CA2776704C - Modified steam and gas push with additional horizontal production wells to enhance heavy oil/bitumen recovery process - Google Patents

Abstract

A system and method of production of hydrocarbons, such as heavy oil or bitumen, by injection of heat energy in situ is provided, which combines the benefits of SAGP and the use of an additional producer, with specific timing specifications for the initiation of co-injection of non-condensable gas and steam prior to inter-chamber fluid communication.

Description

MODIFIED STEAM AND GAS PUSH WITH ADDITIONAL
HORIZONTAL PRODUCTION WELLS TO ENHANCE
HEAVY OIL / BITUMEN RECOVERY PROCESS
FIELD OF THE INVENTION
This invention is related to the recovery of hydrocarbons such as heavy oil or bitumen from an underground formation, using a combination of steam-assisted gravity drainage, modified steam and gas push, and additional production wells.
PRIOR ART
1.0 Steam-assisted gravity drainage ("SAGD") is the process commonly employed in commercial projects for hydrocarbon recovery from heavy oil and bitumen deposits. The SAGD process, based on Canadian Patent 1130201, makes use of a pair of essentially parallel horizontal wells, separated by a short vertical distance (typically 4 ¨ 10 m), to recover immobile oil at initial reservoir conditions.
Steam is injected into the oil reservoir continuously from the top horizontal well and the heated oil in the reservoir drains by gravity from the reservoir into the bottom horizontal well. During the start-up phase, steam is normally circulated within both wells to heat up the region between the wells and thereby render the oil mobile.
Continuous steam injection and production of oil and steam condensate during the SAGD phase results in the formation of a steam chamber, from which most of the oil has drained.
A modification of SAGD to improve the thermal efficiency of the process was suggested by Butlerl. Consider SAGD carried out at a (nearly) constant steam chamber pressure. The entire steam chamber has to be maintained at the high temperature corresponding to the chamber pressure (typically 200 to 250 C) by steam injection. Butler's idea was to reduce the temperatures in the top portion of the chamber, but maintain the high temperature near the SAGD well pair in order to minimize the tendency for gas coning into the producer. This may be accomplished by co-injection with steam of a small quantity (typically less than 1 mole percent) of non-condensable gas, typically natural gas which is readily available in the field, but VVSLega1\048127\00104\7807348v7 also nitrogen, methane, or any other non-condensable gas (collectively, "NCG"). He called the modified process "Steam and Gas Push" or "SAGP". Unlike steam, the NCG can travel large distances (since it does not condense) and convey the pressure of the steam/NCG chamber, thereby providing pressure support and facilitating gravity drainage of oil.
The NCG accumulates near the top of the chamber and reduces the partial pressure of steam. This results in temperature reduction (as compared to SAGD) in the region of NCG accumulation. This NCG and steam mixture provides some insulation near the top of the reservoir which in turn reduces heat losses to the overburden.
As originally conceived by Butlerl, in SAGP NCG co-injection begins at the initiation of the production process, immediately following the initial steam circulation period. NCG fingers quickly move to the top of the pay zone during the chamber rise period. The pressure support provided by the fast-moving NCG
tends to increase the oil flow rate by accelerating the gravity drainage process. At the same time, the colder temperatures in the top region for SAGP tend to decrease the oil flow rate. Based on laboratory results (as shown in Figure 14 on p. 57 of Ref. 2), in the chamber rising phase the production rates for SAGP are approximately the same as for SAGD with reduced steam requirements. However, once the bulk of the chamber reaches the top of the reservoir, there is a risk that the SAGP oil rates could become progressively lower as compared to SAGD. To minimize the possibility of reduced oil rates for SAGP during the spreading phase, a modification of SAGP
is proposed in this invention.
Another advantage of SAGP is that it provides more flexibility in selecting operating pressures. There are situations for which the chamber pressure of SAGD cannot be reduced below the initial pressure of the reservoir. For example, if bottom water is present, the chamber pressure must be maintained close to the bottom water pressure to prevent the incursion of water into the chamber. SAGP

circumvents this limitation by lowering the steam partial pressure without reducing the WSLegal\048127\00104\7807348v7 total pressure of the steam/NCG chamber. SAGP thus provides the opportunity to decrease individual well instantaneous steam-oil ratio ("ISOR") and thereby free up steam for redeployment in other wells. By applying this strategy, it is possible to achieve overall oil production rates above design capacity without increasing the steam generation capacity of the project.
Other processes to improve the thermal efficiency of SAGD are described in Canadian Patents 2277378 and 2591498. In Patent 2277378, a SAGD
well pair is supplemented by a horizontal "offset" well located at the elevation of the SAGD producer. The offset well begins operation in the cyclic steam stimulation ("CSS") mode after the SAGD well pair has undergone a few years of operation.
Once fluid communication is established between the SAGD well pair and the offset well, CSS is discontinued at the offset well. The offset well then becomes a full time producer. A small amount of nitrogen or methane may also be injected with the steam in the SAGD injector after the fluid communication between the SAGD well pair and the offset well is established. Based on reservoir simulation results, it was claimed that the process in Patent 2277378 resulted in increased oil rates, oil recovery and reduced steam consumption as compared to SAGD.
The well arrangement in Patent 2591498 consists of an infill well drilled between two adjacent SAGD well pairs. Separate mobilized zones are created initially using SAGD at each of the SAGD well pairs. Over a period of time, the two mobilized zones merge to form a common mobilized zone. A bypassed region of oil is then formed beneath the common mobilized zone between the adjacent well pairs.
The main objective of the infill well is to recover this bypassed oil, after the common mobilized zone has been formed, substantially by gravity drainage. Based on reservoir simulation results, the process in Patent 2591498 is claimed to reduce the cumulative steam-oil ratio ("CSOR") significantly, and increase the calendar day oil rate, for a given oil recovery, as compared to SAGD.

WSLegal\048127\00104\7807348v7 SUMMARY OF THE INVENTION
A purpose of the present invention is to further enhance the thermal efficiency of SAGD and SAGP while maintaining high oil recovery. Referring to Figure 1, the invention in one embodiment requires two horizontal injector-producer well pairs 50, 60, of the type used in SAGD schemes (commonly referred to as "adjacent well pairs"). The elevation is nearly the same for the two injectors 30, 31, and for the two producers 40, 41. A horizontal well, herein referred to as an "additional producer" 70, is placed at or near the elevation of the producers 40, 41 of the adjacent well pairs 50, 60, approximately midway between those producers 40, io 41. The two well pairs 50, 60 are initially operated, for example in a SAGD mode, with steam injection through the injectors 30, 31 and oil production from the producers 40, 41. This operation results in the formation of steam chambers 55, 65 around the two well pairs 50, 60. The steam chambers 55, 65 are allowed to rise to the top 15 of the pay zone 20 and spread sideways. It is to be understood that, while is a SAGD process is used as the example, the invention may be practiced in any suitable setting which involves injection of thermal energy into a reservoir containing hydrocarbons, such as heavy oil, or bitumen (any of which are referred to as "Oil").
In another embodiment, the present invention provides an in situ recovery process for Oil in an underground reservoir comprising the steps of:
drilling 20 a SAGD well pair, with associated steam generation, injection, and production facilities, with facilities for co-injection of NCG; drilling a second, essentially parallel and adjacent, well pair; and producing Oil from the well pairs using a SAGD
process until the average temperature of a producible adjacent volume of the reservoir outside the chamber reaches a temperature which permits included Oil to be 25 mobilisable; and then co-injecting NCG with steam into the injector of at least one well pair.
In another embodiment, adding the further steps of drilling an additional horizontal well essentially parallel with and equidistant from the producers of the WSLegal\048127\00104\7807348v7 adjacent well pairs; and producing the Oil using the additional horizontal well, without or prior to co-injecting NCG.
In yet another embodiment, production of the Oil using the additional horizontal well follows or is contemporaneous with co-injection of NCG. If the additional horizontal well does not produce at satisfactory rates, stimulation of the additional horizontal well will be carried out prior to production.
In any embodiment, the average temperature of the producible Oil adjacent to the chambers is within the range of temperature required to alter viscosity of the heavy oil/ bitumen being specific to the type of heavy oil/bitumen to be 1.0 produced. In the case of typical Athabasca bitumen, the range is between about 60 and 100 C, while the temperature range will be lower for the less viscous Cold Lake type of bitumen.
The process is workable when the viscosity of the Oil becomes producible, below approximately 10,000 mPa.s and preferably below about 2,000 mPa.s.
The invention may also be economic where the heat injection process is not SAGD or SAGP but is another method of increasing temperature of the reservoir in situ.
The present invention makes use of the heat stored in the reservoir 20 to improve the thermal efficiency of SAGD, without requiring the two SAGD
chambers 55, 65 to merge. The average temperature in the Oil between the adjacent chambers 90 may be estimated from the cumulative Oil production and steam injection. As the average temperature of the Oil in the region 90 continues to increase, the viscosity of the initially immobile Oil will be reduced to a point where it is mobile enough to be produced from the additional producer 70, using methods that are commonly used to produce heavy oil. In the case of typical Athabasca bitumen, this point is achieved at a temperature range of 60 ¨ 100 C at which time the viscosity has been reduced from more than 1,000,000 mPa.s to less than 2,000 mPa.s.

WSLegal\048127\00104\7807348v7 Since the initially immobile Oil is now mobile enough to be produced by conventional techniques, there is no need to continue steam injection at full rates.
NCG is then co-injected with steam to maintain chamber pressure and recover the heat stored in the chambers 55, 65. The heat recovered by the NCG injection boils residual water in the chambers 55, 65 and further steam is produced. The in situ generated steam flows to chamber boundaries where it condenses and transfers heat to the Oil and continues the recovery operation. The steam and NCG also provide a pressure drive to push the heated Oil to the additional producer 70. This combination of heat recovery by NCG co-injection and production via the additional producer 70 results in significant reductions in steam consumption and CSOR while maintaining high recoveries similar to SAGD. NCG/steam co-injection begins when sufficient heat has been stored outside the steam chamber, and not from the beginning of steam injection (as in SAGP processes), for a preferred embodiment of the present process.
Although the average temperature in the region 90 outside the chambers is estimated to be 60 ¨ 100 C for typical Athabasca bitumen, at the time the additional producer 70 operation begins, according to the criterion here, it is possible for the temperature at the additional producer 70 location to be lower. If this is the case, it may be necessary or useful to stimulate the additional producer 70, for example by steam stimulation, to initiate Oil production. This wellbore stimulation may be required periodically to maintain reasonable production rates.
It is not necessary for the steam chambers 55, 65 or the "mobilized zones" in the terminology of Patent 2591498 to merge, before commencing additional producer 70 operations, as per the criterion on stored heat used here. In this respect, the present process differs from the one described in Patent 2591498.
It is also not necessary to achieve hydraulic communication between a steam chamber from the additional producer 70, created by CSS operations, and the chamber from either SAGD well pair 55 or 65, as in Patent 2277378. The present vvsLegal018127\00104\7807348v7 process is therefore different from the processes described in Patents 2591498 and 2277378.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 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
The well 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 SAGP which itself is a modification of SAGD:
1) The first modification is called "Modified SAGP" or "MSAGP". A key feature of MSAGP is that co-injection of NCG with steam begins, when 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. The concentration of NCG in the injection stream may be steadily increased or even made 100%, resulting in significant reduction in steam consumption compared to SAGD or SAGP. For a given chamber pressure, ISOR and CSOR are significantly lower for MSAGP as compared to SAGD or SAGP.
¨ 7 ¨
VVSLegal \048127\00104\7807348v7 , 2) In the second modification, MSAGP 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 by steam/NCG push (mainly pressure drive) from the chambers 55, 65 of the adjacent well pairs 50, 60. 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 MSAGP" or "eMSAGP".
As described earlier, SAGP is a modification of SAGD in which a small quantity of NCG (typically less than 1 mole percent) is co-injected with steam right from the beginning of steam injection. SAGP is an attractive process as it provides comparable Oil production rates to SAGD in the chamber rising phase with reduced energy requirements. It appears that evolved solution gas and reservoir gas generated as a result of steam heating will provide most of the amount of gas required to capture the early SAGP benefits in SAGD itself. Once the bulk of the chambers 55, 65 have reached the top 15 of the reservoir 20, the Oil production rate for SAGP may be lower than the rate for SAGD, as the horizontal spreading of the gas/liquid interface slows down due to the accumulation of NCG and the subsequent reduction in temperature. The addition of significant amounts of NCG to steam at this phase of the operation could pose the risk of further reducing the spreading rate of the chambers 55, 65.
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 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 outside the chambers. The VVSLega1\048127\00104\7807348v7 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.s which will be achieved at temperatures between about 60 C and 100 C.
With the Oil warmed and a considerable amount of heat already stored in the reservoir 20, steam injection can be curtailed significantly. Any reduction in the steam injection rate will be supplemented by NCG injection to maintain suitable chamber pressure. Maintaining chamber pressure is important as it provides the pressure drive for the recovery process.
When steam injection rates are reduced, 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, and additional steam is produced.
The in situ generated steam flows to chamber boundaries where it heats the Oil and continues the recovery operation. By controlling the NCG and steam injection rates, significant amounts of stored heat will be systemically extracted from the chamber to continue the recovery operation leading to higher overall thermal efficiency of the production processes over the life of the wells. The NCG concentration in the co-injection stream may be increased over time perhaps up to 100%.
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. 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 VVSLegaR048127\00104\7807348v7 only a limited number of wellbore stimulations will be required, as the average temperature outside the chamber is high enough to achieve reasonable production rates.
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, combined with gravity drainage, will result in improved production rates and a lower overall CSOR. The injected NCG also helps to insulate the top of the chambers 55, 65 to reduce heat losses to the overburden 10.
The preferred embodiment of this invention is as follows. Initially the io two well pairs 50, 60 are operated in the SAGD mode. eMSAGP 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 mobile ¨ for typical Athabasca bitumen, the temperature range is 60 ¨ 100 C.
At any given time during the SAGD phase of the process, the volume of the chambers 55, 65 (associated with an adjacent well pair 50, 60) may be estimated from the cumulative 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 zo 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 eMSAGP may then be based on the estimated average temperature in the reservoir region 90 outside the chamber between the two well pairs ¨ for Athabasca bitumen, this time typically corresponds to 3 to 5 years after the beginning of SAGD.
At that point in time NCG/steam co-injection begins in the SAGD injectors 30, 31 with reduced steam injection rates. The NCG and steam rates are adjusted so as to WSLegal\048127\00104\7807348v7 maintain chamber pressure. The steam rates are slowly reduced with time and the NCG concentration in the co-injection stream is slowly increased. It may become possible to shut off steam injection altogether and inject NCG only.
Additional producer 70 operations begin at about the same time as NCG/steam co-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 head ¨ in 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.
Reservoir simulation results show that considerable reduction in cumulative steam injected and CSOR may be achieved by eMSAGP while maintaining high recoveries similar to SAGD.
References 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.
- 11. -WSLegal\048127\00104\7807348v7 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.

VVSLega1\048127\00104\7807348v7

Claims (10)

WHAT IS CLAIMED IS:

1. An in situ recovery process for Oil in an underground reservoir comprising the steps of:
a. drilling a SAGD well pair, with associated steam generation, injection, and production facilities, with facilities for co-injection of NCG;
b. drilling a second, essentially parallel and adjacent, well pair at a similar elevation;
c. producing Oil from the well pairs using a SAGD process resulting in a chamber until the average temperature of a producible adjacent volume of the reservoir outside the chamber reaches a temperature which permits included Oil to be mobilisable; and then co-injecting NCG with steam into the injector of at least one well pair.

2. The process of claim 1, adding at any time the further step of drilling an additional horizontal well essentially parallel and at a similar elevation with and equidistant from the producers of the adjacent well pairs; and adding after step c but without or prior to co-injecting NCG, a further step d:
d. producing the included Oil using the additional horizontal well.

3. The process of claim 2, where production of the included Oil using the additional horizontal well follows or is contemporaneous with co-injection of NCG.

4. The process of claim 2 where, if the additional horizontal well does not produce at satisfactory rates, adding the step of stimulating the additional horizontal well.

5. The process of claim 3 where the additional horizontal well does not produce at satisfactory rates, adding the step of stimulating the additional horizontal well.

6. The process of claim 1, 2, 3, 4 or 5 where the average temperature of the included Oil is between 60 and 100 °C for typical Athabasca bitumen, the range of temperature required to alter viscosity of the included Oil being specific to the type of Oil to be produced.

7. The process of claim 1, 2, 3, 4 or 5 where the average temperature of the included Oil is between 30 and 70 °C for typical Cold Lake bitumen.

8. The process of claim 1, 2, 3, 4 or 5 where the viscosity of the included Oil when it becomes producible is below 10,000 mPa.s.

9. The process of claim 1, 2, 3, 4 or 5 where the viscosity of the included Oil when it becomes producible is below 2,000 mPa.s.

10. The process of claim 1, 2, 3, 4 or 5 where the heat injection process is not SAGD or SAGP but is another method of increasing temperature of the reservoir in situ.