Steam-solvent-gas process with additional horizontal production wells to enhance heavy oil / bitumen recovery

Abstract

A system and method of production of hydrocarbons, such as heavy oil or bitumen, by injection of steam, solvent and NCG is provided, which combines the benefits of SAGD, VAPEX, and the use of an additional producer, with specific timing specifications for the initiation of solvent injection prior to inter-chamber fluid communication.

Claims

1. An in situ recovery process for oil in an underground reservoir in an oil bearing formation comprising the steps of: a. drilling a first well pair which comprises a substantially horizontal first producer wellbore within the oil bearing formation and nearer to the bottom of the oil bearing formation than to the midpoint of the formation's vertical depth, and a substantially parallel first horizontal injector wellbore in the same formation but separated by a vertical distance above the first producer wellbore and located nearer the top of the formation than the first producer wellbore, with associated steam generation and oil production facilities, and with facilities for injection of steam, solvent and Non-Condensable Gas (NCG); b. drilling a second well pair substantially parallel to the first well pair, with a second producer wellbore at the same elevation within the same formation as the first producer wellbore and offset from the first producer wellbore by a horizontal distance, and with a second injector wellbore at the same elevation within the same formation as the first injector wellbore and offset from the first injector wellbore by the same horizontal distance; c. producing the oil from the formation around the first and second well pairs by at least: i. initially heating the oil by continuously injecting the steam into the injector wellbores; ii. mobilizing the oil by heat from the steam, and draining the mobilized oil by gravity to the producer wellbores; wherein the steam forms a chamber about and above each of the injector wellbores and; iii. removing the oil from the formation; d. continuing production according to step c until: a) an average temperature of a producible volume of the reservoir outside and adjacent to each of the chambers is increased to a value which permits the reservoir oil in the adjacent volume of the reservoir to be mobilisable; and b) the chambers have extended to the top of the oil bearing formation, and have further extended horizontally at the top of the chambers to thereby conjoin; and e. after step d, injecting the solvent and i. co-injecting the steam to maintain or increase reservoir temperature; and ii. co-injecting the NCG to maintain or increase reservoir pressure via the injector wellbore of at least one of the well pairs; and f. producing the reservoir oil from the producer wellbore of at least one of the well pairs.

2. The process of claim 1, adding at any time the further step of drilling an additional horizontal producer well between and parallel to and at the same elevation within the formation as, and equidistant from, the first and second producer wellbores of the first and second well pairs; and after drilling the additional horizontal producer well, adding after step c but prior to or contemporaneously with the solvent injection of step e, a further step c1: c1. producing the reservoir oil via the additional horizontal producer well.

3. The process of claim 1, adding at any time the further step of drilling an additional horizontal producer well between and parallel to and at the same elevation within the formation as, and equidistant from, the first and second producer wellbores of the first and second well pairs; and after drilling the additional horizontal producer well and after step e, producing the reservoir oil via the additional horizontal producer well.

4. The process of claim 2, with an added step of stimulating the additional horizontal producer well with steam until production from the additional horizontal producer well is established.

5. The process of claim 3, with an added step of stimulating the additional horizontal producer well with steam until production from the additional horizontal producer well is established.

6. The process of claim 1, wherein the reservoir oil of the producible volume of the reservoir outside and adjacent to each of the chambers around the injector wellbores is brought to a temperature within a range required to alter the viscosity of the reservoir oil to be produced so that the oil is mobilisable.

7. The process of claim 1, wherein the reservoir oil is Athabasca bitumen, and where the average temperature of the reservoir oil of the producible volume of the reservoir outside and adjacent to each of the chambers around the injectors wellbores is brought to between 60 and 100 C.

8. The process of claim 1, wherein the reservoir is Cold Lake bitumen, and where the average temperature of the reservoir oil of the producible volume of the reservoir outside and adjacent to each of the chambers around the injectors wellbores is brought to between 30 and 70 C.

9. The process of claim 1 where, the step of increasing the average temperature in step (d)(a) does not use steam.

10. The process of claim 1 where the injected volume of one or more of: the solvent, steam, or NCG is adjusted to optimize oil phase viscosity, chamber pressure and temperature in situ for production of reservoir oil.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) FIG. 1 (which is not to scale) is a cross-sectional portrayal of a fictional formation on a plane perpendicular to surface and to horizontal well bores in the formation.

DETAILED DESCRIPTION

(2) SAGD may be modified by injecting a solvent, with or without steam/NCG. The SAGD well arrangement may also be modified. Solvent injection is used to decrease the viscosity of the oil phase by the solvent concentration effect, in addition to the decrease of viscosity caused by the temperature increase effect due to steam injection. Solvent/NCG injection is also used to recover the heat stored in the chamber and for pressure maintenance. The timing of injection of solvent, steam and NCG has to be chosen appropriately. A process of this type, without the solvent, is described in Canadian Patent 2776704.

(3) The well system for a preferred embodiment of the process here is a modification of the SAGD system with additional producers. The system consists of two adjacent horizontal and essentially parallel injector-producer well pairs 50, 60, vertically separated by a short distance (typically 4-10 m), of the type used for SAGD, with an additional horizontal production well 70 (referred to as an additional producer) approximately midway between the well pairs 50, 60 at about the elevation of the adjacent SAGD well pairs' producers 40, 41. It is understood that in the field implementation of the invention, there may be several SAGD well pairs 50, 60 with additional producers 70 approximately mid-way between at least some of the adjacent pairs as part of a planned array of wells. The process here is based on the following two modifications of VAPEX: 1) The first modification is called Modified VAPEX or MVAPEX. In VAPEX, solvent alone is injected in vapour form right from the beginning. In MVAPEX, there is an initial SAGD mode (steam injection only) until the average temperature in the reservoir region 90 outside the chambers is in a range for which the Oil becomes mobile. For typical Athabasca bitumen, this range is 60-100 C. and is realized after 3 to 5 years of SAGD operation. At this stage of the process, solvent injection in vapour form begins with or without steam/NCG, resulting in significantly increased Oil rates and lower CSOR, as compared to SAGD. 2) In the second modification, MVAPEX is further enhanced by incorporating at least one additional producer 70. (More than one additional producer may be deployed within an array of well pairs.) These additional producers 70 capture Oil mainly by pressure drive from the chambers 55, 65 of the adjacent well pairs 50, 60 (with some help from gravity drainage). This is not to be confused with the infill wells capturing bypassed oil by gravity drainage in Patent 2591498 and similar techniques of the prior art. The twice modified process is called enhanced MVAPEX or eMVAPEX.
A preferred embodiment of the process here begins as SAGD (steam injection only), with the additional producers 70 shut in or not present. When the average temperature in the reservoir region 90 outside the chambers reaches values in a range for which the Oil becomes mobile, solvent injection begins in 30, 31 with or without steam or NCG (most commonly, steam injection rates are reduced), and the additional producers 70 begin operation (mainly by pressure drive from the chambers 55 and 65). The injection rates of solvent vapour, steam and NCG are adjusted to maintain chamber pressure, may be variable over time, and are adjusted to maximize efficient production of Oil as part of recovered oil phase liquids. For typical Athabasca bitumen, a target average temperature range for mobilization of the Oil is 60-100 C., which is realized after 3 to 5 years of SAGD operation. When solvent injection of this invention begins after the Oil is mobilized, the viscosity of the Oil (bitumen) in the reservoir region 90, is reduced to a few thousand mPa.Math.s due to heating of this region during the initial SAGD part of the processthe bitumen in this region 90 then has a viscosity similar to that of heavy oil. As the solvent injection proceeds, the solvent dissolves in the oil phase in the region 90, and further reduces the viscosity of the oil phase to values typical for light oil. This diluted and heated oil phase is then drained by the SAGD producers 40, 41 mainly by gravity drainage, and by the additional producer 70 mainly by pressure drive (and some gravity drainage). The Oil production rates during the solvent injection phase of the process here, may be further enhanced by production from the additional producers, and will be considerably higher than the Oil production rates which would be expected to be achieved by continuation of SAGD. Furthermore, because of the pressure support provided by the chamber via injected solvent, with or without co-injection of NCG and/or steam, the Oil production rate from the additional producer is expected to suffer only a mild decline, resulting in a rapid drainage of the Oil in region 90the expectation is that the time to ultimate recovery is considerably reduced, compared to SAGD alone, without affecting the ultimate recovery. When the ultimate recovery point is reached, injection of solvent and steam may be stopped, and if necessary, NCG injection is continued or initiated to maintain chamber pressure. It should be emphasized that for the process here, steam rates may be reduced or steam may be shutoff completely, once the region 90 becomes hot enough, and solvent injection is initiated from the SAGD injectors 30, 31. Co-injection of NCG is also optional or variable, adjusted to maintain pressure in the chambers.

(4) When the chambers 55, 65 approach the vertical plane A-A midway between the SAGD well pairs, after recovering typically 30-40% of Oil in place above the SAGD producers 40, 41 there is a large amount of heat stored in the chambers 55, 65 and the associated region 90. At this point in time, approximately two thirds of the previously injected heat remains underground for typical SAGD projects that have a CSOR between 2.5 and 3. The stored heat is in most cases divided roughly evenly between the chambers 55, 65 and the region 90 outside the chambers. The average temperature of the Oil in the producible region 90 of the reservoir outside the chamber can reach the point where the Oil's viscosity has been reduced to within producible ranges without the need for further heating of the Oil. These temperatures may be reached well before the chambers 55, 65 around the adjacent well pairs 50, 60 merge or come into fluid communication with each other. For typical Athabasca bitumen, the Oil will be mobile at a viscosity below 2,000 mPa.Math.s which will be achieved at temperatures between about 60 C. and 100 C.

(5) With the Oil warmed and a considerable amount of heat already stored in the reservoir 20, steam injection may be reduced or even stopped, and solvent injection with optional co-injection of NCG may be initiated to accelerate Oil production by maintaining formation pressures and reducing in situ bitumen viscosity by having injected both heat and suitable solvent. The injection rates for each of these substances (solvent, steam, NCG) may be adjusted to maintain suitable chamber pressure. Maintaining chamber pressure is important as it provides the pressure drive for the recovery process.

(6) When solvent injection begins, steam injection is reduced or stopped, and NCG injection is optional. The partial pressure of steam in the chambers 55, 65 falls as the system cools. The heat stored in the rocks, particularly within the core of the chambers 55, 65 where temperature is the highest, is recovered and transferred to water in the pores in the formation, and additional steam is produced there. The in situ generated steam flows to chamber boundaries where it heats the Oil and continues the recovery operation. Significant amounts of stored heat will be systemically extracted from the chambers to maintain the temperature in the adjacent region 90, leading to higher overall thermal efficiency of the production processes over the life of the wells.

(7) To accelerate and increase Oil recovery, an additional producer 70 is placed approximately midway between two adjacent SAGD well pairs 50, 60 at about the elevation of the SAGD producers 40, 41. The producer 70 will likely be in the coolest region of the reservoir from a geometrical perspective. However, it is also a location that should have the full gravity head to aid production. Periodic stimulation of the wellbore 70 may be required to reduce the viscosity of the Oil surrounding the additional producer 70 to maintain reasonable production rates. It is expected that only a limited number of wellbore stimulations will be required, as the average temperature outside the chamber will become high enough to achieve reasonable production rates.

(8) The chamber(s) 55, 65 of one or both adjacent well pairs 50, 60 act(s) as a pressure support for the additional producer 70. Pressure drive from such chamber(s) 55, 65, provided by injected solvent and optionally co-injected NCG and/or steam, combined with gravity drainage, will result in improved Oil production rates and a lower overall CSOR.

(9) A preferred embodiment of this invention is as follows. Initially the two well pairs 50, 60 are operated in the SAGD mode, with the additional producer 70 shut-in. eMVAPEX operations begin when the SAGD chamber(s) 55, 65 has(have) risen to near the top of the pay zone 20 and spread sideways sufficiently so as to render a sufficient volume of adjacent producible Oil in the reservoir region 90 outside the chamber(s) hot enough to be mobilefor typical Athabasca bitumen, the temperature range is 60-100 C. At any given time during the SAGD part of the process, the volume of the chambers 55, 65 (associated with an adjacent well pair 50, 60) may be estimated from the cumulative steam injection volumes and Oil production and associated reservoir parameters, such as initial and residual Oil saturations and porosity. From the volumes of chambers 55, 65 and the drainage volumes associated with the well pairs 50, 60, the average temperature in the region 90 outside the chambers may be estimated from the cumulative steam injection, by assuming that between 20% and 30% of the injected heat is stored in the reservoir region 90 outside the chambers for typical SAGD projects that have a CSOR between 2.5 and 3. This average temperature may also be estimated by setting up a history-matched reservoir simulation model. The decision to begin eMVAPEX may then be based on the estimated average temperature in the reservoir region 90 outside the chamber between the two well pairsfor Athabasca bitumen, this time typically corresponds to 3 to 5 years after the beginning of SAGD. At that point in time, steam injection is reduced or stopped, and solvent and optional NCG injection begins in the SAGD injectors 30, 31. The injection rates of solvent, optional NCG and/or steam are adjusted so as to maintain chamber pressure.

(10) Additional producer 70 operations begin at about the same time as solvent injection. Although at this time the average temperature in the region 90 outside the chamber is high enough for the Oil be mobile, it is possible that the additional producer 70 may be cold. If this is the case, the additional producer wellbore 70 is stimulated for a suitable period of time before commencing production. Multiple wellbore stimulations may be required to achieve reasonable sustained production from the additional producer 70. Wellbore stimulations may be discontinued when sustained production is achieved in the additional producer 70. In the process here, there is no steam chamber surrounding the additional producer 70, at least during the early stages of operation, and the mobile Oil in the reservoir region 90 outside the chambers flows into the additional producer well 70 because of pressure drive from the well pairs' 50, 60 associated chambers 55, 65, and some gravity headin this respect the process of this invention differs from the processes described in Patents 2277378 and 2591498, which require the formation of conjoined or merged chambers surrounding their associated infill/offset wells, and the merging of at least two steam chambers.

(11) So far, it has not been possible to achieve attractive bitumen production rates in the field using VAPEX with propane as the solvent. Steam-solvent processes have not shown much promise. Poor solvent recovery is a major issue, making the processes economically unattractive. It is expected that high solvent recoveries can be achieved in eMVAPEX due to the pressure drive to the additional producers.

(12) eMVAPEX, being a solvent based process, inherits several further advantages associated with such processes. Under suitable conditions, in situ upgrading of bitumen can occur because of deasphalting, resulting in higher production rates, and a higher price for the product leaving relatively low value asphaltenes unproduced in the formation, and recovering an essentially upgraded oil product. The process also reduces steam consumption and GHG emissions.

(13) Reservoir simulation results indicate that considerable reduction in cumulative steam injected and CSOR may be achieved by eMVAPEX while the Oil production is accelerated due to solvent action, while maintaining high ultimate recoveries similar to SAGD.

REFERENCES

(14) 1. Butler, R., The Steam and Gas Push (SAGP), Journal of Canadian Petroleum Technology, Vol. 38, No. 3, pp. 54-61, March 1999. 2. Butler, R. M., Jiang, Q. and Yee, C.-T., Steam and Gas Push (SAGP)3; Recent Theoretical Developments and Laboratory Results, Journal of Canadian Petroleum Technology, Vol. 39, No. 8, pp. 51-60, August 2000. 3. Butler, R. M. and Mokrys, I. J., A new process (VAPEX) for recovering heavy oils using hot water and hydrocarbon vapour, Journal of Canadian Petroleum Technology, Vol. 30, No. 1, pp. 97-106, January-February 1991. 4. Butler, R. M., Horizontal Wells for the Recovery of Oil, Gas and Bitumen, Petroleum Society Monograph Number 2, Canadian Institute of Mining, Metallurgy & Petroleum, 1994.

(15) The above-described embodiments of the invention are provided as examples. Alterations, modifications and variations can be effected to particular portions of these embodiments by those with skill in the art without departing from the scope of the invention, which is solely defined by the claims appended hereto.