HYDROCARBON PRODUCTION APPARATUS

Info

Publication number: 20150101794
Type: Application
Filed: Oct 13, 2014
Publication Date: Apr 16, 2015
Inventors: Christian Canas (Calgary), Subodh Gupta (Calgary), Simon Gittins (Calgary)
Application Number: 14/513,124

Abstract

An apparatus is disclosed for use in a hydrocarbon production well that includes a casing extending from a segment of the production well to a wellhead. A production conduit extends inside the casing, from a first end in the hydrocarbon production well to a second end at the wellhead. A receptacle includes a bottom spaced from the first end of the production conduit and at least one sidewall extending around a portion of the production conduit proximal the first end such that the receptacle extends around the first end of the production conduit. The receptacle includes an opening for liquid to pass into the receptacle to separate liquids from gases. A submersible pump is disposed in the production well and includes a motor outside the receptacle and coupled to a pump body inside the receptacle to pump the liquid from a pump inlet in the receptacle, through the production conduit to the second end.

Description

Description

INCORPORATION BY REFERENCE TO ANY PRIORITY APPLICATIONS

Any and all applications for which a foreign or domestic priority claim is identified in the Application Data Sheet as filed with the present application are hereby incorporated by reference under 37 CFR 1.57.

This application claims priority to U.S. Provisional Application Ser. No. 61/891,301, filed Oct. 15, 2013, the disclosure of which is incorporated herein by reference in its entirety.

BACKGROUND

1. Field of the Invention

The present invention relates to the production of hydrocarbons such as heavy oils and bitumen from underground deposits by artificial lifting of the fluid including the hydrocarbons.

2. Description of the Related Art

When a hydrocarbon reservoir lacks sufficient energy for oil, gas, and water to flow from wells at desired rates, supplemental production methods may be utilized. Gas and water injection for pressure support or secondary recovery may be utilized to maintain well productivity. When fluids do not naturally flow to the surface or do not naturally flow at a sufficient rate, a pump or gas lift techniques may be utilized, referred to as artificial lift. Lift processes transfer energy downhole or decrease fluid density in wellbores to reduce the hydrostatic load on formations, and cause inflow. Commercial hydrocarbon volumes can be boosted or displaced to the surface. Artificial lift also improves recovery by reducing the bottomhole pressure at which wells become uneconomic and are abandoned. Also, the development of unconventional resources such as viscous hydrocarbons usually include construction of complex wells, and high hydrocarbon lifting rates are desirable to produce oil quickly and efficiently at low cost.

Rod pump, gas lift, and electric submersible pumps are the most common artificial lift systems. Hydraulic and progressing cavity pumps are also utilized. Electric submersible systems use multiple centrifugal pump stages mounted in series within a housing, mated closely to a submersible electric motor on the end of tubing and connected to surface controls and electric power by an armor-protected cable. Submersible systems have a wide performance range. Standard surface electric drives power outputs from 100 to 30,000 barrels per day and variable-speed drives add pump-rate flexibility. High Gas Oil Ratio (GOR) fluids can be handled. Large gas volumes may lock up and destroy pumps, however. Submersible pumps may be operated at temperatures above 350° F. (177 C) utilizing special high-temperature motors and cables. High GOR, high-gas environments are now common in electric submersible pump applications. Reliable gas-handling technology is desirable to produce hydrocarbons utilizing pumps.

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. In some cases, such deposits are mined using open-pit mining techniques to extract hydrocarbon-bearing material for later processing to extract the hydrocarbons. Alternatively, 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. Pat. No. 4,116,275, the content of which is incorporated herein by reference in its entirety, 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 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. Pat. No. 4,344,485, the contents of each of which is incorporated herein by reference in its entirety. 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 that is vertically spaced and near the injection well. The injection and production wells are located close to the bottom of the hydrocarbon deposit to collect the hydrocarbons that flow toward the bottom.

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 upwardly and laterally from the injection well, viscous hydrocarbons in the reservoir are heated and mobilized, in particular, at the margins of the steam chamber where the steam condenses and heats the viscous hydrocarbons by thermal conduction. The heated hydrocarbons and aqueous condensate drain, under the effects of gravity, toward the bottom of the steam chamber, where the production well is located. The heated hydrocarbons and aqueous condensate are collected and produced from the production well.

When the pressure in the steam chamber is sufficiently high, the fluids produced, including liquids and gases naturally flow through the production well, to the surface. The gases may include vapor, or water in the form of steam, hydrocarbon gases, and other trace compounds. The liquid may include hydrocarbons, water, and other compounds. Artificial lift may be utilized along with the SAGD process to increase the flow rate from the production well. Electric submersible pumps may be utilized in the production well to facilitate the flow of the fluids to the surface. Such pumps, however, are susceptible to vapor locking, also referred to as air locking or gas locking, when the fluid in the pump intake is too high in gas phase.

Canadian patent 2,228,416 to Kisman, the content of which is incorporated herein by reference in its entirety, discloses a first conduit that is insulated and extends within the well, from the bottom of a hydrocarbon-bearing formation to a well head. The first conduit includes a port through which fluid enters the insulated conduit. A pump near the bottom of the first conduit pumps fluid from the bottom of the first conduit, through a second conduit that extends inside the first conduit, to the surface. Kisman aims to separate the gas and liquid phases upon entry into the first conduit and to avoid reheating of the separated liquid phase. The liquid phase is pumped through the second conduit to the surface and the gas phase moves to the surface through the first conduit. The Kisman apparatus utilizes additional conduits that run coextensive with the well and the length of the first conduit and the location of the port are extremely important to promote separation of the liquid and gases and avoid reheating of the separated liquids.

Improvements in apparatus for use with artificial lift are desirable.

SUMMARY

According to an aspect of an embodiment, an apparatus for use in a hydrocarbon production well includes a production well casing that extends from a segment of the hydrocarbon production well to a wellhead. The apparatus includes a production conduit extending inside the production well casing, from a first end located within the hydrocarbon production well to a second end at the wellhead. The apparatus also includes a receptacle including a receptacle bottom spaced from the first end of the production conduit and at least one receptacle sidewall extending around a portion of the production conduit proximal the first end such that the receptacle extends around the first end of the production conduit. The receptacle includes at least one opening for the passage of liquid into the receptacle to facilitate separation of the liquids from gases in the hydrocarbon production well. A submersible pump is disposed in the hydrocarbon production well and includes a motor disposed outside the receptacle and coupled to a pump body disposed inside the receptacle to pump the liquid from a pump inlet in the receptacle into the production conduit and through the production conduit to the second end. The apparatus may be utilized in any suitable hydrocarbon production well, including, for example, a SAGD production well.

BRIEF DESCRIPTION OF THE DRAWINGS

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

FIG. 1 is a sectional view through a reservoir, illustrating a steam-assisted gravity drainage (“SAGD”) well pair;

FIG. 2 is a side sectional view through a hydrocarbon production well including an apparatus for use in the well in accordance with an embodiment;

FIG. 3 is a side sectional view through a hydrocarbon production well including an apparatus for use in the well in accordance with another embodiment; and

FIG. 4 is a side sectional view through a hydrocarbon production well including an apparatus for use in the well in accordance with still another embodiment.

DETAILED DESCRIPTION

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.

The disclosure generally relates to an apparatus for use in a hydrocarbon production well that includes a production well casing that extends from a segment of the hydrocarbon production well to a wellhead. The apparatus includes a production conduit extending inside the production well casing, from a first end located within the hydrocarbon production well to a second end at the wellhead. The apparatus also includes a receptacle including a receptacle bottom spaced from the first end of the production conduit and at least one receptacle sidewall extending around a portion of the production conduit proximal the first end such that the receptacle extends around the first end of the production conduit. The receptacle includes at least one opening for the passage of liquid into the receptacle to facilitate separation of the liquids from gases in the hydrocarbon production well. A submersible pump is disposed in the hydrocarbon production well and includes a motor disposed outside the receptacle and coupled to a pump body disposed inside the receptacle to pump the liquid from a pump inlet in the receptacle into the production conduit and through the production conduit to the second end. The apparatus may be utilized in any suitable hydrocarbon production well, including, for example, a steam-assisted gravity drainage (“SAGD”) production well.

As described above, various hydrocarbon recovery processes, such as SAGD, are known for mobilizing viscous hydrocarbons. In the SAGD process, a well pair, including hydrocarbon production well and a steam injection well are utilized. One example of a well pair is illustrated in FIG. 1. The hydrocarbon production well 100 includes a generally horizontal segment 102 that extends near a base or bottom 104 of a hydrocarbon reservoir 106. The steam injection well 112 also includes a generally horizontal segment 114 that is disposed generally parallel to and is spaced vertically above the horizontal segment 102 of the hydrocarbon production well.

During SAGD, steam is injected into the steam injection well 112 to mobilize the hydrocarbons and create a steam chamber in the reservoir 106, around and above the generally horizontal segment 112. In addition to steam injection into the steam injection well 112, light hydrocarbons, such as ethane, propane or butane may optionally be injected with the steam. 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). Viscous hydrocarbons in the reservoir are heated and mobilized and the mobilized hydrocarbons drain, under the effects 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.

Artificial lift may be utilized to facilitate the flow of the heated hydrocarbons and aqueous condensate to the surface, for example, when the SAGD operation is carried out at sufficiently low pressure that artificial lift is required to recover mobilized hydrocarbon at the surface, or when increased rate of movement of the fluid from the well is desirable.

An embodiment of an apparatus 200 for use with a hydrocarbon production well, such as the hydrocarbon production well 100 illustrated in FIG. 1, is illustrated in FIG. 2. The hydrocarbon production well 100 includes the generally horizontal segment 102, which is a pipe, also referred to as a slotted liner, that is coupled to a production well casing 108, for example, by a liner hanger 116. The production well casing 108 extends from the generally horizontal segment 102 to the wellhead 110.

The apparatus 200 includes a production conduit 202 that extends inside the production well casing 108, from a first end 204 located within the hydrocarbon production well 100, near the liner hanger 116, to a second end 206 at the wellhead 110. The production conduit 202 is tubular and may extend generally concentrically with the production well casing 108.

A receptacle 210 is disposed around the first end 204 of the production conduit 202. The receptacle 210 includes a receptacle bottom 212 that is spaced from the first end 204 of the production conduit 202. In this example, the receptacle 210 includes a generally cylindrical sidewall 214 that extends from the receptacle bottom 212 and around a lower portion 216 of the production conduit 202 near the first end 204. The generally cylindrical sidewall 214 may extend generally concentrically with the production conduit 202. The receptacle 210 also includes an inwardly extending flange 218 that extends from an upper edge of the sidewall 214 to the production conduit 202. The inwardly extending flange 218 extends inwardly to the production conduit 202 to close the top of the receptacle 210. The sidewall 214 includes openings 219 in the inwardly extending flange 218, to allow the ingress of fluid and to facilitate the separation of the liquids from the gases in the hydrocarbon production well 100. The openings 219 may be any suitable size or shape to facilitate separation of liquids from the gases. A suitable length of the sidewall 214, or distance from the bottom 212 to the inwardly extending flange 218, is utilized to facilitate separation of liquids in the fluid. The inwardly extending flange 218 may couple the receptacle 210 to the production conduit 202. In this example, in which the receptacle 210 is coupled to the production conduit, the production conduit may be removed or extracted from the hydrocarbon production well 100 for cleaning. Specialized connections may be utilized to couple sections of the production conduit 202 to facilitate extraction for cleaning of the receptacle 210.

An electric submersible pump 220 is disposed in the hydrocarbon production well 100 and includes a pump motor 222 that is disposed outside of the receptacle 210, and a pump body 224 that is disposed inside the receptacle 210 and is coupled to the pump motor 222 by a shaft 230 that extends through the bottom 212 of the receptacle 210. A seal is utilized between the receptacle bottom 212 and the shaft 230 to inhibit the flow of fluid through the bottom 212 of the receptacle 210. Thus, the fluid in the hydrocarbon production well 100 is not in fluid communication with the liquid in the receptacle 210 through the bottom 212.

The pump body 224 includes inlets 226 disposed in the receptacle 210 and a discharge outlet 228 coupled to the first end 204 of the production conduit 202. The discharge outlet 228 is in fluid communication with the production conduit 202 to pump the liquid from the receptacle 210, through the pump inlets 226, may be spaced from the bottom 212 of the receptacle 210 or spaced from the lowest point in the receptacle 210 to provide a space into which solids may be deposited. Fluid is pumped through the pump inlets 226, into the production conduit 202, and upwardly to the second end 206 at the wellhead 110.

During the production of hydrocarbons, the fluid 234, including hydrocarbons along with aqueous condensate, flows into the generally horizontal segment 102 of the hydrocarbon production well 100. The fluid 234 flows into the production well casing 108 and upwardly, around the receptacle 210. The gases in the fluid rise, as illustrated by the arrows 236, and the liquids, illustrated by the arrows 238 enter the receptacle 210 through the openings 219. The liquids 238 are pumped, through the pump body 224, into the production conduit 202 and to the wellhead 110. The flow path of the liquids is therefore altered to generally separate the gases and cause the gases to flow upwardly while the liquids enter the receptacle 210. A small amount, or small volume, of gases may still enter the receptacle 210. The gases and the liquids separate because the liquids, which are the heavier of the fluids, typically settle and accumulate at the bottom of the production well casing 108. The level of the liquids may rise above the openings 219 in the receptacle 210 and the gases, which are the less heavy fluids, due to buoyancy and gravity segregation. The gases therefore travel toward the wellhead.

A SAGD production well is referred herein as one example of a production well in which the apparatus 200 may be utilized. Use of the apparatus 200 is not limited to a SAGD production well. Instead, the apparatus may be utilized in other production wells, including wells that utilize thermal techniques to mobilize hydrocarbons and in wells that utilize other techniques for recovery of hydrocarbons.

The heat supplied by the motor 222 heats the temperature of the gases in fluids that include dissolved gases, which assists in expelling the dissolved gases from the fluids outside the receptacle 210. When the separated liquids drop into the receptacle 210 and travel downwardly, even with some heat gain, the gas separation within the receptacle 210 is significantly reduced by comparison to gas separation near the intake of a pump without such a receptacle 210 because the fluids have already passed through a more thermodynamically favourable separation condition. The heat provided by the motor 222 also results in water vapours separating from fluids that include water and steam and the separated liquids fall into the receptacle 210. The temperature does not significantly increase when the water vapours separate because a phase change in a single component system occurs at a constant temperature. Because the temperature does not significantly increase, little further vaporization occurs within the receptacle 210.

Another embodiment of an apparatus 300 for use with a hydrocarbon production well, such as the hydrocarbon production well 100 illustrated in FIG. 1, is illustrated in FIG. 3. The hydrocarbon production well 100 includes the generally horizontal segment 102, which is a pipe, also referred to as a slotted liner 102 that is coupled to a production well casing 108, for example, by a liner hanger 116. The production well casing 108 extends from the generally horizontal segment 102 to the wellhead 110.

Many of the elements of the apparatus 300 are similar to those described above with reference to the apparatus 200 illustrated in FIG. 2 and are therefore not described again in detail. In the present example, the liner 102 of the hydrocarbon production well 100 extends past the liner hanger 116 and partly through the production well casing 108. A sealing element 312 is disposed in the liner 102 and forms a bottom of the receptacle 310. The end section of the liner hanger 116 forms the generally cylindrical sidewall 314 of the receptacle 310. In this embodiment, the receptacle 310 does not include an inwardly extending flange and the top of the receptacle 310 is open. Alternatively, the top of the receptacle 310 may include an inwardly extending flange.

The electric submersible pump 320 is disposed in the hydrocarbon production well 100 and includes the pump motor 322 that is disposed outside of the receptacle 310, and the pump body 324 that is disposed inside the receptacle 310 and is coupled to the pump motor 322 by a shaft 330 that extends through the sealing element 312 that acts as the bottom of the receptacle 310. The electric submersible pump 320 may extend through the sealing element 312 by stabbing the pump 320 through the sealing element 312. The sealing element 312 inhibits the flow of fluid through the bottom of and into the receptacle 310. Thus, the fluid in the hydrocarbon production well 100 is not in fluid communication with the liquid in the receptacle 310 through the sealing element 312.

As similarly described above with reference to FIG. 2, in FIG. 3 the pump body 324 includes inlets 326 disposed in the receptacle 310 and a discharge outlet 328 coupled to a first end 304 of the production conduit 302.

The liner 102 includes perforations 340 at locations below the sealing element 312 that act as the bottom of the receptacle 310 to facilitate the flow of fluid from the liner 102 and into the well casing 108.

During the production of hydrocarbons, a fluid 334, including hydrocarbons along with aqueous condensate, flows from the liner 102, through the perforations 340 into the production well casing 108 and upwardly, around the receptacle 310. The gases in the fluid rise, as illustrated by arrows 336, and the liquids, illustrated by arrows 338, enter the receptacle 310 through the open top. The liquids 338 are pumped, through the pump body 324, into the production conduit 302 and to the wellhead 110.

Yet another embodiment of an apparatus 400 for use with a hydrocarbon production well, such as the hydrocarbon production well 100 illustrated in FIG. 1, is illustrated in FIG. 4. Many of the elements of the apparatus 300 are similar to those described above with reference to the apparatus illustrated in FIG. 3 and are therefore not described again in detail.

In this example, a pipe 442 that is larger in diameter than the production conduit 402 and smaller in diameter than the well casing 108 is disposed in the well casing 108, near the liner hanger 116. The pipe 442 is coupled to the well casing 108 by additional packing elements 444 that maintain the pipe 442 in place. A sealing element 412 is disposed in the pipe 442 and forms a bottom of the receptacle 410. The end section of the pipe 442 forms the generally cylindrical sidewall 414 of the receptacle 410. In this embodiment, the receptacle 410 does not include an inwardly extending flange and the top of the receptacle 410 is open. Alternatively, the top of the receptacle 410 may include an inwardly extending flange.

The electric submersible pump 420 is disposed in the hydrocarbon production well 100 and includes the pump motor 422 that is disposed outside of the receptacle 410, and the pump body 424 that is disposed inside the receptacle 410 and is coupled to the pump motor 422 by a shaft 430 that extends through the sealing element 412 that acts as the bottom of the receptacle 410. The electric submersible pump 420 may extend through the sealing element 412 by stabbing the pump 420 through the sealing element 412. The sealing element 412 inhibits the flow of fluid through the bottom of and into the receptacle 410. Thus, the fluid in the hydrocarbon production well 100 is not in fluid communication with the liquid in the receptacle 410 through the sealing element 412.

As similarly described above with reference to FIG. 2, in FIG. 4 the pump body 424 includes inlets 426 disposed in the receptacle 410 and a discharge outlet 428 coupled to the first end 404 of the production conduit 402.

The pipe 442 includes perforations 440 at locations between the sealing element 412 and the additional packing elements 444 to facilitate the flow of fluid around the pipe 442 and upwardly in the well casing 108.

During the production of hydrocarbons, the fluid 434, including hydrocarbons along with aqueous condensate, flows from the liner 102, through the perforations 440 in the pipe 442 and upwardly, around the receptacle 410. The gases in the fluid rise, as illustrated by the arrows 436, and the liquids, illustrated by the arrows 438 enter the receptacle 410 through the open top. The liquids 438 are pumped, through the pump body 424, into the production conduit 402 and to the wellhead 110.

The following examples are submitted to further illustrate embodiments of the present invention. These examples are intended to be illustrative only and are not intended to limit the scope of the present invention. The examples are production results utilizing a proprietary computerized wellbore modeling simulator. The data shown is data from simulations. In each case, Source conditions are identified to approximate the temperature, pressure, and composition of fluids entering a typical production well in a SAGD operation. Heat losses along the wellbore were simulated.

Example 1

This example illustrates the simulated production results from the well casing and from the production conduit when a receptacle, such as the receptacle described in relation to FIG. 2, is utilized. As described, an electric submersible pump intake is disposed in the receptacle and the motor is disposed outside the receptacle, at the bottom thereof.

The source conditions utilized were:

Water Rate=300 t/d;

Oil Rate=150 t/d; and

Methane Rate=4.63 t/d.

The following constraints were identified:

Constraint Pressure: 6.5×10⁶Kpa; and

Constraint Rate: 454.628.

The simulated results from the production conduit were taken from a location disposed in the receptacle, spaced from the bottom but near the bottom of the receptacle. Results from the well casing were taken from a location disposed above the receptacle.

TABLE 1 Production Results Utilizing Receptacle properties Source Production Well Casing Time water bitumen methane water bitumen (days) (t) (t) (t) (t) (t) 0 0 0 0 0 0 30 0 0 0 0 0 30 0.251074 0.125537 0.003804 0.017116 0.000168 30 2.951564 1.475782 0.044721 0.017116 0.000168 30 15.04782 7.52391 0.227997 0.017482 0.000175 31 149.9783 74.98914 2.272398 0.029444 0.000203 31 300.0055 150.0027 4.545538 0.109525 0.000203 32 450.0327 225.0164 6.818678 0.443841 0.000203 32 600.06 300.03 9.091818 1.148552 0.000203 33 900.1144 450.0572 13.6381 3.51272 0.000203 34 1200.169 600.0845 18.18438 6.719242 0.000203 35 1500.223 750.1117 22.73066 10.61535 0.000203 36 1800.278 900.1389 27.27694 15.08798 0.000203 37 2100.333 1050.166 31.82322 19.56072 0.000203 40 3000.496 1500.248 45.46206 35.07769 0.000203 41 3300.55 1650.275 50.00834 40.42166 0.000203 45 4500.768 2250.384 68.19346 63.96322 0.000203 50 6001.041 3000.52 90.92486 96.49311 0.000203 51 6301.095 3150.548 95.47114 103.0815 0.000203 55 7501.313 3750.656 113.6563 130.4718 0.000203 60 9001.585 4500.792 136.3876 166.0904 0.000203 75 13502.4 6751.202 204.5819 281.2993 0.000203 100 21003.76 10501.88 318.2388 488.6925 0.000203 150 36006.49 18003.24 545.5529 932.1273 0.000204 200 51009.21 25504.61 772.8669 1395.694 0.000204 250 66011.94 33005.97 1000.181 1871.863 0.000204 300 81014.66 40507.33 1227.495 2358.739 0.000204 350 96017.38 48008.69 1454.809 2851.618 0.000204 400 111020.1 55510.05 1682.123 3351.248 0.000204 450 126022.8 63011.41 1909.437 3856.718 0.000204 500 141025.5 70512.77 2136.751 4365.749 0.000204 properties Production Well Casing Production Conduit Time methane water bitumen methane (days) (t) (t) (t) (t) 0 0 0 0 0 30 0 0 0 0 30 0.00020107 5.51722288 0.008301364 7.67765E−05 30 0.00020107 22.6429939 0.328802407 0.006175632 30 0.06229784 37.6143723 5.815367222 0.102503106 31 1.59127522 172.920517 73.45058441 0.639277458 31 3.44239831 322.887756 148.4755554 1.067141294 32 5.31504583 472.590057 223.4928131 1.470376372 32 7.20106697 621.920715 298.5088501 1.858973742 33 11.0056677 919.622864 448.5393677 2.602339506 34 14.8368645 1216.47961 598.5687866 3.31843257 35 18.6885223 1512.64441 748.5975342 4.013718128 36 22.5567207 1808.23071 898.6257935 4.692359447 37 26.4247627 2103.81689 1048.654297 5.37101841 40 38.0869789 2988.47241 1498.737915 7.348468781 41 41.9790764 3283.18359 1648.768066 8.002990723 45 57.6059151 4459.86719 2248.878418 10.56170273 50 77.222908 5927.61572 2999.015869 13.67611694 51 81.1485672 6221.08301 3149.042725 14.29676342 55 96.8743973 7393.91846 3749.152588 16.75188065 60 116.573494 8858.57617 4499.289063 19.78393745 75 175.873993 13244.207 6749.699219 28.66124725 100 275.118683 20538.1973 10500.38086 43.05823135 150 474.353149 35097.5078 18001.74414 71.12123871 200 674.040283 49636.7383 25503.10547 98.67886353 250 874.089783 64163.3203 33004.46875 125.921051 300 1074.3988 78679.2031 40505.83203 152.8976288 350 1274.88074 93189.0469 48007.19141 179.7246552 400 1475.5282 107692.148 55508.55469 206.3854065 450 1676.31519 122189.414 63009.91406 232.9029236 500 1877.19751 136683.109 70511.28125 259.332428

As illustrated in Table 1, after 500 days, the total bitumen from the source was 70512.77 tonnes. The total bitumen produced from the production conduit was 70511.28 tonnes. Very little bitumen is produced from the production well casing. After 500 days, the total methane gas from the source was 2136.75 tonnes. The total methane gas produced from the production well casing was 1877.20 tonnes. The total methane from the production conduit was 259.33 tonnes.

Thus, much of the liquids were produced through the production conduit and much of the gas was separated and produced through the production well casing.

Example 2

This example illustrates simulated production results from the well casing and from the production conduit when a receptacle is not present. Source conditions and constraints utilized were identical to those described above with reference to Example 1.

The simulated results from the production conduit were taken from the same location relative to the well casing as in Example 1 but no receptacle was present. Results from the well casing were taken from the same location as in Example 1.

TABLE 2 Production Results With No Receptacle properties Source Production Well Casing Production Conduit Time water bitumen methane water bitumen methane water bitumen methane (days) (t) (t) (t) (t) (t) (t) (t) (t) (t) 0.00 0 0 0 0 0 0 0 0 0 30.00 0 0 0 0 0 0 0 0 0 30.00 0.300054 0.150027 0.004546 0.077905 0.000767 0.000888 0.30685 1.67E−05 1.42E−05 30.01 3.000545 1.500273 0.045463 0.109755 0.001081 0.001069 6.255856 0.504917 0.015642 30.50 150.0272 75.01362 2.27314 0.156757 0.001083 0.430157 163.5936 73.83548 1.769217 31.00 300.0545 150.0272 4.54628 0.348671 0.001083 1.009318 313.6732 148.8664 3.467092 31.50 450.0817 225.0409 6.81942 0.642781 0.001083 1.593243 463.4849 223.8853 5.157238 32.00 600.1089 300.0545 9.09256 1.005043 0.001083 2.180041 613.2172 298.8895 6.844394 33.00 900.1635 450.0817 13.63884 1.888396 0.001083 3.359571 912.5569 448.8376 10.21134 34.00 1200.218 600.1089 18.18512 2.981142 0.001083 4.546077 1211.738 598.709 13.57132 35.00 1500.272 750.1362 22.7314 4.073924 0.001083 5.732541 1510.918 748.5804 16.93133 36.00 1800.327 900.1635 27.27768 5.166698 0.001083 6.919005 1810.099 898.4517 20.29135 37.00 2100.381 1050.191 31.82396 6.259464 0.001083 8.105469 2109.279 1048.323 23.65137 40.00 3000.545 1500.272 45.4628 10.21471 0.001083 11.68563 3006.325 1497.696 33.70915 41.00 3300.599 1650.3 50.00908 11.58594 0.001083 12.88055 3305.302 1647.469 37.05997 45.00 4500.817 2250.408 68.19421 17.58536 0.001083 17.67924 4500.845 2246.383 50.44468 50.00 6001.089 3000.545 90.9256 25.50557 0.001083 23.69952 5995.055 2994.924 67.15402 51.00 6301.144 3150.572 95.47189 27.05603 0.001083 24.90382 6293.965 3144.668 70.49548 55.00 7501.362 3750.681 113.657 32.86282 0.852873 29.73366 7489.076 3743.377 83.84832 60.00 9001.634 4500.817 136.3884 40.39681 3.010169 35.79669 8981.937 4491.253 100.516 75.00 13502.45 6751.226 204.5826 64.32987 10.47331 54.04676 13458.94 6734.112 150.4607 100.00 21003.81 10501.91 318.2396 106.4586 24.16001 84.56349 20918.25 10471.06 233.6012 150.00 36006.54 18003.27 545.5536 194.9442 53.68817 145.7794 35832.58 17942.85 399.6823 200.00 51009.26 25504.63 772.8676 287.0654 85.02808 207.1438 50743.23 25412.86 565.6212 250.00 66011.98 33005.99 1000.182 381.5346 117.5289 268.6006 65651.52 32881.71 731.4697 300.00 81014.71 40507.36 1227.496 477.5292 150.7812 330.1155 80558.27 40349.81 897.2678 350.00 96017.43 48008.71 1454.81 573.8802 184.2078 391.6404 95464.66 47817.73 1063.057 400.00 111020.2 55510.08 1682.124 670.231 217.6342 453.1653 110371 55285.66 1228.845 450.00 126022.9 63011.44 1909.438 766.5814 251.0619 514.6907 125277.4 62753.59 1394.635 500.00 141025.6 70512.8 2136.751 862.9318 284.4959 576.2169 140183.8 70221.52 1560.423

As illustrated in Table 2, after 500 days, the total bitumen from the source was 70512.8 tonnes. The total bitumen produced from the production conduit was 70221.52 tonnes. The total bitumen produced from the production well casing was 284.50 tonnes. After 500 days, the total methane gas from the source was 2136.75 tonnes. The total methane gas produced from the production well casing was 576.22 tonnes. The total methane from the production conduit was 1560.42 tonnes.

Thus, a much greater percentage of gas is produced through the production conduit than in Example 1. Gas separation is greatly improved and less gas enters the electric submersible pump in Example 1. Similar advantages are expected utilizing other embodiments of the receptacles, such as those shown in FIG. 3 and FIG. 4.

Advantageously, the motor 222 of the electric submersible pump 220 is disposed outside of the receptacle 210. Heat generated from the motor 222 raises the temperature of the fluid, which may include gases and liquid outside of the receptacle 210. Also, electric submersible pumps heat up during use in a hydrocarbon production well, which may reduce the life of the pump. By locating the motor 222 outside of the receptacle 210, the motor 222 is cooled by a large volume of fluid from the hydrocarbon production well. Thus, a large volume of fluid may be utilized to exchange heat with the pump and thereby cool the motor. Less heat is generated inside the receptacle. Optionally, all or part of the receptacle 210 may be insulated to reduce heat transfer through the receptacle 210, to the liquid in the receptacle 210. In one example, the bottom 212 of the receptacle 210 may be insulated to reduce heating of the liquid in the receptacle 210 by, for example, the pump motor 222. The insulation, however, is not required and the receptacle 210 may be advantageously utilized without insulation. Furthermore, only one production conduit is utilized and may be located generally concentrically within the production casing. The use of a packer is not necessary.

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

1. An apparatus for use in a hydrocarbon production well that includes a production well casing that extends from a segment of the hydrocarbon production well to a wellhead, the apparatus comprising:

a production conduit extending inside the production well casing, from a first end located within the hydrocarbon production well to a second end at the wellhead;

a receptacle including a receptacle bottom spaced from the first end of the production conduit and at least one receptacle sidewall extending around a portion of the production conduit proximal the first end such that the receptacle extends around the first end of the production conduit, the receptacle including at least one opening therein for the passage of liquid into the receptacle to facilitate separation of the liquids from gases in the hydrocarbon production well; and

a submersible pump disposed in the hydrocarbon production well and comprising a motor disposed outside the receptacle and coupled to a pump body disposed inside the receptacle to pump the liquid from a pump inlet in the receptacle into the production conduit and through the production conduit to the second end.

2. The apparatus according to claim 1, wherein the pump body is coupled to the motor by a coupling that extends through the receptacle bottom.

3. The apparatus according to claim 2, wherein fluid in the hydrocarbon production well is not in fluid communication with the liquid in the receptacle through the receptacle bottom.

4. The apparatus according to claim 1, wherein the receptacle comprises an inwardly extending flange that extends from an upper edge of the receptacle sidewall.

5. The apparatus according to claim 4, wherein the inwardly extending flange extends inwardly to the production conduit.

6. The apparatus according to claim 5, wherein the inwardly extending flange includes at least one opening to facilitate the flow of liquid into the receptacle.

7. The apparatus according to claim 1, wherein the receptacle sidewall is generally cylindrical.

8. The apparatus according to claim 1, wherein the receptacle sidewall is generally concentric with the production conduit

9. The apparatus according to claim 1, wherein the receptacle sidewall is generally concentric with the production well casing.

10. The apparatus according to claim 1, wherein a top of the receptacle is open to facilitate the flow of liquid into the receptacle.

11. The apparatus according to claim 1, wherein the receptacle sidewall is comprised of a top portion of the segment of the hydrocarbon production well and the bottom is comprised of a sealing element disposed in the segment.

12. The apparatus according to claim 11, wherein the segment of the hydrocarbon production well includes openings between the sealing element and a bottom of the production well casing to facilitate the flow of fluid from the segment, around the receptacle.

13. The apparatus according to claim 1, wherein the receptacle sidewall is comprised of a portion of a pipe disposed in the production well casing and the bottom is comprised of a sealing element disposed in the pipe.

14. The apparatus according to claim 13, wherein the pipe is coupled to the production well casing by at least one packing element.

15. The apparatus according to claim 14, wherein the pipe includes openings disposed between the sealing element and the at least one packing element to facilitate the flow fluid from the segment, around the receptacle.

16. The apparatus according to claim 1, wherein the receptacle is insulated to reduce heat transfer through the receptacle, to the liquid in the receptacle.

17. The apparatus according to claim 1, wherein the receptacle bottom is insulated to reduce heat transfer through the receptacle bottom, to the liquid in the receptacle.