LI PINGKE (CA)
BAI YANG (CA)
| CA2869217A1 | 2015-04-30 | |||
| US20140332218A1 | 2014-11-13 | |||
| CA2875846A1 | 2015-03-04 | |||
| CA2853074A1 | 2015-11-30 |
| CLAIMS A thermal recovery method for extracting hydrocarbons from a hydrocarbon bearing reservoir based on the combination application of two types of thermal fluids generators, the method comprising, (a) introducing at least one conventional steam generator for generating steam; the steam quality, rate, pressure, and temperature can be changed within a certain range based on saturated steam characteristics; (b) introducing at least one proprietary controllable steam and C02 unit (CSCU) for generating multiple thermal fluids, including steam, C02, N2, and some liquid water; the steam quality, pressure, and temperature can be changed within a certain range based on saturated steam characteristics and Dalton's Law of partial pressures; (c) the proportion of the thermal fluids from each generator, which can vary from 0% to 100% in the combined multiple thermal fluids system; if the proportion of the thermal fluids from (a) is 0%, then the proportion of the thermal fluids from (b) is 100% and C02 and N2 is maximum; if the proportion of the thermal fluids from (a) is 100%, then the proportion of the thermal fluids from (b) is minimum (0%) and C02 and N2 will not exist in the system; if the proportion of the thermal fluids from (a) is between 0% and 100%), then the proportion of the thermal fluids from (b) is between 100% and 0% and the C02 and N2 content in the combined thermal fluids system is between maximum and zero; (d) injecting the mixed thermal fluids from (a) and (b) into the hydrocarbon bearing formation for developing the hydrocarbons. The method of claim 1 wherein the hydrocarbon is heavy oil or bitumen. The method of claim 1 wherein the combined thermal fluids from (a) and (b) can be injected into at least one well, whose type includes but not limit to horizontal, or vertical, or slanted, or deviated well, to soak for a period of time and then open to produce; when production rate is below an defined economic level, the second cycle begins; this cyclic operations continue until no economic benefit can be obtained. The method of claim 1 wherein the combined thermal fluids from (a) and (b) can be applied in different stages of the steam assisted gravity drainage (SAGD) process, such as in the later stage for reducing heat loss to the overburden and/or during the wind-down process for reservoir pressure maintenance. The method of any one of claim 1 and 3 to 4 wherein the at least one injection well and/or the at least one production well contains at least one sensor at down hole. The method of any one of claim 1 and 3 to 4 wherein the at least one injection well contains at least one sensor at well head. The method of any one of claim 1 and 3 to 4 wherein the surface separation system can provide gas and vapor samples. The method of claim 5 wherein the at least one sensor is a temperature sensor. The method of claim 5 wherein the at least one sensor is a pressure sensor. The method of claim 6 wherein the at least one sensor is a temperature sensor. The method of claim 6 wherein the at least one sensor is a pressure sensor. The method of claim 1 wherein the flow meters are installed on both (a) and (b). The method of claim 1 wherein a number of observation wells can be drilled in the target reservoir and they are some distance away from the injection/production wells. This distance is determined based on reservoir and engineering studies. The method of claim 1 and 13 wherein at least one pressure sensor and at least one temperature sensor are installed in those observation wells at down hole in order to monitor the pressure and temperature variations inside the reservoir. The method of claims 7-14 wherein all data can be metered, measured, monitored, collected, summarized, and analyzed by the PLC. Then the corresponding operating parameters can be adjusted by the PLC to satisfy certain criteria in order to consistently maintain the predefined proportions of thermal fluids generated from both 1 (a) and 1 (b), as described in claim 1 (c). |
FIELD OF THE INVENTION
[001] The invention relates to the recovery, extraction, and production of hydrocarbons, including heavy oil and bitumen.
BACKGROUND
[002] Fossil fuels and hydrocarbon based energy sources are widely used in the world. A number of recovery processes have been investigated and applied for developing the heavy oil and bitumen resources, such as the oil sands found in Canada, Venezuela, China, and the United States.
[003] Methods that have been developed include non-thermal processes and thermal processes. Non-thermal processes include natural pressure depletion, water flooding, polymer flooding, and gas injection. Thermal processes include cyclic steam stimulation (CSS), steam flooding, steam assisted gravity drainage (SAGD), and in-situ combustion. [004] Non-thermal recovery processes have their major disadvantages. Natural pressure depletion may have low recovery factor and production rate; water flooding and polymer flooding consume a large quantity of water with low production rates; gas injection may have low recovery factor and rate with a high consumption of energy.
[005] The in-situ combustion process is cost-effective when building the surface facilities.
However, it is difficult to control the combustion development inside the reservoir.
[006] While SAGD can have a better production rate (as shown in Canadian Patent No. 1 130201 to Butler), the method consumes a large amount of water and its operating cost is high. Particularly during the later stage of the process, steam chamber widely contacts the base of the cap rock. As a result, a large amount of heat is lost to the overburden. In addition, over the wind-down process, steam injection is terminated and the steam chamber pressure gradually drops with the disappearance of the steam chamber. Moreover, due to the well alignment of the SAGD process, the method cannot be applied to develop the heavy oil and oil sands reservoirs thinner than 10 meters.
[007] While CSS can be applied to develop thinner reservoirs with higher production rate, the method is basically rely on the initial reservoir pressure. In the CSS process, oil viscosity reduction is only based on heating from the steam. Heat loss to the overburden and underburden is also huge. To improve the CSS recovery rate, companies has tested liquid solvent additions into the injected steam (as described in Canadian Patent No. 2342955 to Leaute et al.). However, the cost of the liquid solvent is high, which may limit its applications in the field.
[008] Steam flooding process can improve the heavy oil recovery factor significantly if the reservoir properties are appropriate for this process. Generally the heavy oil reservoir needs to pass the screen criteria for steam flooding process. Particularly, oil viscosity needs to be lower than 10,000 centipoise. Due to the steam overriding characteristics, heat loss to the overburden is significant.
[009] SAGD, CSS, and steam flooding utilize the conventional steam generators, which emit huge amount of greenhouse gas into the atmosphere. Meanwhile, a large quantity of heat is released into the atmosphere with the air emission process.
[0010] A need therefore exists for improving SAGD, CSS, and steam flooding processes to develop heavy oil and oil sands reservoirs. A solution that addresses, at least in part, the above and the other shortcomings is desired.
SUMMARY OF THE INVENTION
[0011] The invention is related to a method of recovering hydrocarbons based on SAGD, or CSS, or steam flooding well operations. The composition of the injected thermal fluids can be controlled and adjusted based on two types of thermal fluids generators. One type is the conventional steam generator and the other type is the proprietary controllable steam and C0 2 unit (CSCU).
[0012] According to one embodiment of the invention, the conventional steam generator produces steam with a certain steam quality; the CSCU produces steam with certain steam quality, small amount of liquid water, C0 2 , and N 2 .The two streams of thermal fluids from both conventional steam generator and CSCU are mixed based on pre-designed proportions. Then, they are all injected into a heavy oil or an oil sands reservoir.
[0013] According to another embodiment of the invention, the proportions of thermal fluids from conventional generator can range from 0% to 100%; correspondingly, the thermal fluids from CSCU can range from 100% to 0%. At a certain time, proportions of thermal fluids from both generators are fixed. [0014] According to one aspect of the invention, there is provided a method for recovering hydrocarbons from a heavy oil or oil sands reservoir based on the following major mechanisms: oil viscosity reduction by heating, oil viscosity reduction by C0 2 dissolution in oil, and reservoir energy increase and maintenance by N 2 injection.
[0015] According to another aspect of the invention, there is provided a method to reduce heat loss to the overburden of the reservoir by C0 2 and N 2 injection, which spreads beneath the cap rock and acts like an insulation layer.
[0016] According to another aspect of the invention, there is provided a method of extracting hydrocarbons wherein the hydrocarbon viscosity ranges from 1,000 centipoise to over 1,000,000 centipoise. [0017] According to another aspect of the invention, there is provided a method of extracting hydrocarbons wherein the SAGD, or CSS, or steam flooding operation mode is applied with the injection of the combined thermal fluids.
[0018] According to another aspect of the invention, there is provided a method of combining the two streams of thermal fluids from two generators wherein additional combination equipment, such as a buffer tank, may or may not be used.
[0019] According to another aspect of the invention, there is provided a method of extracting hydrocarbons wherein at least one injection well and at least one production well contains at least one sensor at the down hole. [0020] According to another aspect of the invention, there is provided a method of extracting hydrocarbons wherein at least one injection well and at least one production well contains at least one temperature sensor at the down hole.
[0021] According to another aspect of the invention, there is provided a method of extracting hydrocarbons wherein at least one injection well and at least one production well contains at least one pressure sensor at the down hole. [0022] According to another aspect of the invention, there is provided a method of extracting hydrocarbons wherein at least one injection well and at least one production well contains at least one sensor at the well head.
[0023] According to another aspect of the invention, there is provided a method of extracting hydrocarbons wherein at least one injection well and at least one production well contains at least one temperature sensor at the well head.
[0024] According to another aspect of the invention, there is provided a method of extracting hydrocarbons wherein at least one injection well and at least one production well contains at least one pressure sensor at the well head.
[0025] According to another aspect of the invention, there is provided a method of extracting hydrocarbons wherein at least one flow meter is installed at the conventional steam generator for metering steam injection rate.
[0026] According to another aspect of the invention, there is provided a method of extracting hydrocarbons wherein at least three flow meters are installed at the CSCU for metering water flow rate, air flow rate, and fuel flow rate, respectively. [0027] According to another aspect of the invention, there is provided a method of extracting hydrocarbons wherein at least one flow meter and at least one sampling point are installed at the test separator for metering and monitoring vapor (steam) production rate and gas (N 2 , C0 2 , CH 4 , and H 2 S) production rates.
[0028] According to another aspect of the invention, there is provided a method of extracting hydrocarbons wherein all injection wells have additive (chemicals or corrosion inhibitors) co- injection settings at the well head. The additive injection rate is determined based on reservoir and production engineering studies.
[0029] According to another embodiment of the invention, there is provided a method of extracting hydrocarbons wherein proportional amount of thermal fluids generated from conventional steam 110 generator and CSCU can be adjusted automatically based on the criteria proposed from reservoir and production engineering studies.
[0030] According to another embodiment of the invention, there is provided a method of extracting hydrocarbons wherein if injection/production data collected through [0019] - [0029] do not satisfy the pre-defined criteria, automatic control program will tune the injection composition immediately.
115 [0031] According to another embodiment of the invention, there is provided a method of extracting hydrocarbons wherein observation wells are drilled some distance away from the
injection/production wells. Pressure and temperature sensors are installed inside the observation wells at the down hole to capture the reservoir pressure and temperature data over the injection and production phases.
120 [0032] All the metered, measured, sampled, and monitored data are sent to the programmable logic controller (PLC). The PLC is applied to analyze and adjust the operating parameters based on predefined criteria.
BRIEF DESCRIPTION OF THE DRAWINGS
125 [0033] For a further understanding of the nature and objects of the present invention, reference should be made to the following detailed description, taken in combination with the accompanying drawings, in which:
[0034] FIG. 1 is illustrating the working mechanism of the proprietary CSCU; and
[0035] FIG. 2 is an perspective view illustrating the combination of the thermal fluids generated 130 from conventional steam generator and CSCU according to an embodiment of the invention; and
[0036] FIG. 3 is a 3D view illustrating the method of extracting hydrocarbons based on the cyclic operation mode according to an embodiment of the invention; [0037] FIG. 4 is illustrating the method of extracting hydrocarbon based on the cyclic operation mode with a cross-section perpendicular to the horizontal wellbore in the reservoir; [0038] In the description which follows, like parts are marked throughout the specification and the drawings with the same respective reference numerals.
DETAILED DESCRIPTION OF THE EMBODIMNETS
[0039] The description which follows and the embodiments described therein are provided by way of illustration of an example or examples of particular embodiments of the principles of the present invention. There examples are provided for the purposes of explanation and not limitation of these principles and of the invention. In some instances, certain structures and techniques have not been described or shown in detail in order not to obscure the invention.
[0040] As part of this patent application, a number of terms are being used in accordance with what is understood to be the ordinary meetings of these terms. For instance, "fluid" includes both liquids and gases.
[0041] "Heavy Oil" is defined as petroleum having an American Petroleum Institute gravity below 22.3°API (920 to 1000 kg/m ). "Bitumen" is defined as petroleum existing in semi-solid and solid phases with a density of greater than 1000 kg/m 3 . While these terms are commonly used and are general categories, references to these terms in this application include the continuum of such substances and do not suggest some specific boundaries between the two substances. The term "heavy oil" includes within its scope "bitumen" of all forms.
[0042] "Petroleum" means mixtures consisting primarily of hydrocarbons in different phases, including liquid, gas, or solid phase. "Hydrocarbon" is an organic compound consisting entirely of hydrogen and carbon. In the context of this patent application, the words "petroleum" and
"hydrocarbon" refer to mixtures with significant variation in composition.
[0043] A reservoir is a formation underneath the surface that contains natural accumulation of hydrocarbons. [0044] Figure 1 is illustrating the CSCU working process. The water supply system 10 provides the 160 softened water, the fuel system 20 provides fuel (compressed natural gas or liquid fuel), and the air system 30 provides the compressed air to the CSCU 100. The CSCU products consist of steam, C0 2 , N 2 , and some liquid water.
[0045] In one embodiment, the combustion in the CSCU 100 may be started automatically by electronic igniter when the designed proportional amount of compressed air and fuel are injected 165 into the CSCU.
[0046] Figure 2 is illustrating the mixing of thermal fluids from both CSCU 100 and conventional steam generator 200. The preferred amount of thermal fluids generated from CSCU 100 and conventional steam generator 200 are mixed in the container 300.
[0047] In one embodiment, the volume of thermal fluids coming from CSCU 100 is controlled by 170 valve 110 and the volume of thermal fluids coming from the conventional steam generator 200 is controlled by valve 210. By controlling the volume of thermal fluids coming from the two generators, nitrogen concentrations in the mixed thermal fluids 300 may be reduced or increased.
[0048] In one embodiment, the mixture in the container 300 is injected into the injection well 400 based on pre-defined injection rate.
175 [0049] Figure 3 is illustrating the multiple thermal fluids injection into heavy oil or oil sands
reservoir. The thermal fluids reaches the horizontal wellbore 450 from the well head 400. The horizontal wellbore 450 is drilled in the reservoir 560 which is between the overburden 570 and underburden 580. The horizontal wellbore 450 is completed with slotted liner or wire wrapped screen liner or other preferred liner.
180 [0050] Figure 4 is a cross section normal to the horizontal wellbore. From both Figures 3 and 4, it is seen that the injected thermal fluids (steam, C0 2 , N 2 , and a small amount of liquid water) comes out of the horizontal wellbore 450 and are injected into the heavy oil or oil sands reservoir 560. Since reservoir is cold, the injected steam will condense when it enters the reservoir. However, the N 2 and C0 2 do not condense and they will propagate farther. Therefore, with continuous injection, mainly
185 three zones are formed in the reservoir 560. Zone 500 is mainly steam zone and zone 510 is non- condensable gas zone, which consists of N 2 and C0 2 . Zone 530 is mainly liquid water. Boundary 520 approximately separates steam zone 500 and liquid water zone 530. Inside boundary 460 is the entire impacted region by the injected thermal fluids.
[0051] Figure 3 shows two observation wells 420 in reservoir 560. Pressure and temperature sensors 190 are installed in these observations wells. Along the horizontal wellbore 450, temperature and/or
pressure sensors are also installed. At Well head 400, pressure and temperature sensors and flow meters are installed. Based on the flow rates, pressure, and temperature data, three zones' status (500, 510, and 530) is analyzed.
[0052] Through the analysis of three zones' status and horizontal well injection performance, the 195 proportions of thermal fluids coming from the two generators may be adjusted accordingly. The N 2 concentration in the mixture can be increased or decreased for optimizing the injection process.
[0053] According to another embodiment of the invention, the process monitoring, data collection, analysis, and adjusting described in [0051] and [0052] are automatically performed by the PLC.