CONVECTIVE HEATING STARTUP FOR HEAVY OIL RECOVERY
FIELD OF THE INVENTION
The invention is in the field of thermal processes for enhancing the recovery of viscous hydrocarbons from underground deposits.
BACKGROUND OF THE INVENTION
A variety of processes are used to recover viscous hydrocarbons, such as heavy oils and bitumen, from underground deposits. There are extensive deposits of viscous hydrocarbons around the world, including large deposits in the Northern Alberta tar sands, that are not amenable to standard oil well production technologies. The primary problem associated with producing hydrocarbons from such deposits is that the hydrocarbons are too viscous to flow at commercially relevant rates at the temperatures and pressures present in the reservoir. In some cases, such deposits are mined using open-pit mining techniques to extract the hydrocarbon-bearing material for later processing to extract the hydrocarbons.
Alternatively, thermal techniques may be used to heat the reservoir to produce the heated, mobilized hydrocarbons from wells. One such technique for utilizing a single horizontal well for injecting heated fluids and producing hydrocarbons is described in U.S.
4,116,275, which also describes some of the problems associated with the production of mobilized viscous hydrocarbons from horizontal wells.
One thermal method of recovering viscous hydrocarbons using two vertically spaced horizontal wells is known as steam-assisted gravity drainage (SAGD). Various embodiments of the SAGD process are described in Canadian Patent No. 1,304,287 and corresponding U.S.
Patent No. 4,344,485. In the SAGD process, steam is pumped through an upper, horizontal, injection well into a viscous hydrocarbon reservoir while hydrocarbons are produced from a lower, parallel, horizontal, production well vertically spaced proximate to the injection well.
The injector and production wells are typically located close to the bottom of the hydrocarbon deposit.
It is believed that the SAGD process works as follows. The injected steam creates a 'steam chamber' in the reservoir around and above the horizontal injection well. As the steam chamber expands upwardly and laterally from the injection well, viscous hydrocarbons in the reservoir are heated and mobilized, especially at the margins of the steam chamber where the steam condenses and heats a layer of viscous hydrocarbons by thermal conduction. The mobilized hydrocarbons (and aqueous condensate) drain under the effects of gravity towards the bottom of the steam chamber, where the production well is located. The mobilized hydrocarbons are collected and produced from the production well. The rate of steam injection and the rate of hydrocarbon production may be modulated to control the growth of the steam chamber to ensure that the production well remains located at the bottom of the steam chamber in an appropriate position to collect mobilized hydrocarbons.
It is important for efficient production in the SAGD process that conditions in the portion of the reservoir spanning the injection well and the production well are maintained so that steam does not simply circulate between the injector and the production wells, short-circuiting the intended SAGD process. This may be achieved by either limiting steam injection rates or by throttling the production well at the wellhead so that the bottomhole temperature at the production well is below the temperature at which steam forms at the bottomhole pressure. While this is advantageous for improving heat transfer, it is not an absolute necessity, since some hydrocarbon production may be achieved even where steam is produced from the production well.
A crucial phase of the SAGD process is the initiation of a steam chamber in the hydrocarbon formation. The typical approach to initiating the SAGD process is to simultaneously operate the injector and production wells independently of one another to recirculate steam. The injector and production wells are each completed with a screened (porous) casing (or liner) and an internal tubing string extending to the end of the liner, forming an annulus between the tubing and the casing. High pressure steam is simultaneously injected through the tubings of both the injection well and the production well. Fluid is simultaneously produced from each of the production and injection wells through the annulus between the tubing string and the casing. In effect, heated fluid is independently circulated in each of the injection and production wells during this start-up phase, heating the hydrocarbon formation around each well by thermal conduction. Independent circulation of the wells is continued until efficient fluid communication between the wells is established. In this way, an increase in the fluid transmissibility through the inter-well span between the injection and production wells is established by conductive heating. Once efficient fluid communication is established between the injection and the production wells, the injection well is dedicated to steam injection and the production well is dedicated to fluid production.
Canadian Patent No.
1,304,287 teaches that in the SAGD start-up process, while the production and injection wells are being operated independently to inject steam, steam must be injected through the tubing and fluid collected through the annulus, not the other way around. It is disclosed that if steam is injected through the annulus and fluid collected through the tubing, there is excessive heat loss from the annulus to the tubing and its contents, whereby steam entering the annulus loses heat to both the formation and to the tubing, causing the injected steam to condense before reaching the end of the well.
The requirement for injecting steam through the tubing of the wells in the SAGD
start-up phase can give rise to a problem. The injected steam must travel to the toe of the well, and then migrate back along the well bore to heat the length of the horizontal well. At some point along the length of the well bore, a fracture or other disconformity in the reservoir may be encountered that will absorb a disproportionately large amount of the injected steam, interfering with propagation of the conductive heating front back along the length of the well bore. To avoid this problem, it would be advantageous to provide a start-up method that did not require heating fluid to be injected only through the tubing, so that fluid could be injected along the length of the well through the annulus.
U.S. Patent No. 5,407,009 (the "'009 Patent") identifies a number of potential problems associated with the use of the SAGD process in hydrocarbon formations that are underlain by aquifers. The '009 Patent teaches that thermal methods of heavy hydrocarbon recovery such as SAGD may be inefficient and uneconomical in the presence of bottom water (a zone of mobile water) because injected fluids (and heat) are lost to the bottom water zone ("steam scavenging"), resulting in low hydrocarbon recoveries. The '009 Patent addresses this problem using a technique of injecting a hydrocarbon solvent vapour, such as ethane, propane or butane, to mobilize hydrocarbons in the reservoir.
SUMMARY OF THE INVENTION
The invention provides a process for initiating recovery of viscous hydrocarbons by drilling injection and production wells, which may be horizontal, into a reservoir comprising a region of viscous hydrocarbon deposits. An operative portion of the production well may be below, an operative portion of the injection well. Alternatively, the production and injection wells may be horizontally spaced apart, or an operative portion of the injection well may be above an operative portion of the production well. Heated fluid, such as water or steam, is injected into the injection well and fluid is produced from the production well, to establish fluid flow between the operative portion of the injection well and the operative portion of the production well, and to heat the viscous hydrocarbon deposit by a combination of conductive and convective heating. The process of the invention therefore avoids the prior art step of recirculating heating fluid in either the injection or production wells.
In one aspect of the invention, the heated fluid may be injected through both the injector tubing and the injector annulus. In one aspect of the present invention, the ability to inject through both the injector tubing and the injector annulus provides the advantage of helping to prevent short-circuiting of the inter-well span, as discussed in more detail below.
The start-up process of the invention creates a pressure differential in the reservoir between the injection well and the production well which initiates fluid flows in the inter-well region of the reservoir, facilitating heating of the reservoir by mass transfer or convection, in addition to the heating which is effected by thermal conduction. In one aspect of the invention, the improved heating performance that is thereby achieved allows the injection well and the production well to be located further apart than would be preferable using known start-up procedures.
The process of the invention may be particularly useful in reservoirs that have a mobile fluid zone, such as regions of mobile water. In such embodiments, the operative portion of the production well may be in fluid communication with the operative portion of the injection well. The mobility of such regions may enhance the convective heating of the process of the invention, in contrast to the prior teaching that such mobile regions are disadvantageous to the conductive heating of earlier start-up processes.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 is a schematic vertical cross-section of an injection well and production well pair.
Figure 2 is a schematic representation of an injection well completion.
Figure 3 is a schematic representation of a production well completion.
Figure 4 is a graph showing rates for injection, water production and oil production in a pilot test of the process of the invention.
Figure 5 is a graph showing average production and injection temperatures, together with the surface steam quality of the injected steam in a pilot test of the process of the invention.
Figure 6 is a graph showing average production and injection pressures in a pilot test of the process of the invention.
Figure 7 is a schematic representation of a SAGD process.
DETAILED DESCRIPTION OF THE INVENTION
The present invention provides a process for initiating recovery of viscous hydrocarbons from a reservoir, such as the reservoir shown schematically in Figure 7. Once the start-up phase of the present invention is complete, recovery of hydrocarbons may be undertaken by known methods, such as SAGD (illustrated schematically in Fig.
7). The present invention may be adapted for use with a wide range of heavy oil or oil sand formations, such as parts of the extensive Athabasca tar sands in Northern Alberta, Canada.
The initial step in the process of the invention is the drilling and completion of the injection 10 and production 12 wells. The injection 10 and production 12 wells may be drilled and completed with known techniques. In one embodiment, 'operative' portions of the production 12 and injection 10 wells are generally horizontal, and may be drilled and completed using known horizontal drilling techniques. The production 12 and injection 10 wells are drilled and completed so as to appropriately position the injection 10 and production 12 wells with respect to one another so that it is possible to establish fluid communication between operative portions of the wells 10, 12 through the inter-well span 11.
The operative portion of the production well 12 may be below the operative portion of S injection well 10. The wells 10, 12 may also be positioned near the bottom of the viscous hydrocarbon deposit. Such positioning of wells 10, 12 may be preferable to maximize potential recovery of overlying viscous hydrocarbons by processes such as SAGD.
Figure 1 shows a schematic vertical cross-section of an injection well 10 and production well 12 pair. Vertical'observation' wells 14 may be provided in the vicinity of the injector 10 and producer 12 wells to monitor the status of the reservoir, such as temperature and pressure, at various locations. In one embodiment the operative portions of the injection well 10 and the production well 12 are preferably within about 10 metres of one another.
The reservoir may include a mobile fluid region, such as an aquifer or a zone of mobile hydrocarbons. However, the process may also be adapted to work in regions where there is no significant fluid mobility at the onset of the start-up process.
The injection 10 and/or the production 12 wells) may be located in the mobile fluid region. The degree of fluid mobility in the reservoir, particularly the inter-well span 11, governs the selection by those skilled in the art of fluid injection rates, how fast the hot water injection fluid temperature is increased, how fast the steam quality of the injection fluid is increased and the injection pressures. The invention may therefore be adapted by those skilled in this art for use with reservoirs having a wide range of fluid mobilities by adjusting these parameters. In some embodiments, such adaptations may be such that the higher the fluid mobility is in the reservoir, the higher the injection rates may be, and the faster the increase in the injection fluid temperature may be (and the more rapid may be the increase in steam quality).
Figure 2 shows a schematic representation of an injection well 10 completion in accordance with one embodiment of the invention. Injector casing 16 houses injector tubing 18, forming between them injector annulus 20. Injector casing 16 may be a wire-wrapped screen, slotted liner (in which typically about 1-3% of the casing has 0.01 inch slots) or a perforated casing. An injector instrument string 22 may be provided to monitor temperature and pressure at various points using injector sensors 24. Injector tubing 18 may be provided with holes 26, such holes 26 may allow fluid to pass between injector tubing 18 and injector annulus 20 which may provide for a more even distribution of injection fluid along the length of injection well 10. The end of injector tubing 18 may be provided with an injector tubing cap 30.
Figure 3 shows a schematic representation of a production well 12, completed in accordance with one embodiment of the invention. A porous producer casing 32 houses producer tubing 34, forming between them producer annulus 36. A producer instrument string 38 may be provided to monitor temperature and pressure at various points using producer sensors 40. In one embodiment, a producer tubing instrumentation string 42 extends up the vertical section of producer tubing 34 to monitor pressures and temperatures as fluids are produced, using sensors 43 at various points. Producer tubing holes 44 allow fluid to pass between producer tubing 34 and producer annulus 36. The end of producer tubing 34 may be provided with an producer tubing cap 46. Production well 12 may be provided with a gas lift tubing 48 that communicates through gas ports 49 with producer tubing 34, so that gas may be injected down gas lift tubing 48 to help raise fluids up the vertical portion of producer tubing 34 (as shown by the arrows in Figure 3). Gas lift may be particularly advantageous in 'under pressure' reservoirs, where the reservoir pressure is less than the hydrostatic pressure in production well 12. The producer gas lift rate or producer wellhead pressure may be modulated to maintain the pressure at the production well toe 50 at or close to the reservoir pressure. The temperature at the production well toe 50 may also be monitored to ensure, in one embodiment, that it is maintained below the temperature of steam at the reservoir pressure (the 'saturation' pressure of steam). For example, the temperature may be maintained 10-40°C below the saturation pressure of steam. In one embodiment, where the production well 12 is in a zone of mobile water, the pressure in the production well 12 may be maintained at a high enough level to limit the extent to which mobile water is produced from the reservoir.
Figures 4, 5 and 6 show data from a pilot test of the process of the invention. Figure 4 shows rates for injection, water production and oil production. Figure 5 shows average production and injection temperatures, along with the increase in the steam quality of the injection fluid. Steam quality is a measure of the proportion of the aqueous injection fluid which is in the vapor phase, in terms of mass. Steam quality is measured at the surface, while the other measurements in Figure 5 reflect conditions at the bottom of the wells ('bottomhole' conditions). Figure 6 shows average production and injection pressures. As shown on Figure 6, the injection and production pressures oscillate around an average of about 3000 kPa during approximately the first 40 days of start-up. The boiling point of water at 3000 kPa is approximately 230°C. As shown in Figure 5, the temperature of the injection fluid passes through 230°C some time around the 40~' day of start up. At about the same time, the steam quality of the injection fluids begins to rise. These date reflect the transition during the start up phase from water injection to steam injection. In accordance with one aspect of the invention, the temperature of water injected through injection well 10 during the start-up phase may gradually be increased, as for example is shown in Figure S. This start-up phase may last anywhere from a few days to several months. Gravity acts to pull the water down to heat the inter-well span 11 of the reservoir between injection well 10 and production well 12.
The mobility of fluids in inter-well span 11 is increased by heating during the start-up phase.
Injecting water rather than steam has the advantage that water is less buoyant than steam, so that it more efficiently sinks to heat the inter-well span 11, rather than rising to dissipate heat upwardly into the reservoir (as steam does once SAGD is initiated). Also with hot water, the heating may be more gradual than is possible using steam injection fluid from the outset. The use of steam injection fluid may cause an abrupt change in the temperature profile from the injector to the producer, which may in turn cause too much bitumen to move at once, becoming immobile in the inter-well span 11. Such bitumen plugging may reduce the overall fluid mobility in the inter-well span 11. The injection of hot water may help to reduce bitumen plugging. Similarly, The gradual increase in the steam quality of the injection fluid over a period of time may improve the results of the start-up process of the invention. By heating inter-well span 11 in accordance with the present invention, fluid communication between injection well 10 and production well 12 is improved so that hydrocarbon production at the onset of SAGD is improved.
_g_ Injection fluid may be injected through the injection annulus 20, the injection tubing 18, or both 20, 18. Similarly, fluid may be produced from the production tubing 34, the production annulus 36, or both 34, 36 annulus and tubing of production well 12 (fluid entering annulus 36 of production well 12 may travel to the toe 50 of the production well 12 to enter production tubing 34 and then reverse its direction of flow to return to the surface).
The production tubing 34 may end anywhere between the heel (the transition between vertical and horizontal portions of the well) and the toe 50 of the production well 12.
In one embodiment, heated injection fluid is injected through both the injector tubing 18 and the injector annulus 20. The heated injection fluid then enters the reservoir more evenly along the length of the injection well than it would if it was injected only through the injector tubing 18. This approach helps to avoid problems that can arise if fluids are preferentially injected at the injection well toe 28. Fluids preferentially injected at the injection well toe 28 must travel back along the length of the injection well 10, as well as towards the production well 12. In passing back along the length of the injection well 10, such fluids may 'break through' along paths of reduced resistance to the production well 12. If this happens, the heating of the inter-well region is not uniform. Such 'breakthroughs' can happen where geologically the fluid mobility is increased , reservoir vertical permeability is enhanced or at places where the injector 10 and producer 12 wells happen to be in close proximity.
As shown schematically in Figure 7, following start-up, a steam chamber 71 forms in production layer 57 below overburden 55 and above basement layer 59. Steam is injected, arrow 61, at injection well head 60. Injected steam, arrows 70, sustains the steam chamber and creates a layer of mobilized hydrocarbons 72 which flow, arrows 73 to production well 12 for production at production well head 62, arrow 63.
Although various embodiments of the invention are disclosed herein, other adaptations and modifications may be made by those skilled in the art within the scope of the invention, including the substitution of equivalent parts for the parts of the invention specifically disclosed herein, i.e. parts that perform substantially the same function in substantially the same way to achieve substantially the same result.