WO2014183032A2

WO2014183032A2 - Top-down oil recovery

Info

Publication number: WO2014183032A2
Application number: PCT/US2014/037492
Authority: WO
Inventors: Tawfik N. Nasr; David A. Brown
Original assignee: Conocophillips Company
Priority date: 2013-05-09
Filing date: 2014-05-09
Publication date: 2014-11-13
Also published as: WO2014183032A3; US20140332210A1

Abstract

Methods relate to producing hydrocarbons, such as bitumen in an oil sands reservoir. The methods include utilizing an injector well with multiple horizontal laterals to provide downward fluid drive toward a producer well. Combined influence of gravity and a dispersed area of the fluid drive due to the laterals facilitate a desired full sweep of the reservoir. Fluids utilized for injection include water heated to less than 60 weight percent steam, solvent for the hydrocarbons and emulsifying agent for the hydrocarbons. The methods employing these fluids provide energy efficient recovery of the hydrocarbons.

Description

TOP-DOWN OIL RECOVERY

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application is a non-provisional application which claims benefit under 35 USC § 119(e) to U.S. Provisional Application Ser. No. 61/821,489 filed May 9, 2013, entitled " TOP-DOWN OIL RECOVERY," which is incorporated herein in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH

[0002] None.

FIELD OF THE INVENTION

[0003] Embodiments of the invention relate generally to methods for recovering oil utilizing wellbore configurations and an injection fluid for downward drive of the oil toward a production well.

BACKGROUND OF THE INVENTION

[0004] Several techniques utilized to recover hydrocarbons in the form of bitumen from oil sands rely on generated steam to heat and lower viscosity of the hydrocarbons when the steam is injected into the oil sands. One common approach for this type of recovery includes steam assisted gravity drainage (SAGD). The hydrocarbons once heated become mobile enough for production along with the condensed steam, which is then recovered and recycled.

[0005] However, excessive heat loss to surrounding formations renders such thermal processes ineffective and uneconomical in thin zones. Adding solvent to the steam in the SAGD process provides some benefit to lower a steam to oil ratio. Rate of energy use requirements and heat loss to the surrounding formations still makes recovery in thin zones challenging.

[0006] Alternative approaches inject various fluids, such as hot solvents, to drive the hydrocarbons toward a production well. These prior fluid drive techniques often require volumes of expensive solvents higher than can be justified. Further problems include premature breakthrough of the fluid at the production well due to channeling through a limited area of the formation rather than a desired full sweep across the formation. [0007] Therefore, a need exists for methods of recovering hydrocarbons with limited and efficient energy use per quantity of hydrocarbon production.

BRIEF SUMMARY OF THE DISCLOSURE

[0008] In one embodiment, a method of producing hydrocarbons includes forming a multilateral horizontal injector well in a hydrocarbon-bearing formation with a horizontal length closer to an overburden upper boundary of the hydrocarbon-bearing formation than a lower boundary of the hydrocarbon-bearing formation and forming a horizontal producer well in the hydrocarbon-bearing formation below at least part of the injector well. Heating the hydrocarbon-bearing formation without fluid transfer between the injector and producer wells establishes fluid communication between the injector and producer wells. Next, water heated to less than 60 weight percent steam, solvent for the hydrocarbons and emulsifying agent for the hydrocarbons passes through the injector well and into the hydrocarbon-bearing formation. Producing the hydrocarbons recovered at the producer well by displacement results from combined forces of gravity and a pressure differential maintained between the injector and producer wells that provides a dispersed fluid drive due to the injector well being multilateral.

[0009] For one embodiment, a method of producing hydrocarbons includes forming a multilateral horizontal injector well in a hydrocarbon-bearing formation with a horizontal length within three meters of an upper boundary of the hydrocarbon-bearing formation and forming a horizontal producer well in the hydrocarbon-bearing formation and extending in a horizontal direction within ten meters of the injector well and three meters of a lower boundary of the hydrocarbon-bearing formation. Water heated to less than 60 weight percent steam, solvent for the hydrocarbons and emulsifying agent for the hydrocarbons passes through the injector well and into the hydrocarbon-bearing formation. Producing the hydrocarbons recovered at the producer well by displacement results from combined forces of gravity and a pressure differential maintained between the injector and producer wells that provides a dispersed fluid drive due to the injector well being multilateral. BRIEF DESCRIPTION OF THE DRAWINGS

[0010] A more complete understanding of the present invention and benefits thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings in which:

[0011] Figure 1 is a schematic of a pay zone with an upper horizontal injection well having laterals and a lower horizontal production well, according to one embodiment of the invention.

[0012] Figure 2 is a schematic view of the injection well taken across line 2-2 in Figure 1 , according to one embodiment of the invention.

[0013] Figure 3 is a graph of cumulative energy injected versus cumulative oil produced via a simulated recovery process utilizing an arrangement as shown in Figure 1 and an injection fluid of wet steam, solvent and an emulsifying agent, according to one embodiment of the invention.

[0014] Figure 4 is a graph of time versus energy intensity calculated for the simulated recovery process, according to one embodiment of the invention.

DETAILED DESCRIPTION

[0015] Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow.

[0016] Embodiments of the invention relate to methods of producing hydrocarbons, such as bitumen in an oil sands reservoir. The methods include utilizing an injector well with multiple horizontal laterals to provide downward fluid drive toward a producer well. Combined influence of gravity and a dispersed area of the fluid drive due to the laterals facilitate a desired full sweep of the reservoir. Fluids utilized for injection include water heated to less than 60 weight percent steam, solvent for the hydrocarbons and emulsifying agent for the hydrocarbons. The methods employing these fluids provide energy efficient recovery of the hydrocarbons.

[0017] As used herein, the solvent refers to a fluid that can dilute heavy oil and/or bitumen. Examples of suitable candidates for non-aqueous fluids that may satisfy the selection criteria include CI to C30 hydrocarbons, and combinations thereof. Some embodiments utilize condensing solvents or solvents that are liquid under reservoir conditions including C4 to C30 hydrocarbons, or combinations thereof. Examples of suitable solvents include, without limitation, gases, such as CO or C0₂ alone or within mixtures like flue gas, alkanes such as methane, ethane, propane, butane, pentane, hexane, heptane, octane, nonane, decane, aromatics such as toluene and xylene, as well as various available hydrocarbon fractions, such as condensate, gasoline, naphtha, diluent and combinations thereof.

[0018] The emulsifying agent referenced herein includes any compound capable of forming an emulsion or other reduced viscosity mixture with the hydrocarbons relative to the hydrocarbons alone and that is stable under reservoir conditions, including thermally and chemically stable surfactants, non-ionic, anionic, cationic, amphoteric or zwitterionic surfactants, alkine metal carbonate or an alkaline metal hydroxide, aromatic sulfonates, alkyl benzyl sulfonates, olefin sulfonates, alkyl aryl sulfonates, alkoxy sulfates, alkaline metal carbonates, alkaline metal bicarbonates, alkaline metal hydroxides, sodium carbonate, sodium bicarbonate, sodium hydroxide, potassium carbonate, potassium bicarbonate, potassium hydroxide, magnesium carbonate and calcium carbonate. Oil soluble surfactants which could be used include sorbitan fatty acid esters, saponified hard oils, saponified hydrogenated fatty acid oils, long chain fatty amines, long chain sulfates, long chain sulfonates, phospholipids, lignins, poly ethylene glycol mono-oleates, alkanolamide based surfactants, any other oil soluble surfactants and any combinations thereof.

[0019] Embodiments described herein utilize the water heated in a furnace, heat exchanger or other steam generators including direct steam generators to increase temperature of the water for injection at between 50° and 250° C or between 75° and 150° C. While the water may be heated up to, or below, a boiling point for the water at a pressure desired for injection without generating any steam, some embodiments inject low quality or wet steam when introduced into the well for injection into the reservoir. Such wet steam may contain less than 60 weight percent steam or less than 50 weight percent steam, with a remainder of the water being in liquid phase. [0020] For comparison, conventional steam assisted gravity drainage relies on higher quality steam (e.g., at least 95 weight percent steam) to form and rise into a steam chamber before condensing upon contact with the hydrocarbons in the reservoir. The water heated to less than 60 weight percent steam limits amount of energy needed since less than half the energy is needed relative to making pure steam and also limits energy loss. Such energy loss can result from the steam transferring heat to an overburden rather than the hydrocarbons in the reservoir.

[0021] Figure 1 depicts a hydrocarbon-bearing formation 100 bounded by an overburden upper layer 102 and a lower layer 104. The upper and lower layers 102, 104 may include shale or other less permeable geologic strata than the formation 100, which forms a reservoir pay zone. While not limited to any particular thickness of the formation 100, embodiments of the invention may provide economic recovery even with distances separating the upper and lower layers 102, 104 of less than 20 meters, less than 15 meters or less than 10 meters.

[0022] An upper horizontal injector well 108 having laterals 110 extends through the formation 100 above a lower horizontal producer well 106. Location of the injector well 108 in the formation 100 disposes a horizontal length of the injector well 108 with the laterals 110 closer to the upper layer 102 than the lower layer 104. In some embodiments, the injector well 108 only extends into a top quarter of the formation 100 with the producer well 106 extending to have a horizontal bore in a bottom quarter of the formation 100. For example, forming the injector well 108 may place a horizontal length of the injector well 108 within three meters of the upper layer 102 (e.g., one meter from the upper layer 102) and ten meters of the producer well 106 extending in a horizontal direction within three meters of the lower layer 104.

[0023] For some embodiments, the horizontal bore of the producer well 106 aligns in a vertical direction below a main bore of the injector well 108 from which the laterals 110 branch outward. The producer well 106 may also include horizontal multilaterals like the injector well 108. Any portion of the injector well 108 may cover part of the producer well 106 regardless of orientation, location or configuration of the producer well 106 relative to the injector well 108 in order to achieve desired fluid drive infrastructure. [0024] Figure 2 shows a top view of the injector well 108 taken across line 2-2 in Figure 1. In some embodiments, the injector well 108 may include at least two of the laterals 110 on each side of the main bore along the horizontal length of the injector well 108 and in a common plane with the main bore. The plane formed by all eight of the laterals 110 depicted in Figure 2 thus runs substantially parallel in proximity with the upper layer 102.

[0025] In operation, a preheating stage establishes fluid communication between the injector and producer wells 108, 106. Initial viscosity of the hydrocarbons in the formation 100 prevents such fluid transfer between the injector and producer wells 106, 108 until after the preheating stage. The preheating stage may take at least one week, at least one month, or at least six months to establish this fluid communication depending upon properties of the formation 100 and techniques utilized to introduce the heat. These techniques for the preheating stage include at least one of electric resistive heating, radio frequency heating, electromagnetic heating and steam circulation with steam injection and production occurring in a same one of the injector and producer wells 108, 106 even though one or both may be used for such steam circulation.

[0026] After the preheating stage, the water that is heated, the solvent and the emulsifying agent flow through the injector well 108 and pass from the laterals 110 into the formation 100. In some embodiments, these fluids form a mixture for injection together whether continuous or intermittent. Exemplary suitable alternative injection strategies may include injecting either or both the solvent and the emulsifying agent intermittently or sequentially, such as when the water that is heated is injected at intermittent intervals between when the solvent and the emulsifying agent are injected.

[0027] Volume fractions of the water, the solvent and the emulsifying agent may vary for particular properties of the formation 100. In some embodiments, the water makes up at least 90 volume percent or at least 95 volume percent of a combined quantity of the water and solvent injected. Adjusting total fluid injection rate of the water, the solvent and the emulsifying agent maintains a constant injection bottom-hole pressure in some embodiments.

[0028] The emulsifying agent creates an oil-in-water emulsion with relative lower viscosity than the hydrocarbons alone. The solvent also lowers the viscosity of the hydrocarbons by dilution into the hydrocarbons. Heat transfer from the water to the hydrocarbons further works in synergy with the solvent in reducing the viscosity of the hydrocarbons.

[0029] In some embodiments, a pressure differential of at least 15-20 kilopascals per meter of well separation maintained between the injector well 108 and the producer well 106 facilitates fluid drive of the hydrocarbons in the formation 100. A combined influence of gravity and the fluid drive with the laterals 110 used for the injection creates a piston- like force directing the hydrocarbons towards the producer well 106 to facilitate a uniform and complete sweep of the formation 100 while limiting injected fluid flow channeling. For example, gravity provides a driving force of 9.8 kilopascals per meter that combines with 15-20 kilopascals per meter when a differential pressure of 90-120 kilopascals is maintained between the injector well 108 and the producer well 106 if separated by 6 meters.

[0030] The following examples of certain embodiments of the invention are given. Each example is provided by way of explanation of the invention, one of many embodiments of the invention, and the following examples should not be read to limit, or define, the scope of the invention.

[0031] An evaluation of the processes described herein was carried out using a numerical simulator (STARS by CMG) and based on a configuration as shown in Figures 1 and 2. Hexane and sodium hydroxide provided the solvent and the emulsifying agent, respectively. The evaluation utilized an Athabasca oil sands reservoir of 120 meters in width by 8 meters in height and 500 meters in length.

[0032] With reference to Figures 1 and 2, the producer well 106 extended in a horizontal direction 500 meters in length 1 meter above the lower layer 104. The injector well 108 included a total of eight of the laterals 110 with four each per side of the main bore and each extending 60 meters in length while being separated from one another by 100 meters along the main bore. A distance of 6 meters in a vertical direction separated the main bore of the injector well 108 from the horizontal bore of the producer well 106.

[0033] The preheating stage lasted for six months to establish the fluid communication before initiating top-down displacement, as described herein. During injection after the preheating stage, the water made up 95 volume percent of a combined quantity of the water and solvent injected as a mixture with the emulsifying agent. Total fluid injection rate adjustments maintained the bottom-hole pressure at 3.4 megapascals. A pressure differential between the injector and producer wells of 140 kilopascals, above the hydrostatic head between the wells, contributed to the driving force with gravity.

[0034] A steam-only case used all like parameters except that only steam, in which quality was 95 weight percent steam, was used for injection without the solvent and the emulsifying agent. Energy content of the steam in this steam-only case was about twice as much relative to the mixture. Although the steam-only case does not compare prior art methods to embodiments of the invention, the steam-only case in comparison with use of the mixture provides a baseline for putting energy efficiency into context. The comparison also shows unexpected results in that the mixture still enabled desired cumulative production quantities even with such limited energy input and also in that these improvements indicate that using water or wet steam with less energy provides superior results than co-injecting additives, such as the solvent, with relative higher energy steam where only 30-35% improvements in steam-to-oil ratios are expected.

[0035] Figure 3 illustrates a graph of cumulative energy injected versus cumulative oil produced as determined in the evaluation. The graph shows increase in oil production from the same amount of energy injected using the mixture (represented by curve 300) as compared to the steam-only case (represented by curve 302). After injection of about 1.5 million Giga Joules of energy, an increase in oil production of about 56% was obtained with the mixture 300 relative to the steam-only case 302. To produce an equal 50,000 cubic meters of oil using either the mixture 300 or the steam-only case 302, the amount of energy required with the mixture 300 was only 0.6 million Giga Joules, which amounts to more than 50% savings in energy, compared to about 1.5 million Giga Joules for the steam-only case 302.

[0036] Figure 4 shows a graph of time versus energy intensity calculated for the simulated recovery process. The graph shows that utilizing the mixture (represented by curve 400) lowers the energy intensity as compared to the steam-only case (represented by curve 402). By the end of 7 years of injection, the energy intensity with use of the mixture 400 was 2.6 as compared to 5.2 for the steam-only case 402, which difference represents a reduction of 50%>. [0037] In closing, it should be noted that the discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. At the same time, each and every claim below is hereby incorporated into this detailed description or specification as additional embodiments of the present invention.

[0038] Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the invention as defined by the following claims. Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein. It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents.

Claims

1. A method of producing hydrocarbons, comprising:

forming a multilateral horizontal injector well in a hydrocarbon-bearing formation with a horizontal length closer to an overburden upper boundary of the hydrocarbon- bearing formation than a lower boundary of the hydrocarbon-bearing formation;

forming a horizontal producer well in the hydrocarbon-bearing formation below at least part of the injector well;

heating the hydrocarbon-bearing formation without fluid transfer between the injector and producer wells to establish fluid communication between the injector and producer wells;

introducing water heated to less than 60 weight percent steam, solvent for the hydrocarbons and emulsifying agent for the hydrocarbons through the injector well and into the hydrocarbon-bearing formation; and

producing the hydrocarbons recovered at the producer well by displacement resulting from combined forces of gravity and a pressure differential maintained between the injector and producer wells that provides a dispersed fluid drive due to the injector well being multilateral.

2. A method of producing hydrocarbons, comprising:

forming a multilateral horizontal injector well in a hydrocarbon-bearing formation with a horizontal length within three meters of an upper boundary of the hydrocarbon- bearing formation;

forming a horizontal producer well in the hydrocarbon-bearing formation and extending in a horizontal direction within ten meters of the injector well and three meters of a lower boundary of the hydrocarbon-bearing formation;

3. The method according to one of claims 1 or 2, wherein the injector well includes at least two laterals on each side of a main bore along the horizontal length of the injector well and in a common plane with the main bore.

4. The method according to one of claims 1, 2, or 3, wherein the injector well includes at least four laterals in a common plane with the horizontal length of the injector well.

5. The method according to one of claims 1 through 4, wherein the pressure differential is at least 15-20 kilopascals per meter of separation between the injector and producer wells.

6. The method according to one of claims 1 through 5, wherein the solvent includes hydrocarbons with between 1 and 30 carbon atoms per molecule.

7. The method according to one of claims 1 through 6, wherein the emulsifying agent is a thermally and chemically stable surfactant at reservoir conditions.

8. The method according to one of claims 1 through 7, wherein the emulsifying agent is selected from the group consisting of aromatic sulfonates, alkyl benzyl sulfonates, olefin sulfonates, alkyl aryl sulfonates, alkoxy sulfates, alkaline metal carbonates, alkaline metal bicarbonates and alkaline metal hydroxides.

9. The method according to one of claims 1 through 8, wherein the emulsifying agent includes sodium hydroxide.

10. The method according to one of claims 1 through 9, wherein the solvent includes hydrocarbons with between 4 and 30 carbon atoms per molecule and the emulsifying agent is sodium hydroxide.

11. The method according to one of claims 1 through 10, wherein the injector well is disposed in a top quarter of the hydrocarbon-bearing formation and the producer well is disposed in a bottom quarter of the hydrocarbon-bearing formation.

12. The method according to one of claims 1 through 11, wherein the heating to establish fluid communication between the injector and producer wells includes at least one of electric resistive heating, radio frequency heating, electromagnetic heating and steam circulation with steam injection and production occurring in a same one of the injector and producer wells.

13. The method according to one of claims 1 through 12, wherein the water makes up at least 90 volume percent of a combined quantity of the water and solvent injected.

14. The method according to one of claims 1 through 13, wherein the producer well includes horizontal multilaterals.

15. The method according to one of claims 1 through 14, wherein the water, the solvent and the emulsifying agent are injected together as a mixture.

16. The method according to one of claims 1 through 15, wherein the water is injected at intermittent intervals between when the solvent and the emulsifying agent are injected.

17. The method according to one of claims 1 through 16, wherein the solvent is a hydrocarbon that is liquid under reservoir conditions.

18. The method according to one of claims 1 through 17, wherein a horizontal bore of the producer well aligns in a vertical direction below a main horizontal bore of the injector well.

19. The method according to one of claims 1 through 18, wherein the producer well includes horizontal multilaterals.