CN105247165A - Method for enhanced oil recovery from oil-bearing formations - Google Patents

Abstract

The present application provides methods for recovering oil from oil-bearing formations. A first oil recovery fluid is introduced into the formation through a first well for a first period of time, and oil is produced from a second well. During a second period following the first period, a second oil recovery fluid different from the first oil recovery fluid is introduced into the formation through a second well and oil is produced from a third well, wherein the second well is located at On a fluid flow path extending between the first and third wells.

Description

Method for enhanced oil recovery from oil-bearing formations

technical field

The present invention relates to methods for enhanced oil recovery from oil-bearing formations.

Background technique

In the process of recovering oil from an underground oil-bearing formation, only a part of the oil in the formation can be recovered by employing a primary oil recovery method of producing oil using natural formation pressure. A portion of the oil that cannot be produced from the formation by primary oil recovery methods can be produced by improved or enhanced oil recovery (EOR).

In secondary oil recovery, water or brine is injected into injection wells extending into the oil-bearing formation after the primary oil recovery process is complete. Water or brine mobilizes the oil in the formation, propelling the mobile oil from the injection well to the production well at a distance from the injection well. The mobile oil is produced in the production well along with the formation water and the water injected into the formation.

The secondary oil recovery process, although effective in recovering some portion of the oil remaining in the formation after the primary oil recovery process has ended, often leaves a substantial portion of the residual oil in the formation. The oil may become trapped in the pores of the formation rock, or the oil may adhere to the rock surface of the formation rather than being propelled into the formation by injected water. After the injected water has passed through the formation, residual oil can be trapped in the formation (if only primary and secondary oil recovery processes are used to recover oil from the formation, this would potentially greatly reduce the recovered oil).

A portion of the residual oil at some locations in the formation can be removed after a secondary recovery waterflood by injecting an oil recovery agent into the formation that is different from the water or brine injected into the formation during a secondary recovery waterflood. Produced, this process is called the tertiary oil recovery process. EOR formulations can circulate oil by, for example, releasing oil that is trapped in the pores of formation rock, or by altering the adhesion of oil to the rock surface of the formation, or by reducing the amount of residual oil in the formation. Interfacial tension between oil and water, or by changing the physical properties of the residual oil (eg, viscosity). Examples of such EOR formulations include low ionic strength water, water-soluble polymer formulations, alkali-surfactant-polymer formulations, oil-soluble solvents (e.g., dimethyl ether), and oil-soluble gases (e.g., carbon dioxide and low molecular weight hydrocarbons).

The secondary oil recovery process and the tertiary oil recovery process can be performed by employing a conventional injector-producer configuration. Some conventional injector-producer configurations for secondary and tertiary oil recovery processes are chosen such that the injected water or oil recovery formulation pushes the oil in the formation from the injection well through the formation to the production well. Large arrays of such injector-producer wells can be used to produce oil from a single formation. For example, 10 to 1000 injector-producer pairs arranged in a direct flow path from injector to producer may be used to produce oil from a single formation.

However, there are limitations to the application of EOR processes when using certain conventional injector-producer configurations. For example, in some conventional injector-producer configurations in offshore applications, injectors and producers are placed at large distances apart, such as 1 km or more, due to the high expenditure for drilling the wells. During secondary oil recovery, the oil is mobilized to drive the oil through the formation in a pattern or linear drive. The distance between the injection well and the production well can make the tertiary recovery process technically and economically impractical because, after a long wait for the oil to flow through the secondary recovery process to the production well, The process by which the agent circulates the oil to the production well requires a long wait time. Additionally, some of these injector-producer configurations have been formed with peripheral water injectors that inject water below the oil/water contact location in the formation, where the injected water confines or prevents EOR formulations. contact with oil, which will result in loss of EOR preparations.

There is a need for an improved tertiary oil recovery process for recovering residual oil from oil bearing formations in which injection and production wells are arranged at a greater distance apart.

Contents of the invention

The present invention relates to a method for recovering oil from an oil-bearing formation, the method comprising the steps of:

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 during a first period of time;

During a second period, a first oil recovery fluid is injected into the formation through a first well, a second oil recovery formulation is injected into the formation through a second well, and oil is produced from the formation through a third well extending into the formation , wherein the second well is located on a fluid flow path within the formation between the first well and the second well; wherein the second oil recovery fluid is different from the first oil recovery fluid; wherein the second time period is at After the first period, the second period begins as early as the first time a mixture comprising oil and the first oil recovery fluid is initially produced from the formation by the second well.

Other advantages and other features of the present disclosure will be partially explained in the following description, those of ordinary skill in the art will be able to clearly see these advantages and features after studying the following content, or can learn from the practice of the present disclosure These advantages and features can be seen. The advantages of the present disclosure having been realized and appreciated are pointed out with particularity in the appended claims.

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

Description of drawings

The drawings illustrate one or more embodiments in accordance with the present teachings, by way of example only, and not limitation. In the drawings, like reference numerals indicate the same or similar elements.

Figure 1 illustrates the steps performed in the first period of implementation of the method of the invention in a petroleum production system with vertically arranged wells.

Figure 2 illustrates the steps carried out in a second period of implementation of the method of the invention in an oil production system having a well with horizontally arranged sections.

Figure 3 is a schematic diagram of a well arrangement for producing oil according to the method of the present invention.

Figure 4 illustrates the steps carried out in a second period of implementation of the method of the invention in a petroleum production system with vertically arranged wells.

Figure 5 illustrates the steps carried out in a second period of implementation of the method of the invention in a petroleum production system having a well with horizontally arranged sections.

Figure 6 illustrates the steps performed in a second period of implementation of the method of the invention in a petroleum production system with vertically arranged wells.

Figure 7 illustrates the steps carried out in a second period of implementation of the method of the invention in a petroleum production system having a well with a horizontally arranged section.

Figure 8 illustrates the steps performed by the method of the invention during the second period of implementation in an oil production system with vertically arranged wells; wherein oil is produced from the first and third wells.

Figure 9 illustrates the steps performed in a second period of implementation of the method of the invention in a petroleum production system with vertically arranged wells.

Figure 10 illustrates the steps performed in a second period of implementation of the method of the present invention in an oil production system having a well with horizontally arranged sections.

detailed description

The present invention relates to an improved oil recovery method in which an improved oil recovery formulation (a first oil recovery fluid—after being injected into a formation through a first well) is first introduced in a first period of time The second period of time injects an improved oil recovery formulation (a second oil recovery fluid) into the oil-bearing formation through a second well located between the first well and the third well. The second oil recovery fluid is different from the first oil recovery fluid. Oil is produced from the second well during at least a portion of the first period of time, and oil is produced from the third well during at least a portion of the second period of time, optionally during at least a portion of the first period of time Oil. The second period begins as early as when a mixture comprising oil and the first oil recovery fluid is initially produced from the formation by the second well. When the first well and the third well are separated by a large distance from each other, in the Injecting the second oil recovery fluid through the second well after a period of time allows the second oil recovery fluid to mobilize residual oil for recovery that was not mobilized by the first oil recovery fluid. Compared to the time period used to produce this oil from the third well (for example, if the second oil recovery fluid is only injected through the first well, it will be required to produce this oil from the third well). The time period during which oil from the third well is produced as a result of injection of the second oil recovery fluid through the second well which becomes mobile can be greatly reduced, for example, from years to decades for production. When using peripheral When the sprinkler injects water below the oil/water contact in the formation to increase oil production, injecting a second oil recovery fluid into the formation through a second well instead of the first initial injection well will reduce the loss of the second risk of oil recovery fluids without mobilizing residual oil used for recovery.

Referring now to FIG. 1 , a first well 101 , a second well 103 , and a third well 105 are shown entering an oil-bearing formation 111 from a surface 107 , through overburden 109 . If the oil-bearing formation 111 is located offshore, the surface 107 may be a platform located on the ocean 113; or, if the oil-bearing formation 111 is located onshore, the surface 107 may be the surface of the earth (not shown).

The first well 101 may be a conventional well for injecting fluids into the oil-bearing formation; the second well 103 may be a conventional well for injecting fluids into the oil-bearing formation and for producing fluids including oil from the formation; the third well 105 It may be a conventional well used to produce fluids including oil from the oil-bearing formation. In some embodiments of the method of the present invention, the first well 101 may be a conventional well for producing fluids, including oil, from the formation, in addition to being a conventional well for injecting fluids into the 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 one embodiment of the method of the present invention, which may be performed offshore, the second well 103 may be a sidetracked well moved to a suitable position between the first well 101 and the third well 105, wherein the second Sidetracked well 103 is located within formation 111 in a fluid flow path between the first well and the third well.

As shown in FIG. 1, first well 101, third well 103, and third well 105 may be wells positioned within the formation primarily vertically or laterally relative to the surface of the ocean 113 or the surface of the earth, wherein the vertical Or each of the laterally positioned wells 101 , 103 and 105 are arranged within the formation 111 at a horizontal distance from each other. 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 may be approximately horizontal relative to the surface of the ocean (not shown) or the earth's surface 114. Positioned within a formation, wherein each of the substantially horizontally positioned portions 201, 203, and 205 of the wells 101, 103, and 105 are arranged at a vertical distance from one another within the formation.

Referring now to FIG. 3 , an array 300 of wells is shown. Array 300 includes a first well group 301 (shown with vertical lines), a second well group 303 (shown with horizontal lines), and a third well group 305 (shown with diagonal lines). The first wells may include a plurality of first wells, shown as first well group 301 in array 300; the second wells may include a plurality of second wells, shown as second wells in array 300 Well group 303 ; the third well described above may include a plurality of third wells, shown as third well group 305 in array 300 .

In some embodiments, the array of wells 300 can be viewed as a top view, with the first group of wells 301 , the second group of wells 305 and the third group of wells 307 being vertically arranged wells spaced across a field. In some embodiments, the array of wells 300 can be viewed as a cross-sectional side view of the formation showing a horizontal arrangement of first wells of a first well group 301 , a horizontal arrangement of second wells of a second well group 302 The horizontally arranged portions of the third wells of the third well group and the third well group 305 are respectively spaced apart within the formation.

Each first well in the first group of wells 301 may be spaced a distance 311 from an adjacent first well in the first group of wells, wherein the distance 311 may be from about 100 meters to about 10,000 meters, or from about 250 meters to about 10,000 meters. About 5000 meters, or about 500 meters to about 1000 meters. Each first well in the first well group 301 may be spaced a distance 313 from an adjacent first well in the first well group. The distance 313 may be from about 5 meters to about 10,000 meters, or from about 10 meters to about 2500 meters, or from about 15 meters to about 1000 meters.

Each second well in the second group of wells 303 may be separated by a distance 315 from an adjacent second well in the second group of wells. The distance 315 may be from about 100 meters to about 10,000 meters, or from about 250 meters to about 5,000 meters, or from about 500 meters to about 1,000 meters. Each second well in the second well group 303 may be spaced a distance 317 from an adjacent second well in the second well group. Distance 317 may be from about 5 meters to about 10,000 meters, or from about 10 meters to about 2,500 meters, or from about 15 meters to about 1,000 meters.

Each third well in the third well group 305 may be spaced a distance 319 from an adjacent third well in the third well group. Distance 319 may be from about 100 meters to about 10,000 meters, or from about 250 meters to about 5,000 meters, or from about 500 meters to about 1,000 meters. Each third well in the third well group 305 is spaced a distance 321 from an adjacent production well in the third well group. Distance 321 may be from about 5 meters to about 10,000 meters, or from about 10 meters to about 2,500 meters, or from about 15 meters to about 1,000 meters.

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

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

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

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

Oil-bearing formations may include porous matrix material, oil and water. The oil-bearing formation includes oil that is separated from and produced from the formation after introducing the first oil recovery fluid and after introducing the second oil recovery fluid into the formation immediately after introducing the first oil recovery fluid into the formation. The formation preferably contains a substantial amount of formation crude oil which can be recovered from the formation by mobilizing the crude oil using a first oil recovery fluid and a second oil recovery fluid and subsequently producing the mobile oil A large portion of crude oil.

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

The porous matrix material of the formation may consist of one or more porous matrix materials selected from the group consisting of porous mineral matrix, porous rock matrix, and combinations of both porous mineral matrix and porous rock matrix. The rocky and/or mineral porous matrix material of the formation may consist of sandstone, shale and/or carbonates selected from dolomite, limestone and mixtures thereof, wherein the limestone may be microcrystalline or crystalline limestone. The permeability of the formation may be 0.0001 to 15 Darcy, or may be 0.001 to 1 Darcy.

Oil in an oil-bearing formation may be located in pores within the porous matrix material of the formation. Oil in an oil-bearing formation can be held in pores within the porous matrix material of the formation, for example, by capillary forces, by interaction of the oil with the pore surface, by the viscosity of the oil, or by interfacial tension between oil and water in the formation. stand still.

The oil-bearing formation may be a formation from which oil is readily produced by injecting the first oil recovery fluid and the second oil recovery fluid into the formation, and oil is subsequently readily produced and recovered from the formation. Suitability of the formation for oil recovery is determined by performing a conventional core flow study on the core plug extracted from the formation using the first oil recovery fluid and the second oil recovery fluid sequentially as injectants, wherein, The core plug is saturated with oil from the formation and connate water or water (with a salinity adapted to the formation connate water salinity at similar initial water saturation prior to injection of the first and second oil recovery fluids) .

Referring again to FIG. 1 , in the method of the present invention, in the first period, the first oil recovery fluid is introduced into the oil-bearing formation 111, for example, by injecting the first oil recovery fluid into the formation through the first well 101, The aforementioned injection method is to pump the first oil recovery fluid into the formation through the first well 101 . The first period of time and the first period of time may begin after the end of the primary oil recovery process to recover oil from the formation, such as after less oil or no additional oil is recoverable from the formation due to the natural pressure of the formation. An injection process in which oil recovery fluid is injected into the formation 111 .

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 to the fracture pressure of the formation or a pressure exceeding the fracture pressure of the formation. The pressure at which the first oil recovery fluid is injected into the formation may range from 20% to 95% or 40% to 90% of the fracture pressure of the formation. Optionally, the first oil recovery fluid is injected into the formation at a pressure that is at least the formation fracture pressure, wherein 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 through the first well 101 varies within the range of 0.5 to 20 times the pore volume between the first well 101 and the third well 105, or between the first well and the third well. The pore volume between the three wells varies within the range of 1 to 10 times, or the pore volume between the first well and the third well varies within the range of 2 to 5 times, wherein the term "in the first well and the third well "Between well pore volume" means the formation volume 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 can be readily determined by methods known to those skilled in the art, for example, by modeling studies or by transferring water containing the tracer from the first well 101 to the third well 105. injected into formation 111.

The first oil recovery fluid may be water or brine. The first oil recovery fluid may be, for example, water or brine as used in water injection in conventional secondary oil recovery processes, where the injection of the first oil recovery fluid may be oil recovery for enhanced oil recovery from the formation rate of water injection. The water or brine used as the primary oil recovery fluid may be provided from seawater, brackish water, aquifers, lakes, rivers, or water produced from formations. The water or brine used as the first oil recovery fluid may contain or be adjusted to contain less than 100 mg/l of sulfate ions (SO ₄ ²⁻ ) to inhibit formation acidification by sulfuric acid consuming bacteria. The first oil recovery fluid water or brine can be conditioned to contain less than 100 mg/mL by conventional methods for removing sulfate ions from water, for example, by nanofiltration, by reverse osmosis, by forward osmosis, or by ion exchange. l sulfate. The water or brine used as the primary oil recovery fluid may contain, or may be adjusted to contain, a total dissolved solids (TDS) content of at least 200 parts per million (ppm) to avoid the possibility of clay swelling in the formation. The ground is unstable. Fresh water having a TDS content of less than 200 ppm can be adjusted to contain a TDS content of at least 200 ppm by adding sodium chloride or calcium chloride to the fresh water. The brine used as the first oil recovery fluid preferably contains or can be adjusted to contain a TDS content of less than 50,000 ppm. Brine with a TDS content of greater than 50,000 ppm can be adjusted to contain a TDS content of less than 50,000 ppm by conventional desalination methods, for example, by thermal desalination, nanofiltration, reverse osmosis, forward osmosis, and ion exchange.

When the first oil recovery fluid is introduced into the formation 111 during the first period of time, the first oil recovery fluid spreads into the formation as indicated by arrows 115 . Once the first oil recovery fluid is introduced into the formation 111 during the first period of time, the first oil recovery fluid contacts the oil in the formation, causes at least a portion of the contacted oil to flow, pushes at least a portion of the flowing oil 117 through The formation enters the second well 103 . At least a portion of the mobile oil 117 is then produced from the formation by the second well 103 . By introducing the first oil recovery fluid into the formation, a portion 119 of the flowing oil may be pushed through the formation into the third well such that the flowing portion of oil 119 may be produced by the third well during the first period of time.

Referring to FIG. 2, when the well is horizontally arranged in the formation, the first oil recovery fluid can be introduced into the formation through the horizontally arranged part 201 of the first well 101, and the first oil recovery fluid can be dispersed as shown by arrow 215 into formation 111. 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 flowing oil 217 downward into the horizontally disposed portion 203 of the second well 103 . At least a portion of the mobile oil 217 is then produced from the formation by the second well 103 . A portion 219 of the flowing oil may also be pushed down into the horizontally arranged portion 205 of the third well 105 by introducing the first oil recovery fluid into the formation. During the first period of time, a flowing portion of oil 219 may be produced by the horizontally arranged portion 205 of the third well 105 .

Referring now to FIGS. 1 and 2 , the first period of time is extended until a portion of the first oil recovery fluid is produced from the formation along with the oil through the second well 103 at the earliest. The first recovery fluid may be produced by the second well 103 as a mixture consisting of oil, formation water and the first oil recovery fluid. The first period of time may be extended until the total weight of the first oil recovery fluid and formation water in the mixture (which includes oil, formation water, and first oil recovery fluid) produced by the second well 103 is equal to the weight of the oil The ratio is at least 1:1 or at least 2:1 at the earliest.

Referring now to Figures 4 and 5, after the first 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 during the second period. The first oil recovery fluid may be injected into the first well 101 during a portion of the second time period or during the entire second time period.

The second period begins after the first period. The second period may begin immediately upon the end of the first period, or may begin some time after the end of the first period. The second period begins as early as the second well 103 initially produces a mixture comprising oil and the first oil recovery fluid. The second period of time may begin as soon as a mixture comprising oil, formation water, and the first oil recovery formulation is produced, wherein the ratio of the total weight of the first oil recovery fluid and the formation water in the mixture to the weight of the oil At least 1:1 or at least 2:1. The second period of time may end when injection of the second oil recovery fluid through the second well 103 into the formation 111 ceases.

The second oil recovery fluid may be a fluid effective to mobilize residual oil remaining in the formation after the first oil recovery fluid is introduced into the formation and the oil contacts the first oil recovery fluid in the formation. The second oil recovery fluid is effective to mobilize and produce the oil that has become mobile and produced by the introduction of the first oil recovery fluid into the formation, and to effectively mobilize the bulk of the residual oil and its produced. After the first oil recovery fluid flows into the formation, by releasing the residual oil trapped in the pores of the formation rock, or by changing the adhesion of the residual oil to the surface of the formation rock, or by reducing the residual oil and The second oil recovery fluid can mobilize the residual oil either by interfacial tension between water in the formation, or by changing the physical properties of the residual oil (eg, viscosity). The second oil recovery fluid is different from the first oil recovery fluid, and it can be selected from a low-salinity water-based fluid (with an ionic strength of up to 0.15M and a TDS content of 200ppm to 10000ppm), an aqueous solution of a surfactant, or A group consisting of aqueous solutions of various surfactant compositions, base-surfactant-polymer formulations, aqueous solutions of water-soluble polymers, dimethyl ether and mixtures thereof.

The second oil recovery fluid may be a low salinity water-based fluid with an ionic strength of up to 0.15M and a TDS content of 200 ppm to 10000 ppm. The low salinity water-based fluid may have a TDS content of 500 ppm to 7000 ppm, or 1000 ppm to 5000 ppm, or 1500 ppm to 4500 ppm. The low salinity water-based fluid has an ionic strength of up to 0.1M or up to 0.05M or up to 0.01M, the ionic strength may be from 0.01M to 0.15M, or from 0.02M to 0.125M, or from 0.03M to 0.1M. The term "ionic strength" as used herein is defined by the following equation:

$\mathrm{<span\; class="notranslate">\; I</span>}<span\; class="notranslate">\; =</span>\frac{\mathrm{<span\; class="notranslate">\; 1</span>}}{\mathrm{<span\; class="notranslate">\; 2</span>}}<span\; class="notranslate">\; *</span>{<span\; class="notranslate">\; \&Sigma;</span>}_{\mathrm{<span\; class="notranslate">\; i</span>}<span\; class="notranslate">\; =</span>\mathrm{<span\; class="notranslate">\; 1</span>}}^{\mathrm{<span\; class="notranslate">\; no</span>}}{\mathrm{<span\; class="notranslate">\; c</span>}}_{\mathrm{<span\; class="notranslate">\; i</span>}}{\mathrm{<span\; class="notranslate">\; z</span>}}_{\mathrm{<span\; class="notranslate">\; i</span>}}^{\mathrm{<span\; class="notranslate">\; 2</span>}}$

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.

The low salinity water-based fluid may have an ionic strength less than the ionic strength of connate water present in the oil-bearing formation, and/or the low-salinity water-based fluid may have a concentration of multivalent cations less than the concentration of multivalent cations of the connate water present in the oil-bearing formation , and/or, the low-salinity water-based fluid has a concentration of divalent cations that is less than that of connate water present in the oil-bearing formation. The ratio of the ionic strength of the low-salinity water-based fluid to the ionic strength of 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 to 1 (but not including 1), or It may be 0.05 to 0.9, or it may be 0.1 to 0.8. The ratio of the polyvalent cation content of the low salinity water-based fluid to the polyvalent cation content of 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 to 1 (but not including 1), or may be 0.05 to 0.9, or may be 0.1 to 0.8. The ratio of the divalent ion content of the low-salinity water-based fluid to the divalent ion content of 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 to 1 (but not including 1), or 0.05 to 0.9, or 0.1 to 0.8.

Low salinity water-based fluids may have relatively low multivalent cation content and/or relatively low divalent ion content. Low-salinity water-based fluids have polyvalent cation concentrations of up to 200 ppm, or up to 100 ppm, or up to 75 ppm, or up to 50 ppm, or up to 25 ppm, or may be from 1 ppm to 200 ppm, or may be 2ppm to 100ppm, or may be 3ppm to 75ppm, or may be 4ppm to 50ppm, or may be 5ppm to 25ppm. Low-salinity water-based fluids can have secondary cation concentrations up to 150ppm, or up to 100ppm, or up to 75ppm, or up to 50ppm, or up to 25ppm, or can be 1ppm to 100ppm, or can be 2ppm to 75ppm, or may be 3ppm to 50ppm, or may be 4ppm to 25ppm, or may be 5ppm to 20ppm.

Low-salinity water-based fluids may be supplied from natural sources or may be provided by treating water sources with a TDS content greater than 10,000 ppm; or, if desired, use low-salinity water-based fluids with a TDS content of 5,000 ppm or less , to provide low-salinity water-based fluids by treating water sources with a TDS content greater than 5000ppm to produce water-based fluids. Water-based fluids may be provided from natural sources (eg, aquifers, lakes, or rivers comprising water containing 200 ppm to 10,000 ppm total dissolved solids).

A water-based fluid can be produced by treating a source of brine with a TDS content greater than 10,000 ppm, thereby providing a low-salinity water-based fluid or at least a portion thereof, the system can also include a source of brine with a TDS content of greater than 10,000 ppm and a system for treating A source of brine to produce low-salinity water-based fluids. The brine source may have a TDS content of 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 15000ppm to 200000ppm, or 17500ppm to 150000ppm, or 20000ppm to 100000ppm, or 25000ppm to 50000ppm. The source of brine to be treated may be selected from the group consisting of water in aquifers, seawater, brackish water, water produced from oil-bearing formations, and mixtures thereof. The brine can be treated according to conventional desalination methods to produce a low salinity water-based fluid that is used as a secondary oil recovery fluid.

Alternatively, the second oil recovery fluid may be an aqueous solution containing one or more surfactants. The surfactant may be any surfactant effective to lower the interfacial tension between water and residual oil remaining in the formation after the first oil recovery fluid enters the formation, thereby mobilizing the residual oil to be produced from the formation. Surfactants may be anionic surfactants. The anionic surfactant may be a sulfonate-containing complex, a sulfate-containing complex, a carboxylate complex, a phosphate complex, or a mixture thereof. Anionic surfactants can be α-olefin sulfonate complexes, internal olefin sulfonate complexes, branched alkylbenzene sulfonate complexes, propylene oxide sulfate complexes, ethylene oxide sulfate complexes, propylene oxide - Ethylene oxide sulfate complexes or mixtures thereof. Anionic surfactants may contain 12 to 28 carbon atoms or 12 to 20 carbon atoms. Surfactants in the second oil recovery fluid may include internal olefin sulfonate complexes (which contain 15 to 18 carbon atoms) or propylene oxide sulfate complexes (which contain 12 to 15 carbon atoms), or their A mixture; wherein, the volume ratio of propylene oxide sulfate to internal olefin sulfonate compound (internal olefin sulfonate compound) contained in the mixture is 1:1 to 10:1.

The aqueous surfactant solution of the second oil recovery fluid may contain a certain amount of surfactant to effectively reduce the interfacial tension between the residual oil in the formation and water, so that the residual oil can flow to be produced from the formation. The surfactant aqueous solution of the second oil recovery fluid may contain 0.05% to 5% by weight of surfactant or surfactant composition, or may contain 0.1% to 3% by weight of surfactant or surfactant active agent composition.

The aqueous surfactant solution of the second oil recovery fluid may also contain a co-solvent, wherein the co-solvent may be a low molecular weight alcohol (including but not limited to methanol, ethanol and isopropanol, isobutanol, sec-butanol, n-butanol, butanol, tert-butanol) or diols (including but not limited to ethylene glycol, 1,3-propanediol, 1,2-propanediol, diethylene glycol butyl ether, triethylene glycol monobutyl ester) or sulfo Succinates (including but not limited to sodium dihexyl sulfosuccinate). Co-solvents may be used in the aqueous surfactant solution of the second oil recovery fluid to help prevent the formation of viscous emulsions. 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. Co-solvents may not be present in the aqueous surfactant solution of the second oil recovery fluid.

Alternatively, the second oil recovery fluid may be an aqueous mixture comprising a polymer. The aqueous polymer mixture of the second oil recovery fluid can be prepared or adjusted to have a viscosity of the same order of magnitude as the viscosity of the residual oil in the formation at formation temperature conditions so that the second oil recovery fluid can mobilize the residual oil , driving residual oil through the formation to be produced from the formation with minimal immersion of the oil into the second oil recovery fluid and/or minimal immersion of the second oil recovery fluid into the oil. The aqueous polymer mixture may comprise a polymer selected from the group consisting of polyacrylamides; partially hydrolyzed polyacrylamides; polyacrylates; vinyl copolymers; biopolymers; ); polyvinyl alcohol; polystyrene sulfonate; polyvinylpyrrolidone; AMPS (2-acrylamido-2-methylpropanesulfonic acid); copolymers of acrylamide, acrylic acid, AMPS and n-vinylpyrrolidone in any ratio and combinations of the foregoing. Examples of vinyl copolymers include copolymers of acrylic acid and acrylamide, acrylic acid and lauryl acrylate, and lauryl acrylate and acrylamide. Examples of biopolymers include xanthan gum, guanhua gum and scleroglucan.

The amount of polymer in the aqueous polymer mixture of the second oil recovery fluid should be sufficient such that the viscosity of the second oil recovery fluid is sufficient to drive the flowable residual oil through the oil-bearing formation so that the second oil recovery fluid is immersed in the flowable minimizing residual oil and minimizing immersion of said mobile residual oil into the secondary oil recovery fluid. The amount of polymer in the aqueous polymer mixture of the second oil recovery fluid should be sufficient such that the dynamic viscosity of the second oil recovery fluid at formation temperature is an order of magnitude greater than (less recommended) the residual oil in the oil bearing formation at formation temperature The dynamic viscosity is on the order of , so that the second oil recovery fluid can propel the mobile residual oil through the formation. The amount of polymer in the aqueous polymer mixture of the second oil recovery fluid should be sufficient such that the dynamic viscosity of the second oil recovery fluid is at least 1 mPas (1 cP), or at least 10 mPas at 25°C or at a temperature within the formation temperature range (10cP), or at least 100mPas (100cP), or at least 1000mPas (1000cP). The polymer concentration in the aqueous mixture of the second oil recovery fluid may be from 250 ppm to 10000 ppm, or may be from 500 ppm to 5000 ppm, or may be from 1000 to 2000 ppm.

The average molecular weight of the polymers in the aqueous polymer mixture should be sufficient to provide sufficient viscosity to the secondary oil recovery fluid to drive the mobile residual oil through the formation. The average molecular weight of the polymer is at least 10,000 Daltons, or at least 50,000 Daltons, or at least 100,000 Daltons. The average molecular weight of the polymer is from 10,000 to 30,000,000 Daltons, or from 100,000 to 15,000,000 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 of the above-mentioned surfactants, containing one or more of the above-mentioned polymers, and containing a base. The base in the second oil recovery fluid ASP formulation can be any base that can effectively interact with residual oil in the formation to form a fatty acid ester effective to reduce the interfacial tension between the residual oil in the formation and water. The second oil recovery fluid ASP formulation may include one or more alkali complexes. The one or more base complexes 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 the aforementioned surfactant, an amount of the aforementioned polymer, and an amount of base effective to interact with residual oil in the formation to form a fat Salts of fatty acids effectively reduce the interfacial tension between residual oil in the formation and water, thereby mobilizing the residual oil to be produced from the formation. The second oil recovery fluid may contain from 0.001% to 5% by weight alkali, or from 0.005% to 1% by weight alkali, or from 0.01% to 0.5% by weight alkali.

Optionally, the second oil recovery fluid may comprise an ether, preferably dimethyl ether (DME) or diethyl ether (DEE). The ether in the second oil recovery fluid should be soluble in water, soluble in oil, wherein the ether can pass through the formation water and/or the first oil recovery fluid by introducing the second oil recovery fluid into the formation Into the residual oil in the formation; the ether makes the residual oil mobile by reducing the viscosity of the residual oil as soon as the ether contacts it. Preferably, the second oil recovery fluid is a dimethyl ether formulation. Dimethyl ether formulations may include dimethyl ether and/or dimethyl ether derivatives and/or precursors, eg, methanol and mixtures thereof.

Referring now to FIG. 4, a second oil recovery fluid is introduced into the formation 111 by injecting a second oil recovery fluid into the formation during a second period, wherein, as described above, the second period begins as early as the second Well 103 begins when it produces a mixture comprising oil and a first oil recovery fluid. The injection of the first oil recovery fluid into the first well 101 may continue throughout the second time period or a portion of the second time period. Oil 121 circulated by the first oil recovery fluid or by the first and second oil recovery fluids is produced from the formation by the third well 105 during or for a portion of the second period of time.

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

The volume of the second oil recovery fluid introduced into the formation 111 through the second well 103 may be 0.05 to 20 times the pore volume between the second well 103 and the third well 105, between the second well and the third well 0.1 to 10 times the pore volume of the second well, or 0.2 to 5 times the pore volume between the second well and the third well, wherein the term "the pore volume between the second well and the third well" means that the second well Formation volume swept by the secondary oil recovery fluid between the second well 101 and the third well 105 . The pore volume between the second well and the third well can be readily determined by methods known to those skilled in the art, for example, by modeling studies or by transferring water containing the tracer from the second well 103 to the third well 105. injected into formation 111. In one embodiment of the method of the present invention, which is described in more detail below, a small amount of second oil of limited volume (e.g., a volume of 0.1 to 1 times the pore volume between the second and third wells) The recovery fluid is injected into the formation 111 through the second well 103 during the second period, while the injection of the first oil recovery fluid through the first well 101 continues and the production of mobile oil from the formation through the third well 105 continues. In another embodiment of the method of the present invention (which will be described in more detail below), a substantial amount of the second oil recovery fluid (e.g., a volume greater than 1 times the pore volume between the second and third wells) is The second period is injected into the formation through the second well 103, and at the same time, mobile oil is produced from the formation through the third well 105. The primary oil recovery fluid continues to be injected into the formation.

When the second oil recovery fluid is introduced into the formation 111 during the second period, the second oil recovery fluid spreads into the formation as indicated by arrows 415 . When the second oil recovery fluid is introduced into the formation 111 during the second period of time, the second oil recovery fluid contacts residual oil in the formation, mobilizes at least a portion of the contacted residual oil, and propels the flow of residual oil 121. At least a portion passes through the formation into the third well 105 . The second oil recovery fluid contacts at least a portion of the formation from which at least a portion of oil from the formation has become mobile and removed by contact with the first oil recovery fluid. The second oil recovery fluid may function as a third oil recovery fluid, mobilizing at least a portion of the residual oil still remaining in the portion of the formation from which the oil in the portion of the formation has been treated flows and passes through contact with the first oil recovery fluid and be removed). A portion of the first oil recovery fluid injected into the formation through the first well 101 may pass through the formation into the third well prior to the second oil recovery fluid to circulate and move oil for production from the third well 105 . A second oil recovery fluid may enter the third well from the second well following a portion of the first oil recovery fluid, and may mix with a portion of the first oil recovery fluid. The injected second oil recovery fluid may propel at least a portion of the first oil recovery fluid from the second well through the formation into the third well, wherein the first and second oil recovery fluids communicate the oil 121 from the first oil recovery fluid to the third well. Produced by Mitsui.

Referring now to FIG. 5 , when the well is horizontally disposed in the formation, a second oil recovery fluid is introduced into the formation 111 through the horizontally disposed portion 203 of the second well 103 during a second period of time, as indicated by arrow 515. spread into the formation as shown. As soon as the second oil recovery fluid is introduced into the formation during the second period of time, the second oil recovery fluid contacts the oil in the formation, mobilizes at least a portion of the contacted oil, at least A portion advances down into the horizontally arranged portion 205 of the third well 105 . At least a portion of the mobile oil 221 may then be produced from the formation by the third well 105 . The second oil recovery fluid contacts at least a portion of the formation 111 from which a portion of the oil has been treated to flow and has been removed by contacting the first oil recovery fluid. The second oil recovery fluid can act as a third oil recovery fluid, mobilizing at least a portion of the residual oil still remaining in the portion of the formation from which the oil has been treated to be mobile and have been removed by contact with the first oil recovery fluid). A portion of the first oil recovery fluid injected into the formation through the horizontally arranged portion 201 of the first well 101 may pass down through the formation before the second oil recovery fluid into the horizontally arranged portion 205 of the third well 105 such that Oil circulates and moves to produce from the third well 105 . The second oil recovery fluid may pass from the horizontally arranged portion 203 of the second well 103 into the horizontally arranged portion 205 of the third well 105 following a portion of the first oil recovery fluid, and may be mixed with a portion of the first oil recovery fluid. mix. The injected second oil recovery fluid may push at least a portion of the first oil recovery fluid downwardly 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, wherein , the first and second oil recovery fluids circulate oil for production from the third well.

The first oil recovery fluid may be injected through the first well 101 during a portion of the second time period or throughout the second time period. Injection of the first oil recovery fluid through the first well 101 for at least a portion of the second period of time continues to drive the first oil recovery fluid within the formation and the Oil is passed through the formation into the third well 105 to be produced therefrom. Passing through the first well during at least a portion of the second period of time, particularly if the first oil recovery fluid is thicker than the second oil recovery fluid and the residual oil capable of flowing with the second oil recovery fluid The injection process of injecting the first oil recovery fluid may also function to drive the second oil recovery fluid and the residual oil made mobile by means of the second oil recovery fluid into the third well for production therefrom. In an embodiment of the method of the present invention, the first oil is extracted from the first well 101 during at least 25% of the second period of time or at least 50% of the second period of time or during the entire second period of time. The receiver fluid is injected into the formation 111. In another embodiment, the first oil recovery fluid is not injected into the formation during the second period of time.

Referring now to FIGS. 6 and 7 , a substantial volume of a second oil recovery fluid may be introduced into the formation 111 through the second well 103 during a second period of time, wherein the volume of the second oil recovery fluid introduced into the formation may be greater than 1 time the pore volume between the second well 103 and the third well 105 or between the respective horizontally arranged portions 203 and 205, or more than 2 times the pore volume, or more than 3 times the pore volume, Or 1 to 20 times, or 2 to 10 times, the pore volume between the second well 103 and the third well 105 or between the respective horizontally arranged portions 203 and 205 . After injecting a second oil recovery fluid having a volume greater than one time the pore volume between the second well and the third well or between their respective horizontally arranged portions into the formation, at the end of the second period, the injected second The oil recovery fluid 415 or 515 may extend from the second well 103 to the third well 105 or from the respective horizontal arrangement 203 and 205 in a fluid path within the formation. At least a portion of the oil 121 or 221 moved by the action of the relatively large volume of the second oil recovery fluid and the oil moved by the first oil recovery fluid retained in the formation may be extracted from the formation through the third well 105. Produce.

In one embodiment of the method of the present invention, as shown in FIG. 8, oil 122 may pass through the first well when a relatively large volume of the second oil recovery formulation is introduced into the formation through the second well 103 as described above. 101 is produced from the formation, and oil 121 can be produced from the formation by a third well 105 . The injection of the first oil recovery fluid into the formation through the first well may be stopped at the beginning of the second period or during the first portion of the second period; during the injection of the first oil recovery fluid through the first well After shutting down, oil can be produced from the first well 101 . A portion 815 of the second oil recovery fluid injected into the formation may mobilize and drive at least a portion of the oil 122 that was not able to flow by virtue of the contact of the first oil recovery fluid with the oil in the formation and drive it into the first well 101 to be produced from it. As noted above, another portion 415 of the second oil recovery fluid can mobilize and drive at least a portion of the oil 121 into a third well for production therefrom. The second oil recovery fluid 115 located in the fluid channel between the first well 101 and the second well 103 and the treated fluid that can flow may be injected into the formation through the second well. Oil can also be circulated and driven to be produced from the first well.

Alternatively, referring now to FIGS. 9 and 10 , a small volume of second oil recovery relative to the volume of pores within the formation between second well 103 and third well 105 or between their respective horizontal portions 203 and 205 The collector body 915 or 1015 may be introduced into the formation through a second well during a second period of time. In this embodiment of the method, the volume of second oil recovery fluid 915 or 1015 introduced into the formation may be the pores between the second well 103 and the third well 105 or between their respective horizontal portions 203 and 205 0.05 to 1 times the volume. The relatively small volume of the second oil recovery fluid 915 or 1015 may be sufficient to communicate a substantial portion of the residual oil that was not communicated by the first oil recovery fluid in contact with the oil in the formation, e.g., at least 10 weight percent of the residual oil % or at least 20% or at least 50% of the fraction can be rendered mobile by contact with the small amount of secondary oil recovery fluid. In this embodiment, the small amount of second oil recovery fluid 915 or 1015 is injected into the formation through the second well 103 or its horizontal arrangement 203 while continuing to inject the first well 101 or its horizontal arrangement 201 into the formation. Oil recovery fluid. The injected small amount of the second oil recovery fluid 915 or 1015 may contact and circulate at least a portion of the oil in the formation that was not able to flow due to contact with the first oil recovery fluid. By continuing to inject the small amount of the second oil recovery fluid, the small amount of the second oil recovery fluid and the oil 121 or 221 that becomes mobile may first be driven through the formation into the third well 105 to produce oil therefrom .

Continuing to inject the first oil recovery fluid 115 or 215 through the first well 101 or its horizontal portion 201 during a third period after the process of injecting the small amount of the second oil recovery fluid 915 or 1015 and the second period ends, Wherein the third period begins as soon as the second period ends. Continuing to inject the first oil recovery fluid through the first well, the small amount of the second oil recovery fluid 915 or 1015 and the treated mobile oil 121 or 221 can be driven through the formation into the third oil recovery fluid during the third period. Well 105 or a horizontal portion 205 thereof to produce therefrom. Optionally, while the first oil recovery fluid is continuously injected into the formation through the first well 101 or its horizontal portion 201, or after the process of injecting the first oil recovery fluid into the formation through the first well is stopped, at The first oil recovery fluid may be injected into the formation through the second well 103 or its horizontal portion 203 during the three time periods.

Oil 121 or 221 , including oil communicated from contact with the first oil recovery fluid and residual oil communicated from contact with the second oil recovery fluid, may be produced from the formation by 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 by the third well 105 . The process of producing oil from the formation 111 by the third well 105 can continue during the first, second and third time periods, wherein when not enough oil is produced, production can be stopped to make the process economical.

The present invention is well adapted to attain the above objects and advantages as well as those inherent in the invention. The specific embodiments described above are illustrative only, as the 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. Although systems and methods are described in terms of "comprising," "comprising," or "comprising" various elements or steps, compositions and methods can also consist essentially of or consist of the various elements and steps. Whenever a numerical range having a lower limit and an upper limit is disclosed, any value falling within that range and any subsumed range is also specifically disclosed. In particular, each numerical range disclosed herein (in the format "a to b" or, equivalently, "a-b") should be understood as recitation of each numerical range that falls within the broader numerical range. and range. Whenever a numerical range is disclosed having only a specified lower limit, or only a specified upper limit, or both a specified upper and a specified lower limit, that range also includes approximately the specified lower limit and/or the specified Any numeric value for the upper limit. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly defined by the patentee. Additionally, the indefinite articles "a" or "an" (a, an) in the claims are defined herein to mean one or more than one of the elements described herein.

Claims (13)

1. A method for recovering oil from an oil-bearing formation, comprising the steps of: 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 during a first period of time; During a second period, a second oil recovery fluid is injected into the formation through a second well, and oil is produced from the formation through a third well extending into the formation, wherein the second well is located within the formation between the first well and On a fluid flow path between the third wells; wherein the first oil recovery fluid and the second oil recovery fluid have different compositions; wherein the second period of time is after the first period of time and the second period of time begins at the earliest This begins when a mixture comprising oil and the first oil recovery fluid is produced from the formation by the second well. 2. The method of claim 1, further comprising the step of injecting the first oil recovery fluid into the formation through the first well and producing oil from the formation through the third well during a third period of time; wherein the first The third period begins upon completion of injection of the second oil recovery fluid into the formation through the second well. 3. The method of claim 1 or 2, further comprising the step of producing oil from the formation by the third well during at least a portion of the first period of time. 4. The method of claim 1 or any one of claims 2-3, wherein the second period of time occurs as early as when a mixture comprising oil, formation water and the first oil recovery fluid is initially produced Initially, the ratio of the total weight of the first oil recovery fluid and formation water to the weight of oil in the mixture is at least 1:1. 5. The method of claim 1 or any one of claims 2-4, wherein the first oil recovery fluid is water or brine. 6. The method of claim 1 or any one of claims 2-5, wherein the second oil recovery fluid is selected from the group consisting of a total dissolved solids content of 200 ppm to 10,000 ppm and Water with an ionic strength up to 0.15M; brine; aqueous surfactants or combinations of surfactants; alkali-surfactant-polymer formulations; aqueous solutions of water-soluble polymers; aqueous ethers or ether solutions. 7. The method according to claim 1 or any one of claims 2-6, wherein a small amount of the second well whose volume is 0.1 to 1 times the measured pore volume between the second well and the third well Two oil recovery fluids are injected into the formation. 8. The method of claim 1 or any one of claims 2-7, wherein the first well is part of an array of 2 to 500 first wells and the second well is part of an array of 2 to 500 first wells. The third well is part of an array of 100 second wells, and the third well is part of an array of 2 to 100 third wells, wherein each second well is located between the corresponding first well and the corresponding third well in the formation. on the fluid flow path between the three wells. 9. The method of claim 1 or any one of claims 2-8, wherein the formation, first well, second well and third well are located offshore. 10. The method of claim 1 or any one of claims 2-9, further comprising the step of injecting a first oil recovery fluid through the first well for at least a portion of the second period of time in the formation. 11. The method of claim 1, wherein the injected first oil recovery fluid circulates oil to be produced from the formation as soon as the first oil recovery fluid is injected into the formation; Upon injection of the oil recovery fluid into the formation, the injected second oil recovery fluid communicates residual oil to be produced from the formation, wherein the residual oil is not able to be produced with the aid of the first oil recovery fluid. Oil that flows by action. 12. The method of claim 1, further comprising the step of producing oil from the formation during at least a portion of the second period of time. 13. The method of claim 1, wherein the first and third wells are separated by at least 1 km.