TDS content of at least 10000 ppm, or at least 15000 ppm or at least 17500 ppm, or at least 20000 ppm, or at least 25000 ppm, or at least 30000 ppm, or at least 40000 ppm, or at least 50000 ppm, or from 10000 ppm to 250000 ppm, or from 15000 ppm to 200000 ppm, or from 17500 ppm to 150000 ppm, or from 20000 ppm to 100000 ppm, or from 25000 ppm to 50000 ppm. The saline source water to be processed may be selected from the group consisting of aquifer water, seawater, brackish water, water produced from the oil-bearing formation, and mixtures thereof. The saline source water may be processed according to conventional desalination processes to produce the low salinity aqueous fluid to be used as the second oil recovery fluid.

Alternatively, the second oil recovery fluid may be an aqueous solution containing one or more surfactants. The surfactant(s) may be any surfactant effective to reduce the interfacial tension between water and residual oil left in the formation after passage of the first oil recovery fluid through the formation and thereby mobilize the residual oil for production from the formation. The surfactant may be an anionic surfactant. The anionic surfactant may be a sulfonate-containing compound, a sulfate-containing compound, a carboxylate compound, a phosphate compound, or a blend thereof. The anionic surfactant may be an alpha olefin sulfonate compound, an internal olefin sulfonate compound, a branched alkyl benzene sulfonate compound, a propylene oxide sulfate compound, an ethylene oxide sulfate compound, a propylene oxide-ethylene oxide sulfate compound, or a blend thereof. The anionic surfactant may contain from 12 to 28 carbons, or from 12 to 20 carbons. The surfactant of the second oil recovery fluid may comprise an internal olefin sulfonate compound containing from 15 to 18 carbons or a propylene oxide sulfate compound containing from 12 to 15 carbons, or a blend thereof, where the blend contains a volume ratio of the propylene oxide sulfate to the internal olefin sulfonate compound of from 1:1 to 10:1.

The aqueous surfactant solution of the second oil recovery fluid may contain an amount of the surfactant effective to reduce the interfacial tension between residual oil and water in the formation and thereby mobilize the residual oil for production from the formation. The aqueous surfactant solution of the second oil recovery fluid may contain from 0.05 wt. to 5 wt. of the surfactant or combination of surfactants, or may contain from 0.1 wt.% to 3 wt.% of the surfactant or combination of surfactants.

The aqueous surfactant solution of the second oil recovery fluid may also contain a co-solvent, where the co-solvent may be a low molecular weight alcohol including, but not limited to, methanol, ethanol, and iso-propanol, isobutyl alcohol, secondary butyl alcohol, n-butyl alcohol, t-butyl alcohol, or a glycol including, but not limited to, ethylene glycol, 1,3 -propanediol, 1 ,2-propandiol, diethylene glycol butyl ether, triethylene glycol butyl ether, or a sulfosuccinate including, but not limited to, sodium dihexyl sulfosuccinate. The co- solvent may be utilized in the aqueous surfactant solution of the second oil recovery fluid for assisting in prevention of formation of a viscous emulsion. If present, the co- solvent may comprise from 100 ppm to 50000 ppm, or from 500 ppm to 5000 ppm of the aqueous surfactant solution of the second oil recovery fluid. A co-solvent may be absent from the aqueous surfactant solution of the second oil recovery fluid.

Alternatively, the second oil recovery fluid may be an aqueous mixture containing a polymer. The aqueous polymer mixture of the second oil recovery fluid may be prepared or conditioned to have a viscosity on the same order of magnitude as the viscosity of residual oil in the formation under formation temperature conditions so the second oil recovery fluid may mobilize and drive the residual oil across the formation for production from the formation with a minimum of fingering of the oil through the second oil recovery fluid and/or fingering of the second oil recovery fluid through the oil. The aqueous polymer mixture may comprise a polymer selected from the group consisting of polyacrylamides; partially hydrolyzed polyacrylamides; polyacrylates; ethylenic copolymers; biopolymers; carboxymethylcelloluses; polyvinyl alcohols; polystyrene sulfonates; polyvinylpyrrolidones; AMPS (2-acrylamide-methyl propane sulfonate); co- polymers of acrylamide, acrylic acid, AMPS, and n-vinylpyrrolidone in any ratio; and combinations thereof. Examples of ethylenic co-polymers include co-polymers of acrylic acid and acrylamide, acrylic acid and lauryl acrylate, and lauryl acrylate and acrylamide. Examples of biopolymers include xanthan gum, guar gum, and scleroglucan.

The quantity of polymer in the aqueous polymer mixture of the second oil recovery fluid should be sufficient to provide the second oil recovery fluid with a viscosity sufficient to drive mobilized residual oil through the oil-bearing formation with a minimum of fingering of the second oil recovery fluid through the mobilized residual oil and with a minimum of fingering of the mobilized residual oil through the second oil recovery fluid. The quantity of the polymer in the aqueous polymer mixture of the second oil recovery fluid may be sufficient to provide the second oil recovery fluid with a dynamic viscosity at formation temperatures on the same order of magnitude, or, less preferably a greater order of magnitude, as the dynamic viscosity of the residual oil in the oil-bearing formation at formation temperatures so the second oil recovery fluid may push mobilized residual oil through the formation. The quantity of the polymer in the aqueous polymer mixture of the second oil recovery fluid may be sufficient to provide the second oil recovery fluid with a dynamic viscosity 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) at 25°C or at a temperature within a formation temperature range. The concentration of polymer in the aqueous mixture of the second oil recovery fluid may be from 250 ppm to 10000 ppm, or from 500 ppm to 5000 ppm, or from 1000 to 2000 ppm.

The molecular weight average of the polymer in the aqueous polymer mixture should be sufficient to provide sufficient viscosity to the second oil recovery fluid to drive mobilized residual oil through the formation. The polymer may have a molecular weight average of at least 10000 daltons, or at least 50000 daltons, or at least 100000 daltons. The polymer may have a molecular weight average of from 10000 to 30000000 daltons, or from 100000 to 15000000 daltons.

Alternatively, the second oil recovery fluid may be an alkaline-surfactant-polymer ("ASP") formulation. The ASP formulation may be an aqueous solution containing one or more surfactants as described above, and containing one or more polymers as described above, and containing an alkali. The alkali of the second oil recovery fluid ASP formulation may be any alkali effective to interact with residual oil in the formation to form a soap effective to reduce the interfacial tension between residual oil and water in the formation. The second oil recovery fluid ASP formulation may comprise one or more alkali compounds. The one or more alkali compounds may be selected from the group consisting of lithium hydroxide, sodium hydroxide, potassium hydroxide, lithium carbonate, sodium carbonate, potassium carbonate, lithium bicarbonate, sodium bicarbonate, potassium bicarbonate, lithium silicate, sodium silicate, potassium silicate, lithium phosphate, sodium phosphate, potassium phosphate, and mixtures thereof.

The second oil recovery fluid ASP formulation may contain an amount of surfactant as described above, an amount of polymer as describe above, and an amount of the alkali effective to interact with the residual oil in the formation to form a soap effective to reduce the interfacial tension between residual oil and water in the formation and thereby mobilize the residual oil for production from the formation. The second oil recovery fluid may contain from 0.001 wt. to 5 wt. of the alkali, or from 0.005 wt. to 1 wt.% of the alkali, or from 0.01 wt.% to 0.5 wt.% of the alkali.

Alternatively, the second oil recovery fluid may comprise an ether, preferably dimethyl ether ("DME") or diethyl ether ("DEE"). The ether of the second oil recovery fluid should be soluble in water and soluble in oil, where the ether may be transported through formation water and/or the first recovery fluid to residual oil in the formation by introduction of the second oil recovery fluid into the formation, and the ether may mobilize the residual oil by reducing the viscosity of the residual oil upon contact with the residual oil. Preferably the second oil recovery fluid is a dimethyl ether formulation. The dimethyl ether formulation may include dimethyl ether and/or dimethyl ether derivatives and/or precursors for example, methanol and mixtures thereof.

Referring now to Fig. 4, the second oil recovery fluid is introduced into the formation 111 for a second time period by injecting the second oil recovery fluid into the formation, where, as described above, the second time period commences, at the earliest, upon initial production of a mixture comprising oil and the first oil recovery fluid through the second well 103. Injection of the first oil recovery fluid through the first well 101 may continue throughout the second time period, or for a portion of the second time period. Oil 121 mobilized by the first oil recovery fluid, or by the first and the second oil recovery fluids, is produced from the formation through the third well 105 during the second time period, or for a portion of the second time period.

The pressure at which the second oil recovery fluid is introduced into the formation 111 through the second well 103 may range from the instantaneous pressure in the formation at the second well 103 up to the fracture pressure of the formation or exceeding the fracture pressure of the formation. The pressure at which the second oil recovery fluid may be injected into the formation may range from 20% to 95%, or from 40% to 90%, of the fracture pressure of the formation. Alternatively, the second oil recovery fluid may be injected into the formation at a pressure of at least the fracture pressure of the formation, where the second oil recovery fluid may be injected under formation fracturing conditions.

The volume of the second oil recovery fluid introduced into the formation 111 via the second well 103 may range from 0.05 to 20 pore volumes between the second well 103 and the third well 105, or from 0.1 to 10 pore volumes between the second well and the third well, or from 0.2 to 5 pore volumes between the second well and the third well, where the term "pore volume between the second well and the third well" refers to the volume of the formation that may be swept by the second oil recovery fluid between the second well 101 and the third well 105. The pore volume between the second well and the third well may be readily be determined by methods known to a person skilled in the art, for example by modelling studies or by injecting water having a tracer contained therein through the formation 111 from the second well 101 to the third well 105. In one embodiment of the process of the present invention, as described in further detail below, a slug of limited volume of the second oil recovery fluid, for example a volume of from 0.1 to 1 pore volume between the second and third well, is injected into the formation 111 through the second well 103 in the second time period while continuing injection of the first oil recovery fluid through the first well 101 and producing mobilized oil from the formation through the third well 105. In another embodiment of the process of the present invention, as described in further detail below, a large volume of the second oil recovery fluid, for example a volume of greater than 1 pore volume between the second and third wells, is injected into the formation through the second well 103 in the second time period while producing mobilized oil from the formation through the third well 105, and, optionally, continuing injection of the first oil recovery fluid into the formation through the first well for a portion, or all, of the second time period. As the second oil recovery fluid is introduced into the formation 111 during the second time period, the second oil recovery fluid spreads into the formation as shown by arrow 415. Upon introduction to the formation 111 and during the second time period, the second oil recovery fluid contacts residual oil within the formation, mobilizes at least a portion of the contacted residual oil, and pushes at least a portion of the mobilized residual oil 121 across the formation to the third well 105. The second oil recovery fluid contacts at least a portion of the formation from which a portion of oil has been mobilized and removed by contact with the first oil recovery fluid. The second oil recovery fluid may act as a tertiary oil recovery fluid and mobilize at least a portion of residual oil left behind in the portion of the formation from which oil has been mobilized and removed by contact with the first oil recovery fluid. A portion of the first oil recovery fluid injected into the formation through the first well 101 may precede the second oil recovery fluid through the formation to the third well, mobilizing and moving oil for production from the third well 105. The second oil recovery fluid may follow a portion of the first oil recovery fluid from the second well to the third well, and may mix with a portion of the first oil recovery fluid. The injected second oil recovery fluid may push at least a portion of the first oil recovery fluid through the formation from the second well to the third well, where the first and second oil recovery fluids mobilize oil 121 for production from the third well.

Referring now to Fig. 5, when the wells are horizontally disposed in the formation, the second oil recovery fluid is introduced into the formation 111 during the second time period through the horizontally disposed portion 203 of the second well 103, and the second oil recovery fluid spreads into the formation as shown by arrows 515. Upon introduction to the formation 111 and during the second time period, the second oil recovery fluid contacts oil within the formation, mobilizes at least a portion of the contacted oil, and pushes at least a portion of the mobilized oil downwards to the horizontally disposed portion 205 of the third well 105. At least a portion of the mobilized oil 221 then may be produced from the formation through the third well 105. The second oil recovery fluid contacts at least a portion of the formation 111 from which a portion of oil has been mobilized and removed by contact with the first oil recovery fluid. The second oil recovery fluid may act as a tertiary oil recovery fluid and mobilize at least a portion of residual oil left behind in the portion of the formation from which oil has been mobilized and removed by contact with the first oil recovery fluid. A portion of the first oil recovery fluid injected into the formation through horizontally disposed portion 201 of the first well 101 may precede the second oil recovery fluid downward through the formation to the horizontally disposed portion 205 of the third well 105, mobilizing and moving oil for production from the third well 105. The second oil recovery fluid may follow a portion of the first oil recovery fluid from the horizontally disposed portion 203 of the second well 103 to the horizontally disposed portion 205 of the third well 105 and may mix with a portion of the first oil recovery fluid. The injected second oil recovery fluid may push at least a portion of the first oil recovery fluid downward through the formation from the horizontally disposed portion 203 of the second well 103 to the horizontally disposed portion 205 of the third well 105, where the first and second oil recovery fluids mobilize oil for production from the third well.

The first oil recovery fluid may be injected through the first well 101 for a portion, or all, of the second time period. Injection of the first oil recovery fluid through the first well 101 during at least a portion of the second time period may continue to push the first oil recovery fluid within the formation and oil mobilized by the first oil recovery fluid through the formation to the third well 105 for production therefrom. Injection of the first oil recovery fluid through the first well during at least a portion of the second time period may also serve to drive the second oil recovery fluid and residual oil mobilized by the second oil recovery fluid to the third well for production therefrom, particularly if the first oil recovery fluid is more dense than the second oil recovery fluid and the residual oil mobilized by the second oil recovery fluid. In an embodiment of the process of the present invention, the first oil recovery fluid is injected through the first well 101 into the formation 111 for at least 25% of the time of the second time period, or for at least 50% of the time of the second time period, or for the entire second time period. In another embodiment, the first oil recovery fluid is not injected into the formation during the second time period.

Referring now to Figs. 6 and 7, a large volume of the second oil recovery fluid may be introduced into the formation 111 through the second well 103 during the second time period, where the volume of the second oil recovery fluid introduced into the formation may be greater than 1 pore volume, or greater than 2 pore volumes, or greater than 3 pore volumes, or from 1 pore volume and 20 pore volumes, or from 2 pore volumes to 10 pore volumes between the second well 103 and the third well 105, or respective horizontally disposed portions 203 and 205 thereof. At the end of the second time period after injection of a volume of the second oil recovery fluid into the formation of greater than 1 pore volume between the second well and the third well or their respective horizontally disposed portions thereof, the injected second oil recovery fluid 415 or 515 may extend in a fluid path within the formation from the second well 103 to the third well 105, or from their respective horizontally disposed portions 203 and 205 thereof. The oil 121 or 221 mobilized by the relatively large volume of second oil recovery fluid and at least a portion of oil mobilized by the first oil recovery fluid remaining in the formation may be produced from the formation through the third well 105.

In an embodiment of the process of the present invention, as shown in Fig. 8, when a relatively large volume of the second oil recovery formulation is introduced into the formation as described above through the second well 103, oil 122 may be produced from the formation through the first well 101 and oil 121 may be produced from the formation through the third well 105. Injection of the first oil recovery fluid into the formation through the first well may be halted at the beginning of the second time period, or in a first portion of the second time period, and oil may be produced from the first well 101 after injection of the first oil recovery fluid through the first well is halted. A portion 815 of the second oil recovery fluid injected into the formation may mobilize and drive at least a portion of oil 122 not mobilized by contact of the first oil recovery fluid with oil in the formation to the first well 101 for production therefrom. As described above, another portion 415 of the second oil recovery fluid may mobilize and drive at least a portion of oil 121 to the third well for production therefrom. The first oil recovery fluid 115 and oil mobilized thereby located in a fluid path between the first and second wells 101 and 103 also may be mobilized and driven for production from the first well by injection of the second oil recovery fluid into the formation through the second well.

Alternatively, referring now to Figs. 9 and 10, a small volume slug 915 or 1015 of the second oil recovery fluid, relative to the pore volume within the formation between the second and third wells 103 and 105, or their respective horizontally disposed portions 203 and 205 thereof, may be introduced into the formation through the second well during the second time period. The volume of the second oil recovery fluid 915 or 1015 introduced into the formation in this embodiment of the process may be from 0.05 to 1 pore volumes between the second well 103 and the third well 105 or their respective horizontally disposed portions 203 and 205 thereof. The relatively small volume slug of the second oil recovery fluid 915 or 1015 may be sufficient to mobilize a substantial portion of the residual oil not mobilized by contact of the first oil recovery fluid with oil in the formation, for example at least 10 wt.%, or at least 20 wt.%, or at least 50 wt.% of the residual oil may be mobilized by contact with the second oil recovery fluid slug. In this embodiment, the slug of the second oil recovery fluid 915 or 1015 is injected into the formation through the second well 103, or a horizontally disposed portion 203 thereof, while continuing injection of the first oil recovery fluid through the first well 101 or a horizontally disposed portion 201 thereof. The injected second oil recovery fluid slug 915 or 1015 may contact and mobilize at least a portion of the oil in the formation not mobilized by contact with the first oil recovery fluid. The second oil recovery fluid slug and mobilized oil 121 or 221 may be driven across the formation to the third well 105 for production therefrom initially by the continued injection of the second oil recovery fluid slug.

After injection of the second oil recovery fluid slug 915 or 1015 is complete and the second time period is over, injection of the first oil recovery fluid 115 or 215 through the first well 101 or horizontal portion 201 thereof is continued for a third time period, where the third time period commences upon the end of the second time period. The second oil recovery fluid slug 915 or 1015 and mobilized oil 121 or 221 may be driven across the formation to the third well 105 or horizontal portion thereof 205 for production therefrom during the third time period by the continued injection of the first oil recovery fluid through the first well. Optionally, the first oil recovery fluid may be injected into the formation through the second well 103 or horizontal portion thereof 203 during the third period, either while continuing injection of the first oil recovery fluid into the formation through the first well 101 or horizontal portion 201 thereof, or after stopping injection of the first oil recovery fluid into the formation through the first well.

Oil 121 or 221, including oil mobilized by contact with the first oil recovery fluid and residual oil mobilized by contact with the second oil recovery fluid may be produced from the formation through the third well 105. A portion of the first oil recovery fluid, a portion of the second oil recovery fluid, and formation water may also be produced from the formation 111 through the third well 105. Production of oil from the formation 111 through the third well 105 may be continued for the first, second, and third time periods, where production may be halted when insufficient oil is produced to render the process economical.

The present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, 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, the compositions and methods can also "consist essentially of or "consist of the various components and steps. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, "from a to b," or, equivalently, "from a-b") disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Whenever a numerical range having a specific lower limit only, a specific upper limit only, or a specific upper limit and a specific lower limit is disclosed, the range also includes any numerical value "about" the specified lower limit and/or the specified upper limit. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles "a" or "an", as used in the claims, are defined herein to mean one or more than one of the element that it introduces.

Claims

C L A I M S

1. A process for recovering oil from an oil-bearing formation, comprising:

for a second time period, injecting a second oil recovery fluid into the formation through the second well, and producing oil from the formation through a third well extending into the formation, where the second well is located on a fluid flow path within the formation between the first well and the third well, where the first oil recovery fluid and the second oil recovery fluid have different compositions, and wherein the second time period is after the first time period, and the second time period commences, at the earliest, upon initial production of a mixture comprising oil and the first oil recovery fluid from the formation through the second well.

2. The process of claim 1, further comprising, for a third time period injecting the first oil recovery fluid into the formation through the first well and producing oil from the formation through the third well, wherein the third time period commences upon cessation of injecting the second oil recovery fluid into the formation through the second well.

3. The process of claim 1 or claim 2, further comprising the step of producing oil from the formation through the third well for at least a portion of the first time period.

4. The process of claim 1 or any of claims 2-3, wherein the second time period commences, at the earliest, upon production of a mixture comprising oil, formation water, and the first oil recovery fluid having a weight ratio of the first oil recovery fluid plus formation water to oil of at least 1:1.

5. The process of claim 1 or any of claims 2-4 wherein the first oil recovery fluid is water or brine.

6. The process of claim 1 or any of claims 2-5, wherein the second oil recovery fluid is selected from the group consisting of water having a total dissolved solids content of from 200 ppm to 10000 ppm and an ionic strength of at most 0.15M, brine, an aqueous solution of a surfactant or combination of surfactants, an alkaline- surfactant-polymer formulation, an aqueous solution of water soluble polymer, and an ether or an aqueous solution of an ether.

7. The process of claim 1 or any of claims 2-6, wherein a slug of from 0.1 to 1 pore volumes, as measured between the second well and the third well, of the second oil recovery fluid is injected into the formation.

8. The process of claim 1 or any of claims 2-7 wherein the first well is part of an array of 2 to 500 first wells, the second well is part of an array of 2 to 100 second wells, and the third well is part of an array of 2 to 100 third wells, wherein each second well is located on a fluid flow path within the formation between a corresponding first well and a corresponding third well.

9. The process of claim 1 or any of claims 2-8 wherein the formation, the first well the second well, and the third well are located offshore.

10. The process of claim 1 or any of claims 2-9, further comprising the step of injecting the first oil recovery fluid into the formation through the first well for at least a portion of the second time period.

11. The process of claim 1 wherein the injected first oil recovery fluid mobilizes oil for production from the formation upon injection into the formation and the injected second oil recovery fluid mobilizes residual oil for production from the formation upon injection into the formation, wherein the residual oil is oil that is not mobilized by the first oil recovery fluid.

12. The process of claim 1 further comprising producing oil from the formation for at least a portion of the second time period.

The process of claim 1 wherein the first well and the third well are at least 1 km apart.