CA2897686A1 - Hydrocarbon recovery process - Google Patents

Abstract

A process for facilitating hydrocarbon recovery from a hydrocarbon-bearing formation includes identifying a cold portion along a generally horizontal segment of a well utilized for hydrocarbon production, locating an electric heater in the well, at a location along the generally horizontal segment that corresponds to the identified cold portion, and heating the cold portion of the generally horizontal segment to improve inflow of hydrocarbons into the from a region of the formation near the cold portion.

Description

HYDROCARBON RECOVERY PROCESS
Technical Field [0001] The present invention relates to the production of hydrocarbons such as heavy oils and bitumen from an underground reservoir by heating the reservoir to mobilize the hydrocarbons.
Background

[0002] Extensive deposits of viscous hydrocarbons exist around the world, including large deposits in the Northern Alberta oil sands that are not susceptible to standard oil well production technologies. One 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.
For such reservoirs, thermal techniques may be used to heat the reservoir to mobilize the hydrocarbons and produce the heated, mobilized hydrocarbons from wells.
One such technique for utilizing a horizontal well for injecting heated fluids and producing hydrocarbons is described in U.S. Patent No. 4,116,275, which also describes some of the problems associated with the production of mobilized viscous hydrocarbons from horizontal wells.

[0003] One thermal method of recovering viscous hydrocarbons using spaced horizontal wells is known as steam-assisted gravity drainage (SAGD). SAGD
utilizes gravity in a process that relies on density difference of the mobile fluids to achieve a desirable vertical segregation within the reservoir. 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, pressurized steam is delivered through an upper, horizontal, injection well into a viscous hydrocarbon reservoir while hydrocarbons are produced from a lower, parallel, horizontal, production well that is near the injection well and is vertically spaced from the injection well. The injection and production wells are typically situated in the lower portion of the reservoir, with the producer located close to the base of the hydrocarbon deposit to collect the hydrocarbons that flow toward the bottom.

[0004] The SAGD process is believed to work as follows. The injected steam initially mobilizes the hydrocarbons to create a steam chamber in the reservoir around and above the horizontal injection well. The term steam chamber is utilized to refer to the volume of the reservoir that is saturated with injected steam and from which mobilized oil has at least partially drained. As the steam chamber expands, viscous hydrocarbons in the reservoir are heated and mobilized and move with aqueous condensate, under the effect of gravity, toward the bottom of the steam chamber, where the viscous hydrocarbons and aqueous condensate accumulate such that the liquid /
vapour interface is located below the steam injector and above the producer.
The heated hydrocarbons and aqueous condensate are collected and produced from the production well.

[0005] The steam chamber generally does not expand uniformly, from the steam injection well, over the length of the well pair. Consequently, the steam chamber grows irregularly. Steam is generally more mobile than the viscous hydrocarbons and other fluids. Steam and water develop flow paths and these flow paths are favored by the steam injected and the condensed water, reducing the effectiveness of the steam in heating other regions in the reservoir. Low recovery efficiency of hydrocarbons from oil reservoirs is common and, in large part, is due to this difference in viscosity between the viscous hydrocarbons and the steam and aqueous condensate.

[0006] Pressure loss in the horizontal segment of the injection well, inefficiencies in start-up operations and heterogeneities in the reservoir may also contribute to the irregular growth of the steam chamber, also known as poor conformance in the SAGD
process.

[0007] Attempts to improve conformance include the installation of various types of tubing strings in the injection well and the production well, and the installation of inflow control devices on one or both of the SAGD injection well and the production well.
Multiple tubing strings may be utilized to control inflow and oufflow at various locations along the horizontal length of the SAGD well pair. Further improvements to increase uniformity of steam chamber growth and fluid flow are desirable.

Summary

[0008] According to an aspect of an embodiment, a process is provided for facilitating hydrocarbon recovery from a hydrocarbon-bearing formation. The process includes identifying a cold portion along a generally horizontal segment of a well utilized for hydrocarbon production, locating an electric heater in the well, at a location along the generally horizontal segment that corresponds to the identified cold portion, and heating the cold portion of the generally horizontal segment to improve inflow of hydrocarbons into the well from a region of the formation near the cold portion.
Brief Description of the Drawings

[0009] Embodiments of the present invention will be described, by way of example, with reference to the drawings and to the following description, in which:

[0010] FIG. 1 is a sectional view through a reservoir, illustrating a SAGD well pair;

[0011] FIG. 2 is a sectional side view illustrating a SAGD well pair including an injection well and a production well;

[0012] FIG. 3 is a flowchart illustrating a process for facilitating hydrocarbon recovery from a hydrocarbon-bearing formation;

[0013] FIG. 4 is a sectional side view illustrating a production well according to an embodiment;

[0014] FIG. 5 is a sectional side view illustrating a production well according to another embodiment;

[0015] FIG. 6 is an illustration of a simulation grid showing porosity and well locations;

[0016] FIG. 7 is an illustration, in section view, of the temperature profile of an intermediate well as modeled on January 1, 2019 (5 years after the start of an adjacent SAGD well pair), where a cool portion is located at about the center of the simulated intermediate well and where the cool portion is heated with a heater in the intermediate well;

[0017] FIG. 8 is an illustration, in section view, of the temperature profile of an intermediate well as modeled on January 1, 2019 (5 years after the start of an adjacent SAGD well pair), where a cool portion is located at about the center of the simulated intermediate well and where the cool portion is not heated with a heater in the intermediate well;

[0018] FIG. 9 is an illustration, in section view, of the temperature profile of the intermediate well of FIG. 7 on April 1, 2020, (6 years and 4 months after the start of production through the adjacent SAGD well pair);

[0019] FIG 10 is an illustration, in section view, of the temperature profile of the intermediate well of FIG. 8 on April 1, 2020, (6 years and 4 months after the start of production through the adjacent SAGD well pair);

[0020] FIG. 11 is a graph illustrating the simulated rate of oil production through the intermediate well vs. time for the simulations illustrated in FIGs 6-10;
and

[0021] FIG. 12 is a graph illustrating the simulated cumulative oil produced through the intermediate well vs. time for the simulations illustrated in FIGs 6-10.
Detailed Description

[0022] For simplicity and clarity of illustration, reference numerals may be repeated among the figures to indicate corresponding or analogous elements.
Numerous details are set forth to provide an understanding of the examples described herein. The examples may be practiced without these details. In other instances, well-known methods, procedures, and components are not described in detail to avoid obscuring the examples described. The description is not to be considered as limited to the scope of the examples described herein.

[0023] The disclosure generally relates to a process for facilitating hydrocarbon recovery from a hydrocarbon-bearing formation. The process includes identifying a cold portion along a generally horizontal segment of a well utilized for hydrocarbon production, locating an electric heater in the well, at a location along the generally horizontal segment that corresponds to the identified cold portion, and heating the cold portion of the generally horizontal segment to improve inflow of hydrocarbons into the well from a region of the formation near the cold portion.

[0024] Throughout the description, reference is made to an injection well and a production well. The injection well and the production well may be physically separate wells. Alternatively, the production well and the injection well may be housed, at least partially, in a single physical wellbore, for example, a multilateral well.
The production well and the injection well may be functionally independent components that are hydraulically isolated from each other, and housed within a single physical wellbore.

[0025] As described above, a steam assisted gravity drainage (SAGD) process may be utilized for mobilizing viscous hydrocarbons. In the SAGD process, a well pair, including a hydrocarbon production well and a steam injection well are utilized. One example of a well pair is illustrated in FIG. 1 and an example of a hydrocarbon production well 100 is illustrated in FIG. 2. The hydrocarbon production well includes a generally horizontal segment 102 that extends near the base or bottom 104 of the hydrocarbon reservoir 106. The injection well 108 also includes a generally horizontal segment 110 that is disposed generally parallel to and is spaced vertically above the horizontal segment 102 of the hydrocarbon production well 100.

[0026] During SAGD, steam is injected into the injection well 108 to mobilize the hydrocarbons and create a steam chamber 112 in the reservoir 106, around and above the generally horizontal segment 110. In addition to steam injection into the steam injection well, light hydrocarbons, such as the C3 through C10 alkanes, either individually or in combination, may optionally be injected with the steam such that the light hydrocarbons function as solvents in aiding the mobilization of the hydrocarbons.
The volume of light hydrocarbons that are injected is relatively small compared to the volume of steam injected. The addition of light hydrocarbons is referred to as a solvent-assisted process (SAP). Alternatively, or in addition to the light hydrocarbons, various non-condensing gases, such as methane or carbon dioxide, may be injected.
Viscous hydrocarbons in the reservoir are heated and mobilized and the mobilized hydrocarbons drain under the effect of gravity. Fluids, including the mobilized hydrocarbons along with aqueous condensate, are collected in the generally horizontal segment 102. The fluids may also include gases such as steam and production gases from the SAGD

process.

[0027] As recovery progresses, the efficiency of recovery may decline in part due to the non-uniform displacement of the hydrocarbons by the steam and by the resulting aqueous condensate.

[0028] A flowchart illustrating a process for facilitating hydrocarbon recovery from a hydrocarbon-bearing formation is shown in FIG. 3. The process is carried out in a hydrocarbon reservoir, such as the reservoir 106. The process may contain additional or fewer processes than shown or described, and may be performed in a different order.

[0029] The reservoir is analyzed at 302. For example, the reservoir may be analyzed at 302 by monitoring reservoir characteristics, such as temperature.
For example, the reservoir may be monitored utilizing a fiber-optic cable that extends through the hydrocarbon production well to obtain a real-time temperature profile across the generally horizontal segment of the hydrocarbon production well.
Alternatively or additionally, the inflow of fluids into the generally horizontal segment can be monitored to identify portions in which fluid inflow is low. Alternatively or additionally, seismic surveys may be utilized to obtain indications of steam chamber growth or temperature across the reservoir and across the hydrocarbon production well.

[0030] Alternatively, the reservoir may be analyzed at 302 by modelling or simulation of reservoir conditions, for example, over a period of production such as a few years of SAGD production.

[0031] Cold spots or cold portions are identified at 304. The cold spots or cold portions may be spots or portions along the hydrocarbon production well that are identified at 304. The cold portions along the hydrocarbon production well may be identified based on the temperature profile or the inflow characteristics, or a combination thereof. Cold portions may also be identified by prediction based on simulation, seismic survey results, geological and geophysical analysis of the reservoir, or any combination thereof.

[0032] A cold portion may be identified by identifying the coldest temperature across the hydrocarbon production well or the temperature that is the lowest measured temperature, by comparing measured temperatures to an average temperature, by comparing the measured temperature to a threshold temperature, or in any other suitable manner. Alternatively, a cold portion may be identified by identifying portions in which fluid inflow into the generally horizontal segment of the production well is low by comparison to other parts of the generally horizontal segment of the production well.

[0033] Alternatively, cold portions in the reservoir may be identified at 304 to facilitate the identification of a location for an intermediate well that is located between two well pairs for the collection of mobilized hydrocarbons in a hydrocarbon recovery process. Such a well is also utilized for production and may be referred to as an infill well or a well drilled using Wedge WeIITM technology. The cold spot or spots may be identified utilizing, for example, the simulation data and the intermediate well may be drilled based on the location of the cold portion or cold spots for subsequent heating.

[0034] An electric heater is located in the production well or the additional, intermediate well at 306. The heater is located at a location along the generally horizontal segment of the production well or a generally horizontal segment of the intermediate well that corresponds to the location of the identified cold portion.

[0035] The heater is operated to heat the cold portion at 308. Thus, the heater is utilized to heat the cold portion to increase uniformity of heating across the horizontal segment of the production well or intermediate well. The length of time that the heater is utilized to heat the cold portion at 308 is based on several factors and may be determined by continuing to monitor the reservoir during heating. Analysis may be carried out, for example, by monitoring utilizing fiber optic cable, thermocouples, temperature sensors, observation wells, numerical simulation, or any combination of these monitoring devices and methods. Thus, the reservoir may be analyzed or monitored and heating continues until the identified cold portion is heated or until heating is predicted to have occurred. Fluid may be circulated in the production well or intermediate well during heating. For example, water may be circulated and the water flashes into steam in the area of the electric heater to cause steam chamber growth in the region of the cold portion.

[0036] A sectional side view illustrating an example of a production well is shown in FIG. 4 and described below with continued reference to FIG. 3. As shown in FIG. 4, the production well 100 includes the generally horizontal segment 102.
Optionally, an electric submersible pump (ESP) 402 may be utilized to pump produced fluids, including hydrocarbons, to the wellhead. An ESP 402 may be utilized, for example, when fluids do not naturally flow to the surface or do not naturally flow at a sufficient rate.
Alternatively, other artificial lift apparatus such as a rod pump, progressive cavity pump or gas lift may be utilized to pump produced fluids, including hydrocarbons, to the wellhead when fluids do not naturally flow to the surface or do not naturally flow at a sufficient rate.

[0037] During production, the reservoir is monitored 302 and cold portions along the generally horizontal segment 102 of the production well 100 are identified 304. In the example illustrated in FIG. 4, a cold portion is identified. The production is discontinued and an electric heater 404 is located 306 in the generally horizontal segment 102, at a location that corresponds to the location of the cold portion. The heater 404 is operated 308 to heat the cold portion to improve inflow of the hydrocarbons into the production well 100 from the region of the formation that is near the cold portion. The electric heater 404 may be disposed in a tubing string and may be operated inside the tubing string or a tubing string may be selectively heated. In this example, hydrocarbon production is not carried out during locating the heater 404 and during heating. When heating is completed, the electric heater 404 is removed by pulling the heater from the hydrocarbon production well 100 and hydrocarbon production is resumed.

[0038] Alternatively, hydrocarbon production may continue during localized heating. In the example of FIG. 4, two separate tubing strings, including the production tubing string 406 that is coupled to the ESP 402, and the electric heater tubing string 408 in which the electric heater is located, are utilized. Because the electric heater 404 in the present example is located in an electric heater tubing string 408, which is separate from the production tubing string 406, production can continue while selectively heating at a location or locations along the generally horizontal segment 102 of the production well 100.

[0039] A cold portion is identified 304. Hydrocarbon production continues while an electric heater 404 in the electric heater tubing string 408 is located 306 in the generally horizontal segment 102, at a location that corresponds to the location of the cold portion. The electric heater 404 is operated 308 to heat the cold portion to thereby improve inflow of the hydrocarbons into the production well 100 from the region of the formation that is near the cold portion.

[0040] A sectional side view of yet another example of a production well is shown in FIG. 5 and is described below with continued reference to FIG. 3. In the example of FIG. 5, an electric heater 504 is coupled to production tubing 506, in the same string.
Optionally, an ESP 502 may be utilized to increase flow of fluids to the surface.

[0041] A cold portion is identified 304. Hydrocarbon production continues while the electric heater 504 is located 306 in the generally horizontal segment 102, at a location that corresponds to the location of the cold portion. Thus, the electric heater 504 is selectively located for heating at a cold portion along the horizontal section 102 of the production well 100. The electric heater 504 is operated 308 to heat the cold portion to thereby improve inflow of the hydrocarbons into the production well 100 from the region of the formation that is near the cold portion. In the present example, the electric heater 504 is located and is used to selectively heat a cold portion while producing hydrocarbons. Thus, fluids are continuously produced from the production well during heating.

[0042] In the above-described embodiments, the heater is located in a production well. The heater may be located in any well through which hydrocarbons are produced.
For example, the heater may be located in a production well of a well pair, such as a well pair utilized in SAGD or in a solvent aided process. Alternatively, the heater may be located in a single well that is located between two well pairs for the collection of mobilized hydrocarbons in a hydrocarbon recovery process. Such a single well is also referred to as an infill well, an intermediate well, or a well drilled using Wedge WeIITM
technology.

[0043] Computationally Simulated Oil Production

[0044] An exemplary process according to the present disclosure was computationally simulated using a mathematical model of a reservoir. This exemplary process was compared to a computational simulation of a process that lacks a heater.

[0045] Details of the simulated reservoir are as follows:

[0046] Simulation Grid

[0047] A half element of symmetry was employed to ensure faster run times. The model had 33 m pay, an 800 m long well. There was 31 m of overburden and 31 m underburden. Grid dimensions were 25 x 210 x 33. Block dimensions for the main reservoir were as follows:

[0048] I ¨ direction: lm 24*2 m lm (26 blocks, total length of 50 m)

[0049] J ¨ direction: 16*50m (16 blocks, total length of 800 m)

[0050] K ¨ direction: 16 m8m4m2m 35*1 m2m4m8m 16 m (41 blocks, total length of 93 m).

[0051] Simulated Wells

[0052] In the simulated intermediate well having a heater, the intermediate well was located 50 m laterally away from a SAGD well pair. The heater in the intermediate well was turned on for 1 year, starting 5 years after the SAGD well pair starts to operate, with a maximum temperature of 180 C and maximum power input of 300 kW. The SAGD production well and offset intermediate well were in the plane.

[0053] In the simulated intermediate well lacking a heater, the intermediate well was located 50 m laterally away from a SAGD well pair, and the SAGD production well and offset intermediate well were in the plane.

[0054] At the start of the simulations for both wells, there is a portion in the center of the intermediate well, at about the 400-500m interval, that is cooler than the adjacent areas to the left and right. The general location of the cool portion is identified by a "*" in FIGs 7 and 8. Production of the intermediate well is started 5 years after the SAGD well pair starts to operate.

[0055] Reservoir Properties

[0056] The grid was populated using the following reservoir variables:
= Temperature = 12 C
= cl) =0.33 = Kh = 7.0 D
= Kv = 1.5 D
= Reference pressure of 2,400 kPa at the top of the SAGD pay = Sw = 0.20 = So = 0.80 = Mass Fraction Oil of Dead Oil = 0.89 = Mass Fraction Oil of CH4 = 0.11.

[0057] The thermal properties of the reservoir were characterized using two rock types. Rock type one represented clean sand and was used to populate a selected pay, representing the McMurray formation in Alberta, Canada. A second rock type representing shale was used to populate the over and underburden grid. The properties of the two rock types were defined with the following properties:

[0058] Rocktype 1 (Sand) = Porosity Reference Pressure = 100 kPa = Compressibility = le-6 1/kPa = Volumetric Heat Capacity 2.39e6 J/(m3*C) = Rock Thermal Conductivity = 196,820 J/(m*day*C) = Water Thermal Conductivity = 552,960 J/(m*day*C) = Oil Thermal Conductivity = 0 = Gas Thermal Conductivity = 0

[0059] Rocktype 2 (Shale Overburden & Underburden) = Porosity Reference Pressure = 100 kPa = Compressibility = 1e6 1/kPa = Volumetric Heat Capacity 2.39e6 J/(m3*C) = Rock Thermal Conductivity = 146,880 J/(m*day*C) = Water Thermal Conductivity = 0 = Oil Thermal Conductivity = 0 = Gas Thermal Conductivity = 0

[0060] Relative Permeability

[0061] The oil-water relative permeability curves have the following properties:
= Connate Water Saturation = 0.2 = Critical Water Saturation = 0.2 = Residual Oil Saturation = 0.15 = Irreducible Oil Saturation = 0.15 = Max relative water permeability = 0.559 = Max relative oil-water permeability = 0.95

[0062] The oil-gas relative permeability curves have the following properties:
= Critical Gas Saturation = 0.05 = Residual Liquid Saturation = 0.3 = Max relative gas permeability = 0.72 = Max relative oil-gas permeability = 0.95

[0063] Results of the simulated reservoirs are illustrated in FIGs. 11 and 12. At simulation time = 0 days, operation of the SAGD well pair is started. After 5 years (simulation time = approximately 1825 days), production through the offset, intermediate well is started. The heater in the exemplary simulated intermediate well is turned on for 1 year then the heater is turned off. The intermediate wells produce oil for a total of 5 years (simulation time = approximately 3650 days).

[0064] The heated intermediate well starts producing oil in less than 1 year of heating. As illustrated in FIG. 9, the heated intermediate well, as of April 1, 2020 (which corresponds to 1 year and 4 months of production), has vertical flow in the heated area and is 100% started.

[0065] The unheated intermediate well is not fully started until well after 1 year of the start. As illustrated in FIG. 10, there is no vertical flow in the cool zone and the unheated zone is not 100% started as of April 1, 2020 (which corresponds to 1 year and 4 months of production).

[0066] The described embodiments are to be considered in all respects only as illustrative and not restrictive. The scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole. All changes that come with meaning and range of equivalency of the claims are to be embraced within their scope.

Claims (13)

Claims

1. A process for facilitating hydrocarbon recovery from a hydrocarbon-bearing formation, the process comprising:
identifying a cold portion along a generally horizontal segment of a well utilized for hydrocarbon production;
locating an electric heater in the well, at a location along the generally horizontal segment that corresponds to the identified cold portion;
heating the cold portion of the generally horizontal segment to improve inflow of hydrocarbons into the well from a region of the formation near the cold portion.

2. The process according to claim 1, comprising circulating fluid into the well.

3. The process according to claim 1 or claim 2, comprising introducing steam into the formation at or near the cold spot by injecting water into the well while heating the cold portion.

4. The process according to any one of claims 1-3, wherein the cold portion comprises a portion at which a temperature is lower than an average temperature along the generally horizontal segment.

5. The process according to any one of claims 1-3, wherein the cold portion comprises a portion that has a temperature that is lower than a remainder of the generally horizontal segment.

6. The process according to any one of claims 1-5, comprising monitoring the generally horizontal segment of the well prior to identifying the cold portion.

7. The process according to claim 6, wherein monitoring comprises monitoring inflow along the generally horizontal segment.

8. The process according to claim 6, wherein monitoring comprises obtaining a temperature profile along the generally horizontal segment.

9. The process according to claim 6, wherein monitoring comprises seismically surveying the formation from a ground surface and wherein the cold portion is identified based on a seismic response.

10. The process according to any one of claims 1-9, wherein the cold portion is identified by prediction based on at least one of numerical simulation, seismic survey results, geological and geophysical analysis of the reservoir, and any combination thereof.

11. The process according to any one of claims 1-10, wherein locating in the well, the electric heater, comprises locating the heater in a heater string disposed in a wellbore of the well.

12. The process according to any one of claims 1-11, comprising recovering hydrocarbons from the reservoir through a hydrocarbon production string in the wellbore of the well.

13. The process according to claim 12, wherein recovering comprises utilizing artificial lift to lift the hydrocarbons to a wellhead of the well.