US20120241150A1

US20120241150A1 - Methods for producing oil and/or gas

Info

Publication number: US20120241150A1
Application number: US13/188,539
Authority: US
Inventors: Ahmed Hamed AL YAHYAI; Felix Antonio Ascanio Milano; Jose Luis CHAVARRIA; Hamish Peter CLARK; Cornelis Petrus Josephus Walthera Van Kruijsdijk; William H. Williams; Mirko ZATKA
Original assignee: Shell Oil Co
Current assignee: Shell USA Inc
Priority date: 2010-07-26
Filing date: 2011-07-22
Publication date: 2012-09-27

Abstract

A method for producing oil from an underground formation comprising providing a first well in one or more formations, the first well comprising a plurality of sections along a length of the well; providing a second well in the formation; injecting an enhanced oil recovery formulation into at least a first section and a second section of the first well and into the formation; flowing the formulation and/or oil towards the second well in one or more formations; producing the formulation and/or oil from the second well; and then modifying the injecting into the second section, while continuing the injecting into the first section.

Description

FIELD OF THE INVENTION

The present disclosure relates to methods for producing oil and/or gas.

BACKGROUND OF THE INVENTION

Enhanced Oil Recovery (EOR) may be used to increase oil recovery in fields worldwide. There are three main types of EOR, thermal, chemical/polymer and gas injection, which may be used to increase oil recovery from a reservoir, beyond what can be achieved by conventional means—possibly extending the life of a field and boosting the oil recovery factor.
Thermal enhanced recovery works by adding heat to the reservoir. The most widely practiced form is a steam-drive, which reduces oil viscosity so that it can flow to the producing wells. Chemical flooding increases recovery by reducing the capillary forces that trap residual oil. Polymer flooding improves the sweep efficiency of injected water. Miscible injection works in a similar way to chemical flooding. By injecting a fluid that is miscible with the oil, trapped residual oil can be recovered.
Referring to FIG. 1 a, there is illustrated prior art system 100. System 100 includes underground formation 102, underground formation 104, underground formation 106, and underground formation 108. Production facility 110 is provided at the surface. Well 112 traverses formations 102 and 104, and has a horizontal portion with openings in formation 106. The portion of formation 106 is shown at 114. Oil and gas are produced from formation 106 through well 112, to production facility 110. Gas and liquid may be separated from each other, gas is stored in gas storage 116 or further processed and/or transported and liquid is stored in liquid storage 118 or further processed and/or transported.
Well 132 traverses formations 102 and 104, and has a horizontal portion with openings in formation 106 or well may have openings in multiple formations. The portion of formation 106 is shown at 134. Steam is injected into well 132 from steam production facility 130, and then flows across formation 106 to aid in the production of oil and/or gas to well 112.
Well 112 has a heel section where the horizontal portion of the well intersects the vertical portion of the well, and a toe section at a distal end of the horizontal portion. These portions may be connected by a deviated section, such as a curve.
Well 132 has a heel section where the horizontal portion of the well intersects the vertical portion of the well, and a toe section at a distal end of the horizontal portion.
As shown in FIG. 1 a, the toe section of a well 132 is aligned with the heel section of well 112, and the toe section of a well 112 is aligned with the heel section of well 132.
Referring to FIG. 1 b, there is illustrated prior art system 100. System 100 includes underground formation 102, underground formation 104, underground formation 106, and underground formation 108. Production facility 110 is provided at the surface. Well 112 traverses formations 102 and 104, and has a horizontal portion with openings in formation 106 or well may have openings in multiple formations. The portion of formation 106 is shown at 114. Oil and gas are produced from formation 106 through well 112, to production facility 110. Gas and liquid may be separated from each other, gas is stored in gas storage 116 or further processed and/or transported and liquid is stored in liquid storage 118 or further processed and/or transported.
Well 132 traverses formations 102 and 104, and has a horizontal portion with openings in formation 106. The portion of formation 106 is shown at 134. Steam is injected into well 132 from steam production facility 130, and then flows across formation 106 to aid in the production of oil and/or gas to well 112.
Well 112 has a heel section where the horizontal portion of the well intersects the vertical portion of the well, and a toe section at a distal end of the horizontal portion. These portions may be connected by a deviated section, such as a curve.
Well 132 has a heel section where the horizontal portion of the well intersects the vertical portion of the well, and a toe section at a distal end of the horizontal portion.
As shown in FIG. 1 b, the toe section of a well 132 is aligned with the toe section of well 112, and the heel section of a well 112 is aligned with the heel section of well 132.
U.S. Pat. No. 5,215,146 discloses a method for reducing the time during which steam moves in a lateral direction between two parallel superimposed horizontal wells when utilizing a Steam Assisted Gravity Drainage (SAGD) process. Foam is added while injecting steam into an upper horizontal well once steam breakthrough occurs in an interwell region. Foam enters the interwell region thereby causing an increased pressure gradient. This increased pressure gradient adds to the gravity force thereby providing a greater interstitial oil velocity which increases oil drainage between wells during startup. U.S. Pat. No. 5,215,146 is herein incorporated by reference in its entirety.
Canadian Patent Number 2,277,378 discloses a pair of vertically spaced, parallel, co-extensive, horizontal injection and production wells and a laterally spaced, horizontal offset well are provided in a subterranean reservoir containing heavy oil. Fluid communication is established across the span of formation extending between the pair of wells. Steam-assisted gravity drainage (“SAGD”) is then practiced by injecting steam through the injection well and producing heated oil and steam condensate through the production well, which is operated under steam trap control. Cyclic steam stimulation is practised at the offset well. The steam chamber developed at the offset well tends to grow toward the steam chamber of the SAGD pair, thereby accelerating development of communication between the SAGD pair and the offset well. This process is continued until fluid communication is established between the injection well and the offset well. The offset well is then converted to producing heated oil and steam condensate under steam trap control as steam continues to be injected through the injection well. The process yields improved oil recovery rates with improved steam consumption. Canadian Patent Number 2,277,378 is herein incorporated by reference in its entirety.
U.S. Patent Publication Number 2005/0082067 discloses that steam assisted gravity drainage (“SAGD”) is practiced in a first section of a reservoir containing heavy oil. When steam/oil ratio rises sufficiently, steam injection into the first section is curtailed or terminated. Non-condensible gas is then injected into the section to pressurize it and production of residual oil and steam condensate is continued. Concurrently with pressurization, SAGD is practiced in an adjacent reservoir section. As a result, some of the residual oil in the first section is recovered and steam loss from the second section to the first section is ameliorated. U.S. Patent Publication Number 2005/0082067 is herein incorporated by reference in its entirety.
There is a need in the art for improved systems and methods for enhanced oil recovery. There is a further need in the art for improved systems and methods for enhanced oil recovery using steam, for example through viscosity reduction. There is a further need in the art for improved systems and methods for steam flooding. There is a further need in the art for improved systems and methods for enhanced oil recovery with steam assisted gravity drainage (SAGD).

SUMMARY OF THE INVENTION

In one aspect, the invention provides a method for producing oil from an underground formation comprising providing a first well in the formation, the first well comprising a plurality of sections along a length of the well; providing a second well in the formation; injecting an enhanced oil recovery formulation into at least a first section and a second section of the first well and into the formation; forcing the formulation and/or oil towards the second well in the formation; producing the formulation and/or oil from the second well; and then stopping the injecting into the second section, while continuing the injecting into the first section.
Advantages of the invention include one or more of the following:
Improved systems and methods for enhanced recovery of hydrocarbons from a formation with steam.
Improved systems and methods for enhanced recovery of hydrocarbons from a formation with steam injected into a horizontal well.
Improved compositions and/or techniques for secondary recovery of hydrocarbons.
Improved systems and methods for enhanced oil recovery.
Improved systems and methods for enhanced oil recovery using a SAGD process.
Improved systems and methods for enhanced oil recovery using gravity drainage.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1 a and 1 b illustrate an oil and/or gas production system.

FIG. 2 a illustrates an oil and/or gas production system.

FIG. 2 b illustrates an injection well of an oil and/or gas production system.

FIG. 2 c illustrates a production well of an oil and/or gas production system.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 2 a:
Referring to FIG. 2 a, there is illustrated oil and/or gas production system 200. System 200 includes underground formation 202, underground formation 204, underground formation 206, and underground formation 208. Production facility 210 is provided at the surface. Well 212 traverses formations 202 and 204, and has a horizontal portion with openings in a bottom portion 214 of formation 206. Oil and gas are produced from bottom portion 214 of formation 206 through well 212, to production facility 210. Gas and liquid are separated from each other, gas is stored in gas storage 216 or further processed and/or transported and liquid is stored in liquid storage 218 or further processed and/or transported.
Well 232 traverses formations 202 and 204, and has a horizontal portion with openings in a top portion 234 of formation 206. Steam is injected into well 232 from steam production facility 230, and then flows across formation 206 to aid in the production of oil and/or gas to well 212.
In some embodiments, wells 212 and 232 may be used in a single formation or in multiple formations or portions of formations. For example, well 232 may traverse formation 202, and have a horizontal portion with openings in portion of formation 204 and/or portions of formation 206. Steam is injected into well 232 from steam production facility 230, and then flows across formations 204 and 206 to aid in the production of oil and/or gas to well 212 in formation 206.
Well 212 has a heel section where the horizontal portion of the well intersects the vertical portion of the well, and a toe section at a distal end of the horizontal portion, these portions may be connected by a deviated section such as a curve.
Well 232 has a heel section where the horizontal portion of the well intersects the vertical portion of the well, and a toe section at a distal end of the horizontal portion, these portions may be connected by a deviated section such as a curve.
As shown in FIG. 2 a, the toe section of a well 232 is aligned with the heel section of well 212, and the toe section of a well 212 is aligned with the heel section of well 232. In another embodiment, the toe section of a well 232 is aligned with the toe section of well 212, and the heel section of a well 212 is aligned with the heel section of well 232. The relative alignment of the toe sections and the heel sections is not critical.
In some embodiments, the vertical spacing between the horizontal section of well 212 and the horizontal section of well 232 may be from about 5 to about 150 meters, for example from about 10 to about 50 m.
In some embodiments, the horizontal spacing between the horizontal section of well 212 and the horizontal section of well 232 may be from about 5 to about 200 meters, for example from about 10 to about 100 m.
In some embodiments, the horizontal section of well 212 may have a length from about 50 to about 2000 m, for example from about 200 to about 1000 m.
In some embodiments, the horizontal section of well 232 may have a length from about 50 to about 2000 m, for example from about 200 to about 1000 m.
In some embodiments, formation 206 may be at a depth from about 50 to about 5000 m, for example from about 100 to 500 meters deep.
In some embodiments, wells 212 and 232 may be horizontal and may be used for a SAGD type recovery, where steam is injected into well 232 which forms a steam chamber above and around well 232. The steam mobilizes oil in the area which drains by gravity to well 212.
In some embodiments, wells 212 and 232 may be horizontal and may be used for a steam drive type recovery, where steam is injected into well 232 which mobilizes oil in the area and forces the oil towards well 212. In some embodiments, wells 212 and/or wells 232 may be vertical wells.
In some embodiments, wells 212 and 232 may be horizontal and may be used for a hybrid SAGD and steam drive type recovery.
In some embodiments, wells 212 and 232 may be used for an EOR recovery, for example where steam, water, solvents, polymers, surfactants, akalis, and/or mixtures thereof may be injected into well 232 to produce more oil from well 212. In some embodiments, wells 212 and/or wells 232 may be vertical wells.
Although wells 212 and 232 are shown with an abrupt right angle transition from vertical to horizontal, in some embodiments, wells 212 and 232 may have a smooth transition from vertical to deviated to horizontal, for example with a smooth curved radius.
FIG. 2 b:
Referring now to FIG. 2 b, a detailed view of the horizontal section of well 232 is shown. The horizontal section of well 232 includes section 232 a, section 232 b, and section 232 c. Steam supply line 240 is connected to the steam source 230 at a first end, and is located within the vertical section well 232, and then is connected to valves 242 a, 242 b, and 242 c at a second end. Section 232 a, section 232 b, and section 232 c are separated from each other by dividers 270. Suitable dividers 270 include packers, cup seals, steam diverters, or a wall across well 232.
Section 232 a includes valve 242 a which diverts a portion of steam from steam supply line 240 into chamber 244 a. Steam exits the chamber 244 a through perforations 246 a and flows into formation portions 234. One or more sensors 248 a are provided adjacent to perforations 246 a to measure formation and/or oil properties, such as pressure, temperature, chemical properties, etc. Sensors 248 a could be a pressure transducer, a thermometer, a thermocouple, a fiber optic sensor, or other sensors as are known in the art.
Section 232 b includes valve 242 b which diverts a portion of steam from steam supply line 240 into chamber 244 b. Steam exits the chamber 244 b through perforations 246 b and flows into formation portions 234. One or more sensors 248 b are provided adjacent to perforations 246 b to measure formation and/or oil properties, such as pressure, temperature, chemical properties, etc. Sensors 248 b could be a pressure transducer, a thermometer, a thermocouple, a fiber optic sensor, or other sensors as are known in the art.
Section 232 c includes valve 242 c which diverts a portion of steam from steam supply line 240 into chamber 244 c. Steam exits the chamber 244 c through perforations 246 c and flows into formation portions 234. One or more sensors 248 c are provided adjacent to perforations 246 c to measure formation and/or oil properties, such as pressure, temperature, chemical properties, etc. Sensors 248 c could be a pressure transducer, a thermometer, a thermocouple, a fiber optic sensor, or other sensors as are known in the art.
Although perforations 246 a, 246 b, and 246 c may be used, in other embodiments, other types of openings may be used, for example, a slotted liner, a sand screen, a wire-wrap screen, a casing, a liner, or other completion methods as are known in the art giving connection between wellbore and formation.
Although section 232 a, section 232 b, and section 232 c are shown as horizontal sections in the Figure, in some embodiments, section 232 a, section 232 b, and section 232 c may be a horizontal section, a vertical section, or a deviated section for example from about 15 to about 75 degrees from horizontal.
FIG. 2 c:
Referring now to FIG. 2 c, a detailed view of the horizontal section of well 212 is shown. The horizontal section of well 212 includes section 212 a, section 212 b, and section 212 c. Oil and/or gas production line 250 is connected to the production facility 210 at a first end, and is located within the vertical section of well 212, and then is connected to valves 252 a, 252 b, and 252 c at a second end. Section 212 a, section 212 b, and section 212 c are separated from each other by dividers 272. Suitable dividers 272 include packers, cup seals, steam diverters, or a wall across well 212.
Section 212 a includes valve 252 a which allows oil and/or gas and/or steam or other injected fluids in chamber 254 a to flow into valve 252 a and then into oil and/or gas production line 250. Oil and/or gas flow into the chamber 254 a through perforations 256 a from formation portions 214. One or more sensors 258 a are provided adjacent to perforations 256 a to measure formation and/or oil properties, such as pressure, temperature, chemical properties, etc. Sensors 258 a could be a pressure transducer, a thermometer, a thermocouple, a fiber optic sensor, or other sensors as are known in the art.
Section 212 b includes valve 252 b which allows oil and/or gas and/or steam or other injected fluids in chamber 254 b to flow into valve 252 b and then into oil and/or gas production line 250. Oil and/or gas flow into the chamber 254 b through perforations 256 b from formation portions 214. One or more sensors 258 b are provided adjacent to perforations 256 b to measure formation and/or oil properties, such as pressure, temperature, chemical properties, etc. Sensors 258 b could be a pressure transducer, a thermometer, a thermocouple, a fiber optic sensor, or other sensors as are known in the art.
Section 212 c includes valve 252 c which allows oil and/or gas and/or steam or other injected fluids in chamber 254 c to flow into valve 252 c and then into oil and/or gas production line 250. Oil and/or gas flow into the chamber 254 c through perforations 256 c from formation portions 214. One or more sensors 258 c are provided adjacent to perforations 256 c to measure formation and/or oil properties, such as pressure, temperature, chemical properties, etc. Sensors 258 c could be a pressure transducer, a thermometer, a thermocouple, a fiber optic sensor, or other sensors as are known in the art.
Although section 212 a, section 212 b, and section 212 c are shown as horizontal sections in the Figure, in some embodiments, section 212 a, section 212 b, and section 212 c may be a horizontal section, a vertical section, or a deviated section for example from about 15 to about 75 degrees from horizontal.
Although perforations 256 a, 256 b, and 256 c may be used, in other embodiments, other types of openings may be used, for example, a slotted liner, a sand screen, a wire-wrap screen, a casing, a liner, or other completion methods as are known in the art giving connection between wellbore and formation.
Operation:
In operation, steam may be generated at steam source 230 and then pumped through steam supply line 240 to valves 242 a, 242 b, and 242 c. A portion of steam will be supplied to each of the chambers 244 a, 244 b, and 244 c. Steam will then flow into the formation portions 234, that will act to heat, mobilize, lower the viscosity of, and/or force oil and/or gas across the formation 206 and into the formation portions 214. Oil and/or gas will then enter into the chambers 254 a, 254 b, and 254 c through the perforations 256. The oil and/or gas will be collected in the oil production line 250 and brought to the surface.
If the formation 206 between section 232 a and section 212 a has a higher porosity and/or many more fractures than the portion of the formation between section 232 c and section 212 c, then much more steam will flow between section 232 a and section 212 a. This high volume of steam pumped across the formation 206 between section 232 a and section 212 a will cause that section of the formation to get much hotter than the portion of the formation between section 232 c and section 212 c. It could also cause an increased volume of oil and/or gas across that section of the formation 206. In such a case, the valve 242 a could be turned off for a period of time, or turned down for period of time so that less steam would be provided to section 232 a.
It is generally desirable in a steam flooding operation to uniformly heat the formation adjacent to all of the sections 232 a, 232 b, and 232 c; and/or to uniformly produce oil and/or gas across the formation 206 adjacent to all of the sections 232 a, 232 b, and 232 c. In order to achieve the goals of uniformly heating the formation and/or uniformly producing oil and/or gas, valves 242 a, 242 b, and 242 c may be used to provide more steam to sections that are cooler and less steam to sections that are hotter. In addition, valves 252 a, 252 b, and 252 c may be used to reduce the flow of oil and/or gas and/or steam or other injected fluids from fast flowing sections, and to increase the flow of oil and/or gas and/or steam or other injected fluids from slow flowing sections.
In some embodiments, valves 242 a, 242 b, and 242 c are on-off valves, while in other embodiments valves 242 a, 242 b, and 242 c may be positioned on, off, and numerous positions in between which are partially on.
In some embodiments, valves 252 a, 252 b, and 252 c are on-off valves, while in other embodiments valves 252 a, 252 b, and 252 c may be positioned on, off, and numerous positions in between which are partially on.
In some embodiments, valves 242 a, 242 b, and 242 c and valves 252 a, 252 b, and 252 c may be controlled from the surface, for example hydraulically controlled, electrically controlled, and/or mechanically controlled.
In some embodiments, valves 242 a, 242 b, and 242 c may be used in well 232 with no valves in well 212.
In some embodiments, valves 252 a, 252 b, and 252 c may be used in well 212 with no valves in well 232.
In some embodiments, valves 242 a, 242 b, and 242 c may be used in well 232 and valves 252 a, 252 b, and 252 c may be used in well 212.
In some embodiments, suitable control valves 252 and 242 are commercially available from e.g., Baker Hughes, Halliburton, and Schlumberger.
The recovery of oil and/or gas with array of wells 200 from an underground formation may be accomplished by any known method. Suitable methods include subsea production, surface production, primary, secondary, or tertiary production. The selection of the method used to recover the oil and/or gas from the underground formation is not critical.
Although above the steam has been discussed as the injectant, other injectants can also be used with the system to increase the flow of oil from the formation. In some embodiments, oil and/or gas may be recovered from a formation into a well, and flow through the well and flowline to a facility. In some embodiments, enhanced oil recovery, with the use of an agent for example steam, water, a surfactant, a polymer flood, and/or a miscible agent such as a solvent and/or a gas such as carbon dioxide, may be used to increase the flow of oil and/or gas from the formation. In some embodiments, suitable miscible enhanced oil recovery agents include carbon disulfide, hydrogen sulfide, carbon dioxide, octane, pentane, LPG, C2-C6 aliphatic hydrocarbons, nitrogen, diesel, mineral spirits, napthsteam, asphalt solvent, kerosene, acetone, xylene, trichloroethane, or mixtures of two or more of the preceding, or other miscible enhanced oil recovery agents as are known in the art. In some embodiments, suitable miscible enhanced oil recovery agents are first contact miscible or multiple contact miscible with oil in the formation. In some embodiments, suitable immiscible enhanced oil recovery agents include water in gas or liquid form, air, mixtures of two or more of the preceding, or other immiscible enhanced oil recovery agents as are known in the art. In some embodiments, suitable immiscible enhanced oil recovery agents are not first contact miscible or multiple contact miscible with oil in the formation.
In some embodiments, immiscible and/or miscible enhanced oil recovery agents injected into the formation may be recovered from the produced oil and/or gas and re-injected into the formation.
In some embodiments, oil as present in the formation prior to the injection of any enhanced oil recovery agents has a viscosity of at least about 100 centipoise, or at least about 500 centipoise, or at least about 1000 centipoise, or at least about 2000 centipoise, or at least about 5000 centipoise, or at least about 10,000 centipoise. In some embodiments, oil as present in the formation prior to the injection of any enhanced oil recovery agents has a viscosity of up to about 5,000,000 centipoise, or up to about 2,000,000 centipoise, or up to about 1,000,000 centipoise, or up to about 500,000 centipoise.
Releasing at least a portion of the enhanced oil recovery agent and/or other liquids and/or gases may be accomplished by any known method. One suitable method is injecting steam into a single conduit in a single well, allowing the steam to soak, and then pumping out at least a portion of the steam with gas and/or liquids. Another suitable method is injecting the steam into a first well, and pumping out at least a portion of the steam with gas and/or liquids through a second well. The selection of the method used to inject at least a portion of the steam and/or other liquids and/or gases is not critical.
In some embodiments, the steam and/or other liquids and/or gases may be pumped into a formation at a pressure up to the fracture pressure of the formation.
In some embodiments, water may be heated prior to being injected into the formation to lower the viscosity of fluids in the formation, for example heavy oils, paraffins, asphaltenes, etc.
In some embodiments, water may be heated and/or boiled while within the formation, with the use of a heated fluid or a heater, to lower the viscosity of fluids in the formation. In some embodiments, water may be heated and/or boiled while within the formation, with the use of a heater. One suitable heater is disclosed in copending United States Patent Application having Ser. No. 10/693,816, filed on Oct. 24, 2003, and having attorney docket number TH2557. United States Patent Application having Ser. No. 10/693,816 is herein incorporated by reference in its entirety.
In some embodiments, steam may be pumped into a formation below the fracture pressure of the formation, for example from about 40% to about 90% of the fracture pressure.
In some embodiments, a quantity of steam or steam mixed with other components may be injected into a well, followed by another component to force steam or steam mixed with other components across the formation, for example air; water in gas or liquid form; water mixed with one or more salts, polymers, and/or surfactants; carbon dioxide; other gases; other liquids; and/or mixtures thereof.

Illustrative Embodiments

In one embodiment, there is disclosed a method for producing oil from an underground formation comprising providing a first well in the formation, the first well comprising a plurality of sections along a length of the well; providing a second well in the formation; injecting an enhanced oil recovery formulation into at least a first section and a second section of the first well and into the formation; forcing the formulation and/or oil towards the second well in the formation; producing the formulation and/or oil from the second well; and then stopping the injecting into the second section, while continuing the injecting into the first section.
In some embodiments, the first well further comprises a first array of wells, and the second well further comprises a second array of wells, wherein a well in the first array of wells is at a distance of 5 meters to 100 meters from one or more adjacent wells in the second array of wells. In some embodiments, the first well comprises from about 3 to about 20 sections along the length of the first well. In some embodiments, the enhanced oil recovery formulation comprises steam. In some embodiments, stopping the injecting into the second section comprises turning off a valve in the second section. In some embodiments, the second well comprises a plurality of sections along a length of the well. In some embodiments, the first well comprises an array of wells of 5 to 500 wells, and the second well comprises an array of wells of 5 to 500 wells. In some embodiments, producing the formulation and/or oil mixture from the second well comprises producing from a first section and from a second section of the second well; and then stopping the production into the second section, while continuing the production into the first section. In some embodiments, the underground formation comprises an oil having a viscosity from 100 to 5,000,000 centipoise. In some embodiments, the method also includes converting at least a portion of the recovered oil into a material selected from the group consisting of transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers. In some embodiments, the steam is injected at a pressure from 0 to 37,000 kilopascals above the initial reservoir pressure, measured prior to when the injection begins. In some embodiments, the underground formation comprises a permeability from 0.0001 to 15 Darcies, for example a permeability from 0.001 to 1 Darcy. In some embodiments, any oil, as present in the underground formation prior to the injecting the formulation, has a viscosity from 5000 to 2,000,000 centipoise, for example from 10,000 to 500,000 centipoise. In some embodiments, the method also includes sensing at least one of a pressure and a temperature at the first section and the second section of the first well. In some embodiments, the method also includes sensing at least one of a pressure and a temperature at a first section and a second section of the second well.
Those of skill in the art will appreciate that many modifications and variations are possible in terms of the disclosed embodiments of the invention, configurations, materials and methods without departing from their spirit and scope. Accordingly, the scope of the claims appended hereafter and their functional equivalents should not be limited by particular embodiments described and illustrated herein, as these are merely exemplary in nature.

Claims

1. A method for producing oil from an underground formation comprising:

providing a first well in the formation, the first well comprising a plurality of sections along a length of the well;

providing a second well in the formation;

injecting an enhanced oil recovery formulation into at least a first section and a second section of the first well and into the formation;

producing the formulation and/or oil from the second well; and

then modifying the injecting into the second section, while continuing the injecting into the first section.

2. The method of claim 1, wherein the first well further comprises a first array of wells, and the second well further comprises a second array of wells, wherein a well in the first array of wells is at a distance of 5 meters to 200 meters from one or more adjacent wells in the second array of wells.

3. The method of claim 1, wherein the first well comprises from about 3 to about 20 sections along the length of the first well.

4. The method of claim 1, wherein the enhanced oil recovery formulation comprises steam.

5. The method of claim 1, wherein modifying the injecting into the second section comprises actuating a valve in the second section.

6. The method of claim 1, wherein the second well comprises a plurality of sections along a length of the well.

7. The method of claim 1, wherein the first well comprises an array of wells of 5 to 500 wells, and the second well comprises an array of wells of 5 to 500 wells.

8. The method of claim 6, wherein producing the formulation and/or oil mixture from the second well comprises producing from a first section and from a second section of the second well; and

then modifying the production into the second section, while continuing the production into the first section.

9. The method of claim 1, wherein the underground formation comprises an oil having a viscosity from 100 to 5,000,000 centipoise.

10. The method of claim 9, further comprising converting at least a portion of the recovered oil into a material selected from the group consisting of transportation fuels such as gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers.

11. The method of claim 4, wherein the steam is injected at a pressure from 0 to 37,000 kilopascals above the initial reservoir pressure, measured prior to when the injection begins.

12. The method of claim 1, wherein the underground formation comprises a permeability from 0.0001 to 15 Darcies.

13. The method of claim 1, wherein any oil, as present in the underground formation prior to the injecting the formulation, has a viscosity from 5000 to 2,000,000 centipoise.

14. The method of claim 1, further comprising sensing at least one of a pressure and a temperature at the first section and the second section of the first well.

15. The method of claim 1, further comprising sensing at least one of a pressure and a temperature at a first section and a second section of the second well.

16. The method of claim 1, wherein the second well comprises a plurality of sections along a length of the well;

further comprising modifying the production into a first plurality of sections of the second well, while continuing the production into a second plurality of sections of the second well.

17. The method of claim 1, further comprising modifying the injecting into a first plurality of sections of the first well, while continuing the injecting into a second plurality of sections of the first well.