Well configuration for coinjection

Abstract

A well configuration for co-injection processes, wherein a horizontal producer well at the bottom of the pay is combined with injection or injection and producer wells that are vertical and above the lower horizontal production well. This well arrangement minimizes “blanket” effects by non-condensable gases.

Claims

1. A method of heavy oil production, said method comprising: a) providing a horizontal production well at a bottom of a heavy oil payzone; b) providing a plurality of vertical injector wells and a plurality of vertical producer wells along said horizontal production well and terminating directly above said horizontal production well; c) injecting steam into said injector wells and said vertical producer wells in a start-up period until fluid communication is established; d) injecting steam and non-condensable solvent (NCS) only into said injector wells to mobilize heavy oil; and e) producing said mobilized heavy oil and condensed steam from said horizontal producer well and simultaneously producing said NCS from said vertical producer wells.

2. The method of claim 1, wherein said steam and said NCS for step d) are produced for said method using a direct steam generator (DSG).

3. The method of claim 1, wherein steam is injected in step d) at a first depth that is higher than a second depth from which said NCS is produced in step e).

4. The method of claim 1, wherein steam is first injected in step d) at a first depth and later in step d) injected at a second depth that is higher than said first depth and higher than a third depth from which said NCS is produced in step e).

5. The method of claim 1, wherein more of said mobilized heavy oil is produced per day than a method using only a horizontal wellpair.

6. The method of claim 1, wherein a said startup period is reduced as compared with a method using only a horizontal wellpair.

7. The method of claim 1, wherein said produced NCS is recycled for use in step d of said method.

8. The method of claim 1, wherein said NCS comprises N.sub.2 or CO.sub.2.

9. The method of claim 1, wherein said vertical injector wells are fitted with active flow control devices, and wherein steam in step c) is injected at a first depth and in step d) is injected at a second depth that is higher than said first depth and higher than a third depth from which said NCS is produced in step e).

10. A method of heavy oil production, said method comprising: a. producing steam and CO.sub.2 with a direct steam generator (DSG); b. injecting said steam and said CO.sub.2 into a plurality of vertical injection wells, the plurality of vertical injection wells each along and terminating directly above a horizontal producer well; c. collecting mobilized heavy oil and water from said horizontal production well; d. collecting said CO.sub.2 from a plurality of vertical production wells, the plurality of vertical production wells each along and terminating directly above said horizontal producer well; and e. recycling said collected CO.sub.2 in step b.

11. The method of claim 10, wherein said steam is injected at a first depth that is higher than a second depth from which said CO.sub.2 is collected produced.

12. The method of claim 10, wherein said steam is first injected at a first depth and later injected at a second depth that is higher than said first depth and higher than a third depth from which said CO.sub.2 is collected.

13. The method of claim 10, wherein said vertical injection wells alternate with said vertical production wells.

14. A method of producing heavy oil from a reservoir, said method comprising: a. providing a horizontal production well at a bottom of a heavy oil payzone, plus a plurality of vertical injector wells and a plurality of vertical producer wells along said horizontal production well and terminating directly above said horizontal production well; b. injecting steam into said vertical injector wells and said vertical producer wells until fluid communication is established; c. injecting steam and non-condensable solvent (NCS) into said vertical injector wells to mobilize said heavy oil; and d. producing said mobilized heavy oil and condensed steam from said horizontal producer well and simultaneously producing said NCS from said vertical producer wells.

15. The method of claim 14, wherein said NCS is N.sub.2 or CO.sub.2.

16. The method of claim 14, wherein said vertical injector wells are fitted with active flow control devices, and wherein said steam in step b) is injected at a first depth and is injected in step c) at a second depth that is higher than said first depth and higher than a third depth from which said NCS is produced in step d).

17. The method of claim 14, wherein said NCS from step d) is recycled for use in step c) of said method.

18. An improved method of heavy oil production using a direct steam generator (DSG), said method comprising injecting steam and CO.sub.2 from said a DSG into a horizontal injection well of a horizontal wellpair and collecting mobilized heavy oil, CO.sub.2 and water from a horizontal production well of said horizontal wellpair, the improvement comprising: injecting said steam and said CO.sub.2 from said DSG into a plurality of vertical injection wells, the plurality of vertical injection wells each along and terminating directly above a horizontal producer well, collecting mobilized heavy oil and water from said horizontal producer well, and collecting said CO.sub.2 from a plurality of vertical production wells, the plurality of vertical production wells each along and terminating directly above said horizontal producer well, wherein the vertical injection wells alternate with the vertical production wells, and wherein more of said mobilized heavy oil is produced per day than a method using only said horizontal wellpair.

19. The method of claim 18, wherein said steam is injected at a first depth that is higher than a second depth from which said CO.sub.2 is collected.

20. The method of claim 18, wherein said steam is first injected at a first depth and later injected at a second depth that is higher than said first depth and higher than a third depth from which said CO.sub.2 is collected.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) The application file contains at least one drawing executed in color. Copies of this patent application publication with color drawing(s) will be provided by the Office upon request and payment of the necessary fee.

(2) FIG. 1 shows a conventional SAGD well pair.

(3) FIG. 2 shows a typical VAPEX process.

(4) FIG. 3 shows an ES-SAGD process that can be used in the invention.

(5) FIG. 4A shows cumulative bitumen production for SAGD versus ES-SAGD (from Gates 2010).

(6) FIG. 4B shows cumulative steam usage, which is substantially decreased (from Gates 2010).

(7) FIG. 5A depicts a side view of a horizontal producer with vertical injectors and producers. FIG. 5 B is a 3D simulation volume with a quarter vertical injector, quarter vertical producer and half a horizontal producer.

(8) FIG. 6 shows an oil production rate comparison.

(9) FIG. 7 shows a CSOR comparison.

(10) FIG. 8 shows an oil recovery comparison.

(11) FIG. 9A (VH_DSG case) depicts performance of the DSG process with the new well configuration. FIG. 9B (DSG control case) depicts performance of a conventional DSG process. VH_DSG case and DSG control case oil saturation (left) and temperature (C.°) (right) distributions depicted are after 3 years of simulated operation.

(12) FIG. 10 shows a simulation model in CMG® STARS.

(13) FIG. 11 shows an oil production rate comparison.

(14) FIG. 12 shows a CSOR comparison.

(15) FIG. 13 shows an oil recovery comparison.

(16) FIG. 14A shows an array of horizontal producers; FIG. 14B shows a radial array of horizontal wells; FIG. 14C shows a horizontal well with branches with the base well and branches each having injectors and producers; and FIG. 14D shows combination radial with branches. Note: wells are not drawn to scale, and right angles are for ease of drawing only.

(17) FIG. 15 shows another well configuration wherein vertical producers (or injectors) are offset to sit between a pair of horizontal producers, thus servicing both wells. This arrangement can be applied to any of the configurations in FIG. 14A, FIG. 14B, FIG. 14C, or FIG. 14D.

DETAILED DESCRIPTION

(18) This disclosure relates to methods, systems and well configurations that avoid gas blanket problems and allow co-injection processes to be used more effectively, especially with DSG steam generation methods. Generally speaking the method uses horizontal production wells with vertical injectors and vertical producers to improve steam-solvent co-injection processes.

(19) Any solvent-steam co-injection process or variant thereon can be used in the method, although we have exemplified herein the process using DSG generated steam-CO.sub.2 co-injection.

(20) In addition to CO.sub.2, solvents used in steam-solvent co-injection processes can include non-condensable gases, light solvents, medium solvents, and combinations thereof. Solvents include at least CH.sub.4, CO, N.sub.2, H.sub.2, ethane, propane, butane, pentane, hexane, up to C12, or more, flue gas, and the like. Inert gases have also been used for injection. Medium weight solvents (i.e., naphtha) gave the best results in the total oil production at a somewhat greater solvent loss, and light solvents and CO.sub.2 are thus preferred.

(21) Solvent to steam levels are typically about 5-20%, but since the solvent is being removed from the steam from via vertical producers, it may be possible to use higher amounts.

(22) Nevertheless, the typical amount of CO.sub.2 co-injected from a DSG will be a function of the efficiency of the generator, and is usually about 10% by mass, but can also vary with generator design and the fuel used. These factors will also affect the solvent profile of the co-injected solvents.

(23) The novel well configurations were modeled using the commercial CMG® STARS reservoir modeling package. The simulation results show that the new well configuration significantly improves oil production at comparable CSOR over the control case of the traditional well configuration for DSG applications. It is also demonstrated in simulation that the proposed well configuration allows flexible injection/production designs and operation to optimize reservoir performance.

(24) Direct steam generation based steam-CO.sub.2 co-injection is a preferred method. DSG is an attractive steam generation technology and its advantages include significant reduction in facility footprint, higher energy efficiency of steam generation, reduction in water consumption (10% make-up water comes from combustion products), and being CO.sub.2 capture ready.

(25) Any DSG and co-injection process can be used herewith. U.S. Pat. No. 8,079,417, for example, relates to devices and methods for deploying steam generators and pumps in connection with steam injection operations. U.S. Pat. No. 8,353,342 relates to methods and systems that include both generating steam for injection into a wellbore and capturing CO.sub.2 produced when generating the steam. U.S. Pat. No. 8,353,343 limits the amount of non-condensable gases in the mixture that may promote dissolving of the CO.sub.2 into the hydrocarbons upon contact of the mixture with the hydrocarbons. U.S. Pat. No. 8,602,103 supplies water and then solvent for hydrocarbons in direct contact with combustion of fuel and oxidant to generate a stream suitable for injection into the reservoir in order to achieve thermal and solvent based recovery. U.S. Pat. No. 8,656,999 describes combustible water impurities in the water, which are then combusted inside a chamber in the direct steam generator and the solid particles are removed from the effluent stream to produce a treated stream. US20120073810 relates to recovery of in situ upgraded hydrocarbons by injecting steam and hydrogen into a reservoir containing the hydrocarbons. US20120227964 relates to methods and systems for processing flue gas from oxy-fuel combustion. US20130068458 relates to installation and configuration of heat exchanger on wellpads for SAGD production process, so as to recover heat from produced fluids at SAGD wellpads to preheat feedwater for wellpad steam generation. US20130333884 includes a CO.sub.2 and steam co-injection well placed at a bottom of a reservoir some horizontal distance from a producer, such that the injection well and producer may both be in a common horizontal plane. US20140060825 provides methods and systems to generate steam and carbon dioxide mixtures suitable for injection to assist in recovering hydrocarbons from oil sands based on concentration of the carbon dioxide in the mixtures as influenced by temperature of water introduced into a direct steam generator. US20140110109 relates to systems and methods of generating steam from produced water by passing the produced water through first and second steam generators coupled together. US20140231081 describes systems and methods of recovering hydrocarbons by injecting into a reservoir outputs from two different types of steam generators along with carbon dioxide.

PRIOR ART WELL CONFIGURATION

(26) The DSG device generates pressurized high temperature steam mixed with effluent gases (mainly CO.sub.2, about 10 wt %) from the direct combustion of natural gas and oxygen in the presence of water, and the outlet stream of steam and effluent gases is injected directly into the reservoir. In DSG use with the conventional horizontal wellpair configuration (FIG. 1), a steam chamber forms and develops vertically and laterally, and mobilized bitumen drains along the chamber boundary under the gravity towards the production well in a manner similar to the SAGD process. The co-injected CO.sub.2 helps reduce bitumen viscosity by dissolution of CO.sub.2 into bitumen and mitigate heat loss to overburden by gas accumulation in the upper portion of the steam chamber.

(27) The co-injected CO.sub.2, however, also behaves as a NCG under the typical reservoir conditions (e.g., Surmont oil sands) and accumulates ahead of the steam front. This gas accumulation provides an insulating effect that retards the steam chamber development and slows bitumen recovery. Thus, the full benefits of DSG use cannot be realized due to the inhibiting effect of the gas blanket.

NOVEL WELL CONFIGURATION

(28) To overcome the challenges of DSG applications with the conventional horizontal wellpair configuration, we propose herein a new well configuration that combines vertical wells and horizontal wells.

(29) Our previous studies and field experiences indicate that NCG can trigger the gas drive mechanism in the region where bitumen is mobile and pressure gradient exists in between injectors and producers. A “gas drive” is similar to steam drive, used e.g., in steam flooding or cyclic stem stimulations, wherein the gas front pushes mobilized oil toward the producer.

(30) It is also proven that the steam chamber development can be significantly improved by efficiently removing NCG from the steam chamber boundary as it travels to the vertically offset vertical producers, consequently resulting in a higher oil production rate.

(31) In addition, it is believed that avoiding the “re-boiling” of CO.sub.2 dissolved in bitumen when the oil phase of bitumen and CO.sub.2 approaches the injector of high temperature keeps the benefit of the solvent effect of CO.sub.2 that results in bitumen viscosity reduction.

(32) The combination of vertical and horizontal well configuration for DSG applications can take advantage of each of these mechanisms.

(33) A general schematic of the proposed well configuration for DSG applications is shown in FIG. 5A & FIG. 5B. A horizontal producer with length of e.g., 1,000-3000 m or so is placed near the bottom of the payzone in the reservoir. A series of vertical injectors and producers are alternatively located several meters right above the horizontal producer, with a certain well spacing between neighboring vertical wells.

(34) The vertical separation is preferably e.g., 4-25 meters, or 5-10 m, but more or less can be used depending on reservoir permeability, pressure and temperature characteristics. The horizontal separation between the vertical wells can also vary, but typically is e.g., 50-500 meters, or about 100 m, but more or less can be used depending on reservoir permeability, pressure and temperature characteristics, as well as on the overall pattern of wells in an array.

(35) The DSG process starts with a “preheat” or “start-up” phase in which the DSG outlet stream of steam and CO.sub.2 is circulated through the wellbores of all the wells to heat up the regions between wells by heat conduction. After establishing the thermal and fluid communication between wells, the DSG outlet stream is injected into the reservoir only through the vertical injectors, and a series of steam chambers form around the vertical injectors and expand continuously.

(36) The horizontal well is operated under the steam trap control to produce oil and water that are driven by both gravity and pressure drive. The vertical producers function as a vent well to produce the NCG (mainly CO.sub.2) with a minimum of live steam, and thus avoiding the gas accumulation in front of the steam chamber. The recovery process continues until the reservoir is depleted or an economic limit is reached.

SIMULATIONS

(37) To evaluate the performance of the new well configuration for the DSG application, numerical simulations with a 3D homogeneous model were conducted using CMG® STARS.

(38) FIG. 10 shows the simulation model that represents a repeated pattern of a 60 m×60 m×35 m region by symmetry. The model consists of a half horizontal producer of 60 m in length located at the bottom, a quarter vertical injector and a quarter vertical producer with 2 m and 1 m, respectively, right above the horizontal producer. The Surmount average reservoir properties were used in the simulation.

(39) Two simulation cases were considered to compare the performance of the DSG process with the new well configuration (FIG. 9A) and with the conventional horizontal wellpair configuration (FIG. 9B). The simulation results of the two cases were compared in terms of oil production rate, CSOR (cumulative SOR), and oil recovery factor in FIG. 6, 7, FIG. 8, FIG. 9A & FIG. 9B, respectively. “VH_DSG” represents the combined Vertical-Horizontal DSG well configuration.

(40) Note that the spikes of production in FIG. 6 etc. are mainly due to the well constraints (steam trap control) used in the simulation model to limit live steam production. If the production wells produce more live steam than the prescribed limit (usually 1 m<3>/day), the production wells will be choked back to limit the amount of steam rate in simulation. This results in the characteristics series of spikes.

(41) The new well configuration case (VH_DSG) gave a higher oil production rate than the conventional well configuration case (DSG), while CSOR values of the two cases were comparable. The oil recovery in the VH_DSG case was doubled that of the DSG case for the same duration of operation.

(42) FIG. 9 shows the profiles of temperature and the oil saturation after 3 years of simulated operation for both the VH_DSG and DSG cases. As seen in FIG. 9, the steam chamber develops much faster in the VH_DSG case than in the DSG case.

(43) Another advantage of the proposed new well configuration is that it provides greater freedom in well design and operation for optimizing the performance of DSG applications. To illustrate this, a second case of VH_DSG (labeled as VH_DSG opt) was simulated, in which the vertical injection and production depths vary by inflow/outflow control devices.

(44) In this simulation VH-DSG was compared against VH_DSG opt. The VH_DSG opt case otherwise utilizes the same well configuration as VH_DSG, but with active control devices, such as sliding sleeves or interval control valves or passive flow control devices. In the early stage, the steam or steam-gas was injected at lower segment of the vertical wells to accelerate the steam chamber development, while at the later stage, it was desired to inject through the upper segment of the vertical wells to increase gas push, but avoid steam breakthrough to the horizontal producer. For the vertical producer (vent well), opening the well at the lower portion of the well helps pulling the steam/thermal chamber toward to the horizontal producer and hence increasing thermal contact and oil drainage.

(45) After simulated operation of half year, the stream was injected through a certain section of the vertical well and gas was produced at the certain section of the vertical producer.

(46) FIG. 11 showed oil rate improvement by adjusting the injection and production depths, which resulted in a higher recovery factor. The adjustment did not impact the CSOR, shown in FIG. 12. The acceleration of oil production is mainly attributed to two factors. First, the ability to adjust the injection depth allows greater gas push mechanism that helps oil drainage in addition to gravity. Second, as aforementioned, setting the venting segment/well lower helps pull the steam chamber close to the horizontal well and thus enhancing drainage.

(47) Further optimization parameters include, but are not limited to, the vertical well spacing, injection/production depth in different operation stages, timing of switching roles of vertical injector, and vertical producer, etc.

(48) We have shown in FIG. 5A & FIG. 5B a simple single horizontal well with some number of injectors/produced vertically situated along the horizontal well line but somewhat above it. However, the concept can be applied to any array of horizontal producers, such as arrays of parallel producers; producers with multilateral well branches, as in fishbone arrangements; radial well arrangements, which allow one to take advantage of fewer wellpads; radial fishbone well configurations, and the like.

(49) See e.g., FIG. 14A-D. In FIG. 14A, the vertical producers and vertical injectors over adjacent horizontal wells are staggered. FIG. 14B shows a radial array of horizontal wells, each with vertical injectors/producers. In FIG. 14C a horizontal well with branches, the base well and branches each having injectors and producers, and FIG. 14D combines a radial configuration with branches.

(50) FIG. 15 shows yet another well configuration wherein vertical producers (or injectors) are laterally offset to sit between a pair of horizontal producers, thus servicing both wells. This arrangement can be applied to any of the configurations in FIG. 14.

(51) In the above simulations, we had both vertical injectors and vertical producers directly over the horizontal producer. However, it may be possible to laterally offset one or the other, especially the vertical producer, and although modeling has not yet been done, we predict that this may improve efficiencies because a single vertical producer can service two horizontal producers. It may be possible to stagger production wells between adjacent rows of horizontal producers, such that one vertical producer well can service two horizontal producers and four injectors (two from each horizontal producer).

(52) In addition, we have exemplified alternating vertical injectors and producers, but this may be variable, depending on the amounts of solvent co-injected into the reservoir, and on the spacing of the wells.

(53) The following are incorporated by reference herein in their entireties for all purposes: US20100050517 US20110036308 US20110232545 US20120073810 US20120227964 US20130068458 US20130333884 US20140060825 US20140110109 US20140231081 U.S. Pat. No. 4,336,839 U.S. Pat. No. 6,230,814 U.S. Pat. No. 6,591,908 U.S. Pat. No. 7,780,152 U.S. Pat. No. 7,814,867 U.S. Pat. No. 8,079,417 U.S. Pat. No. 8,353,342 U.S. Pat. No. 8,353,343 U.S. Pat. No. 8,602,103 U.S. Pat. No. 8,656,999 Ian D. Gates, Solvent-aided Steam-Assisted Gravity Drainage in thin oil sand reservoirs, J. Petrol. Sci. Engin. 74(3-4):138-146 (2010). SPE-148698-MS (2011) Betzer, M. M., Steamdrive Direct Contact Steam Generation for SAGD.