Patent Application
20100065268
The present invention relates to processes for the recover of heavy oil and bitumen, in particular the use of an inclined portion of a production well within a gravity assisted drainage process.
There are several commercial recovery technologies that are currently used to recover in situ heavy oil or bitumen from tar sands reservoirs. In current practice, in situ technologies are used to recover heavy oil or bitumen from deposits that are buried more deeply than about 70 m below which it is no longer economic to obtain hydrocarbon by current surface mining technologies. Most commercial in situ processes can recover between about 10 and 60% of the original hydrocarbon in place depending on the operating conditions of the in situ process and the geology of the heavy oil or bitumen reservoir. The impact of variations of oil phase viscosity has been demonstrated by using detailed and advanced reservoir simulation. In addition to permeability, porosity, and oil saturation heterogeneity, oil phase viscosity variations add another complicating and sometimes process dominating feature for producing heavy oil and bitumen reservoirs.
The Steam Assisted Gravity Drainage (SAGD) is described in U.S. Pat. No. 4,344,485 (Butler) is used by many operators in heavy oil and bitumen reservoirs. In this method, two horizontal wells, drilled substantially parallel to each other, are positioned in the reservoir to recover hydrocarbons. The top well is the injection well and is located between 5 and 10 meters above the bottom well. The bottom well is the production well and typically located between 1 and 3 meters above the base of the oil reservoir. In the process, steam, injected through the top well, forms a vapour phase chamber that grows within the oil formation. The injected steam reaches the edges of the depletion chamber and delivers latent heat to the tar sand. The oil phase is heated and as a consequence its viscosity decreases and the oil drains under the action of gravity within and along the edges of the steam chamber towards the production well. In the initial stages of the process, the chamber grows vertically. After the chamber reaches the top of the reservoir, it grows laterally. The reservoir fluids, heated oil and condensate, enter the production wellbore and are motivated, either by natural pressure or by pump, to the surface. The thermal efficiency of SAGD is measured by the steam (expressed as cold water equivalent) to oil ratio (SOR), that is CWE m3 steam/m3 oil. Typically, a process is considered thermally efficient if its cumulative SOR is between 2 and 3 or lower. There are many published papers and portions of books and regulatory applications that describe the successful design and operation of SAGD. A literature review shows that while SAGD appears to be technically effective at producing heavy oil or bitumen from high quality connected reservoirs, there remains a continued need for well configurations and processes that improve the SOR of SAGD. Currently, the major capital and operating costs of SAGD are tied to the steam generation and water handling, treatment, and recycling facilities.
A variant of SAGD is the Steam and Gas Push (SAGP) process developed by Butler (Thermal Recovery of Oil and Bitumen, Gray-Drain Inc., Calgary, Alberta, 1997}, In SAGP, steam and non-condensable gas are co-injected into the reservoir, and the non-condensable gas forms an insulating layer at the top of the steam chamber. This lowers the heat losses to the cap-rock and improves the thermal efficiency of the recovery process. The well configuration is the same as the standard SAGD configuration.
Examples of literature on design and operation of SAGD in the field include: Butler (Thermal Recovery of Oil and Bitumen, Gray-Drain Inc., Calgary, Alberta, 1997), Komery et al. (Paper 1998.214, Seventh UNITAR International Conference, Beijing, China, 1998), Saltuklaroglu et al. (Paper 99-25, CSPG and Petroleum Society Joint Convention, Calgary, Canada, 1999), Butler et al. (J. Can. Pet. Tech., 39(1): 18, 2000). Examples of literature describing oil composition and viscosity gradients in heavy and bitumen reservoirs include: Larter et al. (2006), Head et al. (2003) and Larter et al. (2003).
There are other examples of processes that use steam or solvent with different well configurations to recover heavy oil and bitumen.
The literature contains many examples of in situ methods to recover heavy oil or bitumen economically yet there is still a need for more thermally-efficient and cost-effective in situ heavy oil or bitumen recovery technologies, especially when considering the vertical and areal variations of viscosity in the reservoir. There is disclosed herein a method to recover heavy oil or bitumen from a heterogeneous viscosity reservoir in a manner that is more cost-effective and thermally-efficient than existing methods.
Further references include:
The present invention relates to a heavy oil or bitumen recovery method. It utilizes an inclined portion within the production well to extend the vapour chamber formation from the injector well. In combination with gravity assisted vapour stimulation processes, the well configuration is designed to enhance the production of heavy oil or bitumen from reservoirs. In one embodiment of the invention, only a portion of the production well is inclined in comparison to the injector well (as examples, H-Well or M-Well and Gravity Assisted Steam Stimulations or “HAGASS” or “MAGASS”). In another embodiment, the production well, inclined along its length (J-Well and Gravity Assisted Steam Stimulation or “JAGASS”), is placed below the injector well whereby the toe of the production well is closest to the injector toe, and the heel of the production well is positioned at a greater distance from the heel of the injector well. The method is applicable to any reservoir, but is especially beneficial in heavy oil and tar sand reservoirs.
The invention also relates to an improved process to recover heavy hydrocarbons from an underground reservoir which shows a vertical or lateral oil mobility gradient controlled by variations in oil viscosity. The method takes advantage of the common vertical changes in oil viscosity in heavy oil tar sand (HOTS) reservoirs and provides a route to initiate earlier production of HOTS petroleum and to ensure maximum vapour chamber growth along the full length of a horizontal vapour injector well.
Embodiments of a heavy oil or bitumen recovery process will now be described by way of example only, with reference to the attached Figures, wherein:
a-l are embodiments of the inclined wells;
a-d show the cumulative steam to oil ratio (cSOR) and thermal efficiencies of the JAGASS embodiment and SAGD;
With reference to the Figures, an inclined well and gravity assisted vapour stimulation process for recovery of in situ heavy oil or bitumen from reservoirs is described. The improved process and well configuration will be described with reference to SAGD recovery process. However, a person skilled in the art will understand that other gravity assisted stimulation processes can be used, including steam and solvent recovery processes.
To sustain mobile oil flow to the bottom of the steam chamber under the action of gravity, it is required to create and grow the vapour chamber in an oil reservoir. This produces the density difference between vapour and liquid phases which causes gravity-induced flow of liquid to the production well. The liquid is then removed from the chamber by the production well which delivers it to the surface. To continuously produce oil from the reservoir, the chamber must expand as the process evolves.
It should be noted that the cumulative volume of steam is expressed in terms of the volume of cold water required to produce the steam volume. The following description refers to the attached Figures.
In standard SAGD, as shown in
In
As shown in
In one embodiment of the process, in a first stage (Stage 1) of the process, displayed in
The injectant may be any suitable fluid that mobilizes hydrocarbons in the reservoir. In various embodiments, for example, the injectant may be water, steam, carbon dioxide, air, nitrogen or hydrocarbon solvent in the liquid or vapour phase. Suitable hydrocarbon solvents include C1-C10 alkanes, aromatics and alcohols. Combinations of these injectants may be used. In the case of air or a gas comprising, in some portion, oxygen being added as an injectant, a controlled burn of hydrocarbons created by igniting a flame front within the reservoir maybe be used to mobilize hydrocarbons. The injectant may operate by displacing reservoir hydrocarbons in a displacement mechanism, or by reducing the viscosity of the reservoir hydrocarbons so that they move by operation of gravity towards the production well 10. Viscosity reduction may be caused by heating, or by dissolution of the injectant in the reservoir hydrocarbons, or by solvent-induced precipitation or phase separation of the heavier components of the reservoir hydrocarbons leading to a more mobile lighter oil phase. Combinations of these mobilizing methods may be used, as for example using a heated solvent, with or without added displacement gas.
Prior to the start of production, it is desirable to establish a communication path between the top well 11 and the bottom well 10. This may be initially established by injection of injectant into either or both the top well 11 and bottom well 10, and should start at the toe, as illustrated in
Injection of injectant into one or both of the wells 10, 11, creates a vapour and mobilized hydrocarbon chamber 19, which in one embodiment will start at the toes of the wells 10, 11. Injectant injected into the oil reservoir from well 11 flows to the edges of the chamber 19. In the case of steam used as an injectant, the steam condenses and releases its latent heat to the oil sand heating it and consequently lowering the oil phase viscosity enabling it to flow under the action of gravity to the production well 10. As the process evolves and oil is produced to the surface, as shown in
As an alternate embodiment of the process, the process can be started from the second Stage alone, that is, without the cold production Stage. In this case, referring to
After production is initiated, it can be maintained in some embodiments by continuing to inject injectant in a manner such that the mobilized hydrocarbon chamber 18 moves upwell. For example, in the case of steam, this may be accomplished using a modified SAGD procedure with a steam trap pressure control to prevent steam breakthrough or by injecting steam in the injector from a coiled tubing steam injector insert shown in
Steam trap control refers to the practice of controlling the production rate or production well pressure so that there is a liquid bath surrounding the production well. This prevents steam from passing directly from the injection well to the production well.
b-d show a J-shaped production well with an incline along the entire length of the well. However, the production well does not need to be inclined along its entire length. For example,
Computer-aided reservoir simulation can be used to predict pressure, oil, solvent, water, and gas production rates, and vapour chamber 8 dimensions to help design the well placement and operating strategy. Also, the reservoir simulation calculations can be used to assist in the estimation of the time intervals of Stage 1 depicted in
a displays the cumulative steam to oil ratio (cSOR) from field scale numerical model predictions of the standard SAGD and JAGASS processes. The cSOR is a measure of the thermal efficiency of the process and is closely correlated with the economic performance of the recovery processes. The results show that the JAGASS process is thermally more efficient than the standard SAGD process.
In an alternative embodiment of the process, the injectant pressure and temperature can be changed throughout the operation of the process to improve the thermal efficiency of the process. For example, in the early stages of the process before the mobilized hydrocarbon chamber 18 has reached the top of the oil-rich interval, the injection pressure and corresponding saturation temperature could be high thus providing relatively high rates of oil production. Later, after the mobilized hydrocarbon chamber 19 has reached the top of the oil zone, the operating pressure and corresponding saturation temperature can be reduced so that heat losses to the overlying cap rock is reduced. This improves the overall thermal efficiency of the process. The pressure and temperature of the process can be measured by pressure sensors and thermocouples or other devices located in the injection or production wells or both as well as observation wells. Also, the pressure of the mobilized hydrocarbon chamber 18 can be estimated from the injection pressure at the injection well head by taking pressure losses in the well into account. A reduction of the pressure in the chamber can be obtained by reducing the amount of injectant injected into the oil reservoir or by raising the production rate of fluids from the reservoir. An alternative method to lower the injectant partial pressure and corresponding injectant saturation temperature can be accomplished by adding an additive to the injected steam.
In an embodiment of the process, a steam additive can be added to injected steam to enhance the production rates of oil. A solvent, whether used in combination with other injectants or on its own, can lower the viscosity of the oil phase thus raising its mobility and therefore its production rate. A non-condensable gas additive for steam injection can also replace a fraction of the volume of steam injected into the reservoir thus raising the thermal efficiency of the process. Examples of solvent additives include the C2 to C10 hydrocarbons such as propane, hexane, or a mixture as would be the case with diluent or gas condensates. Examples of gases include methane, carbon dioxide, nitrogen, or air.
In an additional embodiment of the process, at the end of the process, a blowdown stage can be started in which no injectant is injected into the oil formation and the pressure of the mobilized hydrocarbon chamber is lowered while fluids are continuously produced to the surface. In this stage, because no injectant is being injected, the process is thermally very efficient (oil production with no injection). However, the oil rate declines rapidly because no additional heat is being injected into the reservoir and heat losses to the understrata and overburden start to consume the remaining heat in the oil zone.
In another embodiment of the present invention, the present process can be used to enhance recovery of heavy oil and bitumen from reservoirs that have vertical and/or areal viscosity gradients.
Compositional and fluid property gradients are common and documented in conventional heavy oilfields and in super heavy oil occurrences such as tar sand reservoirs. In the severely biodegraded oils of the Western Canadian tar sand reservoirs, highly non-linear chemical compositional and fluid viscosity gradients are common in both Athabasca and Peace River reservoirs (Larter et al., 2006). The variations in dead oil viscosity can be determined by mechanical recovery of the oil or bitumen with a centrifuge followed by measurements using a viscometer, or by solvent extraction and use of molecular composition and viscosity correlations. The molecular level variations in compositions are proxies for overall bitumen composition and thus viscosity, the actual compound suites most suitable to assess fluid properties varying with level of degradation and oil type. This is easily determined by using standard geochemical protocols and data analysis procedures that look for compound groups that show reproducible changes in composition over the viscosity range of application interest. Comparison of oil or bitumen molecular fingerprints from solvent extracted bitumens in reservoir core or cuttings, with similar sets of analyses on calibration sets of spun or otherwise extracted raw bitumen, allows for estimation of dead oil viscosities solely from the geochemical measurements and allow viscosity profiling of reservoirs to be carried out at meter scale resolution (Larter et al., 2006). These high resolution viscosity logs are essential for optimizing well locations in JAGASS and other thermal recovery processes using intelligent cold and thermal recovery techniques. This geochemical fluid property prediction approach allows for production of routine and rapid high resolution viscosity logs from core or cuttings or analysis of cuttings from horizontal wells. As heavy oil compositions commonly vary along well sections, the oil heterogeneity assessed from either core or cuttings, if appropriate samples are taken and stored, can also be used to allocate production to reservoir zones by using produced oil and multivariate deconvolution data analysis techniques. This is especially useful in allocation of production in horizontal wells and can be used to assess the effectiveness of the recovery well locations and to optimize well operations including steam and other injected fluid cycling sequences.
Dead oil viscosities are converted to live oil viscosities using gas solubility estimates as a function of reservoir pressure data and correlations between gas to oil ratio, live and dead oil viscosity. The dependence of oil viscosity on recovery temperature is determined by using measurements of viscosity on the same oil samples at various temperatures relevant to the recovery process. Thus, a profile through the oil column of viscosity as a function of temperature is obtained.
At in situ initial conditions i.e. temperature and pressure, heavy oil and bitumen have much higher viscosity than conventional light oils. Also, the defining characteristic of heavy and super heavy oilfields is the large spatial variation in fluid properties, such as oil viscosity, commonly seen within the reservoirs. Heavy oil and tar sands are formed by microbial degradation of conventional crude oils over geological timescales. Large-scale lateral and small-scale vertical variations in fluid properties due to interaction of biodegradation and charge mixing are common, with up to orders of magnitude variation in in-reservoir viscosity over the thickness of a reservoir. Constraints such as oil charge mixing, reservoir temperature-dependant biodegradation rate and aqueous nutrient supply to the organisms ultimately dictate the final distribution of viscosity found in heavy oil fields. Head et al. (2003); Larter et al. (2003; 2006); Huang et al. (2004).
The impact of viscosity variations in a heavy oil reservoir on heavy oil and bitumen productivity depends on the recovery method. Cold heavy oil production with sand (CHOPS) is critically influenced by oil viscosity and published literature (Larter et al., 2006) reveals that vertical viscosity gradients can substantially impact both existing steam assisted gravity drainage and cyclic steam stimulation operations if the gradients are not built into simulation protocol and well design procedures. (Larter et al., 2006).
Use of an inclined production well, as set out above, in combination the heavy oil or bitumen recovery method results in increased heavy oil or bitumen production. The inclined production well, or inclined portion of the production well, extends through the viscosity gradients within the reservoir. This allows for the earlier production of hydrocarbons and ensures maximum vapour chamber growth along the full length of the horizontal vapour injector well than with traditional methods.
The embodiments of the process described above are examples. A person skilled in this art understands that variations and modifications of the process can be done without departing from the scope of the claims. Such variations and modifications fall within the scope of the present invention.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/CA07/01216 | 7/19/2007 | WO | 00 | 1/23/2009 |
| Number | Date | Country | |
|---|---|---|---|
| 60820129 | Jul 2006 | US | |
| 60895869 | Mar 2007 | US |
