WO1999015755A2 - Dual injection and lifting system - Google Patents

Dual injection and lifting system Download PDF

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Publication number
WO1999015755A2
WO1999015755A2 PCT/US1998/019585 US9819585W WO9915755A2 WO 1999015755 A2 WO1999015755 A2 WO 1999015755A2 US 9819585 W US9819585 W US 9819585W WO 9915755 A2 WO9915755 A2 WO 9915755A2
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WO
WIPO (PCT)
Prior art keywords
pump
produced
ground
casing
water
Prior art date
Application number
PCT/US1998/019585
Other languages
French (fr)
Other versions
WO1999015755A3 (en
WO1999015755A8 (en
Inventor
Michael R. Berry
Kevin R. Bowlin
Howard L. Mckinzie
Lon A. Stuebinger
Original Assignee
Texaco Development Corporation
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority to CA 2213631 priority Critical patent/CA2213631A1/en
Priority to US60/059,827 priority
Priority to US5973297P priority
Priority to US5973497P priority
Priority to US5973197P priority
Priority to US5982797P priority
Priority to US5978197P priority
Priority to US5973397P priority
Priority to US60/059,732 priority
Priority to US60/059,731 priority
Priority to US60/059,781 priority
Priority to US60/059,733 priority
Priority to US60/059,734 priority
Priority to US09/154,138 priority
Priority to US15414098A priority
Priority to US09/154,142 priority
Priority to US09/154,137 priority
Priority to US09/154,141 priority patent/US6092600A/en
Priority to US09/154,143 priority
Priority to US09/154,138 priority patent/US6105671A/en
Priority to US09/154,137 priority patent/US6131660A/en
Priority to US09/154,143 priority patent/US6092599A/en
Priority to US09/154,142 priority patent/US6079491A/en
Priority to US09/154,140 priority
Priority to US09/154,139 priority patent/US6123149A/en
Priority to US09/154,139 priority
Priority to US09/154,141 priority
Application filed by Texaco Development Corporation filed Critical Texaco Development Corporation
Priority claimed from AU95718/98A external-priority patent/AU9571898A/en
Publication of WO1999015755A2 publication Critical patent/WO1999015755A2/en
Publication of WO1999015755A8 publication Critical patent/WO1999015755A8/en
Publication of WO1999015755A3 publication Critical patent/WO1999015755A3/en

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Classifications

    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/34Arrangements for separating materials produced by the well
    • E21B43/38Arrangements for separating materials produced by the well in the well
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • E21B43/121Lifting well fluids
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • E21B43/121Lifting well fluids
    • E21B43/122Gas lift
    • E21B43/123Gas lift valves
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/34Arrangements for separating materials produced by the well
    • E21B43/38Arrangements for separating materials produced by the well in the well
    • E21B43/385Arrangements for separating materials produced by the well in the well by reinjecting the separated materials into an earth formation in the same well

Abstract

The present invention relates to an apparatus and method for selectively lifting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface while injecting the remaining produced water into an injection zone subsurface in a subterranean well, or alternatively, separately lifting the remaining produced water to the ground surface. Further, this apparatus and method make it possible to produce hydrocarbons from oil wells in a manner that poses less risk and disturbance to the environment.

Description

DUAL INJECTION AND LIFTING SYSTEM
The present application claims priority to: Appl. No. 60/059,732, filed September 23, 1997; Appl. No. 60/059,733, filed September 23, 1997; Appl. No. 60/059,781, filed September 23, 1997; Appl. No. 60/059,734, filed September 23, 1997; Appl. No.
60/059,827, filed September 23, 1997; Appl. No. 60/059,731, filed September 23, 1997; Appl. No. To Be Assigned, entitled "Dual Injection And Lifting System Using An Electrical Submersible Progressive Cavity Pump And An Electrical Submersible Pump," filed September 17, 1998; Appl. No. To Be Assigned, entitled "Dual Injection And Lifting System Using Gas Lift And An Injection Pump," filed September 17, 1998; Appl. No. To Be
Assigned, entitled "Dual Injection And Lifting System Using Rod Pump And An Electrical Submersible Pump (ESP)," filed September 17, 1998; Appl. No. To Be Assigned, entitled "Dual Injection And Lifting System Using A Rod Driven Progressive Cavity Pump And An Electrical Submersible Progressive Cavity Pump," filed September 17, 1998; Appl. No. To Be Assigned, entitled "Dual Injection And Lifting System Using A Rod Driven Progressive Cavity Pump And An Electrical Submersible Pump," filed September 17, 1998; Appl. No. To Be Assigned, entitled "Systems For Minimizing Emulsion Formation In A Pumped Oil Well," filed September 17, 1998; Appl. No. To Be Assigned, entitled "Downhole Oil And Water Separation System," filed September 17, 1998; the disclosure of all of the foregoing applications is incorporated herein by reference as though set forth in full hereinafter. Background of the Invention Field of the Invention
The present invention relates to an apparatus and method for improving the economics of hydrocarbon production from a producing well. In particular, the present invention relates to an apparatus and method for selectively lifting produced fluid, including produced hydrocarbons and a portion of produced water, to the ground surface and for injecting the remaining produced water, subsurface, in a subterranean well, or alternatively, for lifting the remaining produced water to the ground surface.
Related Art
Conventional hydrocarbon production wells have been constructed in subterranean strata that yield both hydrocarbons, such as oil and gas, and an undesired amount of water. These wells are usually lined with heavy steel pipe called "casing" which is cemented in place so that fluids cannot escape or flow along the space between the casing and the well bore wall. In some wells, large amounts of water are produced along with the hydrocarbons from the onset of production. Alternatively, in other wells, relatively large amounts of water can be produced later during the life of the well.
The production of excess water to the ground surface results in associated costs in both the energy to lift, or "produce," as well as the subsequent handling of the excess produced water after it has arrived at the surface. Moreover, the produced water must be disposed of after it has been brought to the ground surface. Surface handling of excess water, in addition, creates risks of environmental pollution from such incidents as broken lines, spills, overflow of tanks, and other occurrences. Further, the facilities, lines, and wells required to handle excess water disturb the environment by virtue of their construction and presence. Accordingly, many oil production fields and wells often rapidly become uneconomic to produce hydrocarbons because of excessive water production.
Various apparatuses and methods have been proposed to overcome the problems associated with excess water production and the aforementioned problems associated with lifting, or producing, this water to the ground surface. Several approaches have been used to produce excess water to the ground surface or to avoid producing the excess water to the ground surface by shutting off the water at the entry into the wellbore. Among these means are: installing larger pumps to pump the water to the ground surface; shutting off the water by injecting gels or resins into the formation; and installing mechanical means in the well to interrupt the flow of water into the wellbore. These approaches, however, have not recognized that effective removal of water from oil or gas wells can be accomplished by transferring the accumulated water subsurface to a water-absorbing injection formation.
An evolving approach to the problem of excess water production is to take advantage of the downhole gravity segregation of produced hydrocarbons and produced water in the wellbore. The excess produced water is then conveyed into an injection formation of the subterranean strata while, for example, the oil and a small poition of the produced water that has not fully segregated from the oil are produced, or "lifted," to the ground surface. Such an approach has generally been referred to as an "in-situ" injection method. The conveyance downhole of produced water, without having lifted a majority or all of it to the ground surface, can substantially improve lease revenues or reduce lease operating expenses and investments, thereby extending the economic life of entire fields.
Devices or systems that lift and/or flow hydrocarbons and a portion of the water to the ground surface, while simultaneously injecting the water which has been separated downhole may be referred to by those persons having ordinary skill in the art as "Dual Injection and Lifting Systems (DIALS)," or alternatively, as "Downhole Oil Water Separation (DOWS)."
Generally, such methods have required the availability of a suitable injection formation, either below or above the production zone, with sufficient permeability to permit injection of the excess water into the injection formation. In addition, these in-situ methods have generally employed pumps of the same type (e.g., dual rod pumps). These pump combinations have generally been powered by the same prime mover or drive, such as a conventional pump drive located at the ground surface.
Conventional coupled systems which have been driven by the same prime mover have presented numerous problems with regard to production flexibility in order to accommodate changing reservoir conditions. This is so because it has not been feasible or simple enough to individually control the amount of fluids being lifted to the ground surface and the amount of water being injected by the coupled pumps. For example, the output of the lifting pump in a coupled system, such as a dual-rod pump, may not be variably reduced during production and the output of the injection pump may not be variably increased during production. Such flexibility is needed, for instance, when the well volume remains constant during production but the percentage of oil production decreases with time.
One example of a conventional production apparatus of the coupled in-situ type is a Dual Action Pumping System ("DAPS") that produces oil and a portion of the water from a casing/tubing annulus on the upstroke of the pump, injects water on the downstroke, and uses the gravity segregation of the oil and water within the annulus. Such an apparatus is shown in U.S. Patent No. 5,497,832, also assigned to the assignee of the present application, the entirety of which is incorporated herein by reference. Tests of this technology in a number of different wells have shown that gravity segregation of oil and water enable a dual-ported, dual-plunger rod pump to selectively lift produced fluids, including produced hydrocarbons and a portion of produced water, while separating and injecting the remaining produced water into an injection zone within the subterranean strata.
The DAPS apparatus, however, does not solve all of the problems associated with excess water production or changing water production within the subterranean reservoir. Very often, the use of two pumps of the same type (e.g., dual rod pumps) may limit the ability of the pumping system to minimize the amount of water lifted to the ground surface. For example, a system, such as DAPS, using a 1.75" diameter rod pump and a 1.5" diameter rod pump will generally lift approximately 18% of the total produced fluids to the ground surface even though the well produces only approximately 5% oil. Further, in coupled systems (i.e., pumps sharing the same prime mover), as noted above, the ability of the systems to adjust to changing water cut production is limited. For example, the various parts of the pump assemblies of coupled systems cannot economically be changed frequently enough to meet changing reservoir conditions.
In a further example of the conventional in-situ approach, coupled rod pumps are used for separating and producing oil from water in a well, while simultaneously injecting the water into the producing formation or into an injection formation below the producing formation. Such an apparatus is shown in U.S. Patent No. 5,697,448. The apparatus employs three spaced packers (upper, middle, and lower). An oil pump is located between the upper and middle packers, and a water pump is located between the middle and lower packers. Produced oil and water are accumulated between the upper and middle packers. The oil is delivered through an opening into the oil pump and fills a cylinder associated with the oil pump. Produced water is allowed to drain through additional passages into the water pump cylinder where it accumulates for injection. Selective pumping of the oil on the upstroke of the pump and the water on the downstroke of the pump is effected by a set of check valves associated with both the oil and water pumps. Such an apparatus, however, is not an optimal solution to the problems associated with changing water and oil production presented by conventional coupled systems. For example, the apparatus does not provide the flexibility needed to vary the percentage of total reservoir output that is lifted or brought to the ground surface without substantial modifications to the system.
In another example of an in-situ type apparatus, a formation injection tool, mounted to a bottom-hole tubing pump, carries out underground separation and down-bore in-situ transport and injection of the undesired fluids into an injection formation in the production well. Such an apparatus is shown in U.S. Patent No. 5,425,416. As with the apparatus shown in U.S. Patent No. 5,697,448, this system does not provide the flexibility needed to quickly and inexpensively change the proportion of fluids lifted to the ground surface as conditions within the subterranean producing strata change.
Moreover, conventional systems such as those described above have failed to provide a simple and effective method for handling high viscosity oils or solids, such as sand, which are present in many production wells. In addition, many wells have become inoperative due to the inability of conventional systems to handle crude oil and gas mixtures or shear sensitive fluids. Conventional wells generally have also not been able to compensate for changes in pressure, such as those that may be caused by gas bubbles.
Thus, there is a need in the art for an apparatus and method that substantially obviates one or more of the limitations and disadvantages of conventional pumping systems. Particularly, there is a need for a system for lifting produced oil and a portion of the produced water to the ground surface, while injecting the remainder of the produced water into an injection formation. There is a particular need for uncoupled systems which have the flexibility to vary the proportions of fluids lifted to the ground surface to the amount of water injected subsurface within the subterranean strata. There is also a need for such systems to be able to handle a variety of conditions within the producing reservoir. There is also a need for a simple system for lifting produced water to the ground surface separate from the produced hydrocarbons. Such a system is needed, for example, where a suitable injection zone is not available or when water is needed at the ground surface for other purposes, such as to generate steam or for waterflooding different zones. There is also a need for such systems to be able to handle a variety of conditions within the producing reservoir.
Conventional hydrocarbon (e.g., crude oil, natural gas, or gas condensate) production wells have been constructed in subterranean strata that yield both hydrocarbons and an undesired amount of water, such as salt water. In many of these wells, the natural pressure in the producing earth formation or reservoir is insufficient to propel or push the fluid produced from the formation to the surface of the earth. In such instances, it is necessary to use artificial lift systems to convey the produced fluids to the ground surface.
Some hydrocarbons, for example, crude oil, have a low viscosity and are relatively easy to pump from the subterranean reservoir. Others have a very high viscosity even at reservoir conditions and present numerous difficulties when attempting to bring such fluids to the ground surface.
Sucker rod pumps may be used to lift viscous hydrocarbons, but in many fields, sucker rod pumps cannot be used. For example, rod pumps are not feasible in highly deviated wells and, in many fields, limited surface rights make sucker rod pumps unfeasible. A number of pumps such as electrical submersible pumps, electrical submersible progressive cavity pumps, and axial flow pumps have been used when sucker rod pumps, or other types of lifting systems, are not feasible. In such systems, the use of such pumps has been proposed for either the reinjection of produced water downhole, or for the artificial lifting of produced hydrocarbons to the surface. One problem in using such pumps as an artificial lift method is that they tend to impart a high shear on the produced fluids as they pass through the pump. If the well is producing both oil and water, this high shear can lead to the formation of emulsions of oil and water having very small droplet size. Such emulsions may be referred to as "tight emulsions." These emulsions may be difficult and expensive to separate in surface separation facilities.
Two examples of such systems utilizing electrical submersible pumps, for example, are shown in U.S. Patent Nos. 4,832,127 and 4,749,034. These inventions mix water with the crude oil at relatively high shear rates to force an emulsion to form in the pump. The emulsion has an effective viscosity less than the viscosity of the crude oil because it is water continuous rather than oil continuous. These inventions make it possible to produce oils otherwise not capable of being produced by electrical submersible pumps, but an excessive amount of water injection from the ground surface is required. For example, the process of U.S. Patent No. 4,832,127 utilizes from 300 to 1,200 barrels of water per day to produce about 225 barrels of oil. This excessive amount of water results in larger pumps, motors, and surface separation equipment. Further, because an emulsion is created, surface separation equipment must be capable of breaking the emulsion.
If such emulsions have an oil-continuous phase (i.e., a "water-in-oil emulsion" having water droplets dispersed in an oil medium), they may also possess a viscosity that can be much higher than that of the base crude oil. The increased viscosity can then result in the use of additional energy to pump the resulting emulsion through production tubing to the surface.
To overcome this problem, several devices and schemes have been proposed to separate the oil and water downhole thereby minimizing or eliminating the formation of the oil/water emulsion. Some of these systems rely on the downhole natural gravity separation of the oil and water. Other systems, however, rely on known separation devices, such as hydrocyclones, which divide the oil and water into separate streams to be handled in separate, individual tubing strings. The separated oil can then be pumped to the surface and the separated water can be disposed of downhole or be pumped to the ground surface via the separate tubing.
Other proposed systems, such as the system shown in U.S. Patent No. 5,159,977, utilize oil/water core flow at the pump inlet in order to reduce electrical motor temperature rise and the frictional pressure drop in the production tubing while increasing pump efficiency. However, this invention requires water to be injected from the ground surface, albeit less than prior known systems, which may result in larger pumps, motors, and surface separation equipment.
Methods for establishing core annular flow in pipelines have been disclosed in, for example, U.S. Patent Nos. 3,977,469, 4,047,539, 4,745,937, and 4,753,261. These processes establish a core flow of a viscous fluid within a core of a less viscous fluid in order to reduce the pressure drop in the pipeline. These inventions, however, do not disclose or suggest an apparatus or method to consistently create core annular flow at the outlet of an electrical submersible pump, electrical submersible progressive cavity pump, or an axial flow pump.
Generally, these pumps may be used in relatively high rate wells where natural (gravity) separation in the wellbore would not occur. The conventional method of achieving downhole separation in wells utilizing such pumps would require the use of a hydrocyclone at the inlet of the pump and two separate pumps at the outputs of the hydrocyclone to handle the separated water and oil streams.
Thus, there is a need in the art for an apparatus and method that substantially obviates one or more of the limitations and disadvantages of conventional pumping systems. Particularly, it would be highly desirable to provide such a pump which does not impart undue shear to the produced oil and water. This would reduce or substantially eliminate the formation of an oil/water emulsion. Furthermore, it would be desirable to provide a pump that could enhance the separation of produced oil and water downhole without requiring the injection of excess water from the ground surface.
Summary of the Invention
The present invention solves the problems with, and overcomes the disadvantages of, conventional coupled systems for lifting produced hydrocarbons and a portion of the produced water to the ground surface following gravity segregation, and for injecting, without lifting to the ground surface, the remaining produced water into an injection zone, or alternatively, separately lifting the remaining produced water to the ground surface.
The present invention relates to an apparatus for selectively lifting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water below the ground surface. The apparatus includes a casing having two spaced intervals. The casing extends from the ground surface downwardly such that a first of the two spaced intervals communicates with a producing zone and a second of the two spaced intervals communicates with an injection zone. The apparatus further includes a first pump and a second pump disposed in the casing. The first pump is not drivingly coupled to the second pump. A packer is also included. The packer is disposed within the casing between the first of the two spaced intervals and the second of the two spaced intervals. The casing and the packer are configured to permit the produced fluids to collect above the packer whereby the produced hydrocarbons and produced water segregate by gravity. The apparatus also includes a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter one of the first and the second pump. A second inlet is also provided for permitting the segregated produced water to enter the other of the first and second pump. In another aspect, the present invention relates to a downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface. The system includes a casing having two spaced intervals. The casing extends from the ground surface downwardly such that a first of the two spaced intervals communicates with a producing zone and a second of the two spaced intervals communicates with an injection zone. The system further includes a rod pump and an electrical submersible pump (ESP) disposed in the casing. A packer is also included. The packer is disposed within the casing between the first of the two spaced intervals and the second of the two spaced intervals. The casing and the packer are configured to permit the produced fluids to collect above the packer whereby the produced hydrocarbons and produced water segregate by gravity. The system also includes a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter one of the rod and the ESP pump. A second inlet is also provided for permitting the segregated produced water to enter the other of the rod and ESP pump. In another aspect, the present invention relates to a method for selectively lifting fluids, including produced hydrocarbons and a portion of produced water from a subterranean well, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water, subsurface. The subterranean well traverses a producing zone and an injection zone. The method includes allowing produced water and produced hydrocarbons to collect above a packer disposed in a casing in the subterranean well. The method further includes controlling a first pump to lift the segregated produced hydrocarbons and a small portion of the produced water to the ground surface. In addition, the method includes controlling a second pump independently of the first pump to inject the segregated produced water into an injection zone.
In another aspect, the present invention relates to an apparatus for selectively lifting produced fluids, including produced hydrocarbons and a poition of produced water, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water below the ground surface. The apparatus includes a casing having two spaced intervals. The casing extends from the ground surface downwardly such that a first of the two spaced intervals communicates with a producing zone and a second of the two spaced intervals communicates with an injection zone. The apparatus further includes an electrical submersible progressive cavity pump and an electrical submersible pump disposed in the casing. A packer is also included. The packer is disposed within the casing between the first of the two spaced intervals and the second of the two spaced intervals. The casing and the packer are configured to permit the produced fluids to collect above the packer whereby the produced hydrocarbons and produced water segregate by gravity. The apparatus also includes a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter one of the electrical submersible progressive cavity pump and the electrical submersible pump. A second inlet is included for permitting the segregated produced water to enter the other of the electrical submersible progressive cavity pump and the electrical submersible pump.
In another aspect, the present invention relates to a downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a poition of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface. The system includes a casing having two spaced intervals. The casing extends from the ground surface downwardly such that a first of the two spaced intervals communicates with a producing zone and a second of the two spaced intervals communicates with an injection zone. The system further includes an electrical submersible progressive cavity pump and an electrical submersible pump disposed in the casing. The electrical submersible progressive cavity pump is not drivingly coupled to the electrical submersible pump. A packer is disposed within the casing between the first of the two spaced intervals and the second of the two spaced intervals. The casing and the packer are configured to permit the produced fluids to collect above the packer whereby the produced hydrocarbons and produced water segregate by gravity. In one aspect of the system, a first inlet permits segregated produced hydrocarbons and portion of the produced water to enter the electrical submersible progressive cavity pump, and a second inlet permits the segregated produced water to enter the electrical submersible pump. In an alternate aspect of the system, the first inlet permits segregated produced hydrocarbons and portion of the produced water to enter the electrical submersible pump, and the second inlet permits the segregated produced water to enter the electrical submersible progressive cavity pump. In another aspect, the present invention relates to a method for selectively lifting fluids, including produced hydrocarbons and a portion of produced water from a subterranean well, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water, subsurface, the subterranean well traversing a producing zone and an injection zone. The method includes allowing produced water and produced hydrocarbons to collect and to segregate above a packer disposed in a casing in the subterranean well. In addition, the method includes controlling one of an electrical submersible progressive cavity pump and electrical submersible pump to lift the segregated produced hydrocarbons and a small poition of the produced water to the ground surface. The method also includes independently controlling the other of the electrical submersible progressive cavity pump and electrical submersible pump to inject the segregated produced water into the injection zone.
In another aspect, the present invention relates to an apparatus for selectively lifting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water below the ground surface. The invention includes a casing having two spaced intervals and extending from the ground surface downwardly such that a first of the two spaced intervals communicates with a producing zone and a second of the two spaced intervals communicates with an injection zone. The invention also includes a gas lift system and a pump disposed in the casing. A packer is included and is preferably disposed within the casing between the first of the two spaced intervals and the second of the two spaced intervals. The casing and the packer are configured to permit the produced fluids to collect above the packer whereby the produced hydrocarbons and produced water segregate under influence of gravity. The present invention also includes a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to be lifted to the ground surface. The first inlet is in fluid-flow communication with the gas lift system. A second inlet is also included for permitting the segregated produced water to enter the pump and thereafter to be injected into the injection zone. In another aspect, the present invention relates to a downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface. The system includes a casing having two spaced intervals. The casing extends from the ground surface downwardly such that a first of the two spaced intervals communicates with a producing zone and a second of the two spaced intervals communicates with an injection zone. The system further includes a gas-lift system and an electrical submersible pump disposed in the casing. The gas-lift system and the electrical submersible pump are independently controlled. A packer is disposed within the casing between the first of the two spaced intervals and the second of the two spaced intervals. The casing and the packer are configured to permit the produced fluids to collect above the packer whereby the produced hydrocarbons and produced water segregate by gravity. A first inlet is included for permitting the segregated produced hydrocarbons and portion of the produced water to be lifted to the ground surface. The first inlet is in fluid-flow communication with the gas lift system. Also included is a second inlet for permitting the segregated produced water to enter the electrical submersible pump and thereafter to be injected into the injection zone.
In another aspect, the present invention relates to a downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface. The system includes a casing having two spaced intervals. The casing extends from the ground surface downwardly such that a first of the two spaced intervals communicates with a producing zone and a second of the two spaced intervals communicates with an injection zone. The system further includes a gas-lift system and an electrical submersible progressive cavity pump disposed in the casing. The gas-lift system and the electrical submersible progressive cavity pump are independently controlled. A packer is disposed within the casing between the first of the two spaced intervals and the second of the two spaced intervals. The casing and the packer are configured to permit the produced fluids to collect above the packer whereby the produced hydrocarbons and produced water segregate by gravity. A first inlet is included for permitting the segregated produced hydrocarbons and poition of the produced water to be lifted to the ground surface. The first inlet is in fluid-flow communication with the gas lift system. Also included is a second inlet for permitting the segregated produced water to enter the electrical submersible progressive cavity pump and thereafter to be injected into the injection zone.
In another aspect, the present invention relates to a downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a poition of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface. The system includes a casing having two spaced intervals. The casing extends from the ground surface downwardly such that a first of the two spaced intervals communicates with a producing zone and a second of the two spaced intervals communicates with an injection zone. The system further includes a gas-lift system and a rod-driven progressive cavity pump disposed in the casing. The gas- lift system and the rod-driven progressive cavity pump are independently controlled. A packer is disposed within the casing between the first of the two spaced intervals and the second of the two spaced intervals. The casing and the packer are configured to permit the produced fluids to collect above the packer whereby the produced hydrocarbons and produced water segregate by gravity. A first inlet is included for permitting the segregated produced hydrocarbons and poition of the produced water to be lifted to the ground surface. The first inlet is in fluid-flow communication with the gas lift system. Also included is a second inlet for permitting the segregated produced water to enter the rod-driven progressive cavity pump and thereafter to be injected into the injection zone.
In another aspect, the present invention relates to a downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface. The system includes a casing having two spaced intervals. The casing extends from the ground surface downwardly such that a first of the two spaced intervals communicates with a producing zone and a second of the two spaced intervals communicates with an injection zone. The system further includes a gas-lift system and a rod pump disposed in the casing. The gas-lift system and the rod pump are independently controlled. A packer is disposed within the casing between the first of the two spaced intervals and the second of the two spaced intervals. The casing and the packer are configured to permit the produced fluids to collect above the packer whereby the produced hydrocarbons and produced water segregate by gravity. A first inlet is included for permitting the segregated produced hydrocarbons and portion of the produced water to be lifted to the ground surface. The first inlet is in fluid-flow communication with the gas lift system. Also included is a second inlet for permitting the segregated produced water to enter the surface-driven rod pump and thereafter to be injected into the injection zone. In another aspect, the present invention relates to a method for selectively lifting fluids, including produced hydrocarbons and a poition of produced water from a subterranean well, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water, subsurface, the subterranean well traversing a producing zone and an injection zone. The method includes allowing produced water and produced hydrocarbons to collect and to segregate above a packer disposed in a casing in the subterranean well. In addition, the method includes controlling a gas lift system to induce flow of the segregated produced hydrocarbons and a small poition of the produced water to the ground surface. The method also includes independently controlling a pump to inject the segregated produced water into an injection zone.
In another aspect, the present invention relates to an apparatus for selectively lifting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water below the ground surface. The apparatus includes a casing having two spaced intervals. The casing extends from the ground surface downwardly such that a first of the two spaced intervals communicates with a producing zone and a second of the two spaced intervals communicates with an injection zone. The apparatus further includes a rod-driven progressive cavity pump and an electrical submersible progressive cavity pump disposed in the casing. A packer is also included. The packer is disposed within the casing between the first of the two spaced intervals and the second of the two spaced intervals. The casing and the packer are configured to permit the produced fluids to collect above the packer whereby the produced hydrocarbons and produced water segregate by gravity. The apparatus also includes a first inlet for permitting the segregated produced hydrocarbons and poition of the produced water to enter one of the rod-driven progressive cavity pump and the electrical submersible progressive cavity pump. A second inlet is included for permitting the segregated produced water to enter the other of the rod-driven progressive cavity pump and the electrical submersible progressive cavity pump.
In another aspect, the present invention relates to a downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface. The system includes a casing having two spaced intervals. The casing extends from the ground surface downwardly such that a first of the two spaced intervals communicates with a producing zone and a second of the two spaced intervals communicates with an injection zone. The system further includes a rod-driven progressive cavity pump and an electrical submersible progressive cavity pump disposed in the casing. The rod-driven progressive cavity pump is not drivingly coupled to the electrical submersible progressive cavity pump. A packer is disposed within the casing between the first of the two spaced intervals and the second of the two spaced intervals. The casing and the packer are configured to permit the produced fluids to collect above the packer whereby the produced hydrocarbons and produced water segregate by gravity. In one aspect of the system, a first inlet permits segregated produced hydrocarbons and poition of the produced water to enter the rod-driven progressive cavity pump, and a second inlet permits the segregated produced water to enter the electrical submersible progressive cavity pump. In an alternate aspect of the system, the first inlet permits segregated produced hydrocarbons and portion of the produced water to enter the electrical submersible progressive cavity pump, and the second inlet permits the segregated produced water to enter the rod-driven progressive cavity pump. In another aspect, the present invention relates to a method for selectively lifting fluids, including produced hydrocarbons and a portion of produced water from a subterranean well, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water, subsurface, the subterranean well traversing a producing zone and an injection zone. The method includes allowing produced water and produced hydrocarbons to collect and to segregate above a packer disposed in a casing in the subterranean well. In addition, the method includes controlling one of a rod-driven progressive cavity pump and electrical submersible progressive cavity pump to lift the segregated produced hydrocarbons and poition of the produced water to the ground surface. The method also includes independently controlling the other of the rod-driven progressive cavity pump and electrical submersible progressive cavity pump to inject the segregated produced water into the injection zone.
In another aspect, the present invention relates to an apparatus for selectively lifting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water below the ground surface. The apparatus includes a casing having two spaced intervals. The casing extends from the ground surface downwardly such that a first of the two spaced intervals communicates with a producing zone and a second of the two spaced intervals communicates with an injection zone. The apparatus further includes a rod-driven progressive cavity pump and an electrical submersible pump disposed in the casing. A packer is also included. The packer is disposed within the casing between the first of the two spaced intervals and the second of the two spaced intervals. The casing and the packer are configured to permit the produced fluids to collect above the packer whereby the produced hydrocarbons and produced water segregate by gravity. The apparatus also includes a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter one of the rod-driven progressive cavity pump and the electrical submersible pump. A second inlet is included for permitting the segregated produced water to enter the other of the rod-driven progressive cavity pump and the electrical submersible pump. In another aspect, the present invention relates to a downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a poition of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface. The system includes a casing having two spaced intervals. The casing extends from the ground surface downwardly such that a first of the two spaced intervals communicates with a producing zone and a second of the two spaced intervals communicates with an injection zone. The system further includes a rod-driven progressive cavity pump and an electrical submersible pump disposed in the casing. The rod-driven progressive cavity pump is not drivingly coupled to the electrical submersible pump. A packer is disposed within the casing between the first of the two spaced intervals and the second of the two spaced intervals. The casing and the packer are configured to permit the produced fluids to collect above the packer whereby the produced hydrocarbons and produced water segregate by gravity. In one aspect of the system, a first inlet permits segregated produced hydrocarbons and poition of the produced water to enter the rod-driven progressive cavity pump, and a second inlet permits the segregated produced water to enter the electrical submersible pump. In an alternate aspect of the system, the first inlet permits segregated produced hydrocarbons and poition of the produced water to enter the electrical submersible pump, and the second inlet permits the segregated produced water to enter the rod-driven progressive cavity pump. In another aspect, the present invention relates to a method for selectively lifting fluids, including produced hydrocarbons and a portion of produced water from a subterranean well, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water, subsurface, the subterranean well traversing a producing zone and an injection zone. The method includes allowing produced water and produced hydrocarbons to collect and to segregate above a packer disposed in a casing in the subterranean well. In addition, the method includes controlling one of a rod-driven progressive cavity pump and electrical submersible pump to lift the segregated produced hydrocarbons and a small poition of the produced water to the ground surface. The method also includes independently controlling the other of the rod-driven progressive cavity pump and electrical submersible pump to inject the segregated produced water into the injection zone.
In another aspect, the present invention relates to a downhole oil and water separation system including a casing having an interval. The casing extends from a ground surface downwardly such that the interval communicates with a producing zone so that produced hydrocarbons and produced water from the producing zone collect in the casing and segregate under influence of gravity. The invention further includes a first pump and a second pump disposed in the casing. The first pump is not drivingly coupled to the second pump. Also included is a first inlet for permitting the segregated produced hydrocarbons to enter the first pump and a second inlet for permitting the segregated produced water to enter the second pump.
In another aspect, the present invention relates to a method for selectively lifting fluids, including produced hydrocarbons and produced water, from a subterranean well to a ground surface. The method includes allowing produced water and produced hydrocarbons to collect and to segregate above a packer disposed in a casing in the subterranean well. In addition, the method includes controlling a first pump to lift the segregated produced hydrocarbons and a poition of the produced water through a first tubing to the ground surface. The method also includes independently controlling a second pump to lift the segregated produced water through a second tubing to the ground surface.
In another aspect, the present invention relates to a pump for conducting produced fluids from a producing well to a ground surface. The invention includes a pump section, and a pump outlet disposed at one end of the pump section and in fluid flow communication with the pump section. A transition conduit having an inlet and an outlet is coupled to the pump outlet. The pump outlet is configured to accelerate produced fluids in a tangential direction toward the transition conduit so that produced fluids exiting the transition conduit are in substantially core annular flow. The invention also includes an outlet conduit in fluid flow communication with the transition conduit for conducting produced fluids to the ground surface. In another aspect, the present invention relates to a method for conducting produced fluids, including hydrocarbons and water, from a producing well to a ground surface is provided. The method includes pumping produced fluids through a pump section into a pump outlet disposed at one end of the pump section. The method further includes accelerating the produced fluids entering the pump outlet in a substantially tangential direction and towards an inlet of a transition conduit coupled to the pump outlet. In addition, the method includes forcing the accelerated produced fluids through the transition conduit thereby further accelerating the produced fluids in the tangential direction and increasing the centripetal and centrifugual forces acting on the produced fluids such that the produced hydrocarbons and produced water separate into substantially core annular flow. The method further includes conducting the separated hydrocarbons and water up an outlet conduit to the ground surface.
Features and Advantages The present invention represents a different approach to the aforementioned problems of conventional systems. The present invention represents an improvement over such systems, and is particularly suitable for use in loosely consolidated formations where solids production can be a problem, or where gas and condensate production accompanies the crude oil production. The present invention also utilizes smaller surface profiles and weight- bearing requirements which may be important in such applications as offshore platforms. The present invention also provides for uncoupled pump systems which are separately and independently controlled by, and driven by, individual drive units, or separately driven and independently controlled by the same drive unit. As such, the present invention provides a simple, expedient, and flexible method for controlling the amount of hydrocarbons and water lifted to the ground surface, while at the same time injecting excess produced water into an injection zone. The present invention provides such flexibility while retaining the advantages of electrical submersible progressive cavity pumps, electrical submersible pumps, rod-driven progressive cavity pumps, and rod pumps. Additionally, the present invention embraces other types of pumps such as hydraulic pumps and Weir pumps. The present invention also is advantageous over purely rod-driven lift systems because it can handle larger volumes of produced fluids. Moreover, the rates for lifting hydrocarbons to the ground surface and for injecting water into a disposal zone may be separately and independently varied and controlled. The present invention may also be used in oil-producing wells to reduce lease costs that are directly associated with the volume of the total produced fluids from a producing well lifted to and handled at the ground surface. A reduction in the volume of produced fluids lifted to and handled at the ground surface results in a lowering of the horsepower required to operate the well since only produced hydrocarbons and a small fraction of produced water are actually lifted to the ground surface. Similarly, water injection costs, water treatment costs, spill containment costs, water transportation costs, and environmental cleanup costs may be substantially reduced by use of the present invention.
The present invention may also increase revenues from oil-producing wells. Use of dual injection and lifting systems such as the present invention, as opposed to use of conventional lift systems (which produce all fluids to surface) can increase production rates of producing wells. This increases operating revenues which can lead to an extended economic life of the well. Moreover, wells which previously were not operating due to high water volumes may be returned to production. The present invention may also reduce investment costs for surface equipment.
Moreover, separation equipment, treating equipment, and filtration equipment may be eliminated or reduced in size.
The present invention may also reduce exposure of the environment to damage from oil-producing operations. Potential environmental damages may be lessened by minimizing the amount of water produced to, and handled at, the surface. As known in the art, such surface water must then be reinjected into the subterranean strata through separate wellbores, or "injection wells." The very act of constructing facilities or drilling injection wells disturb the natural environment. The present invention also provides a simple and effective method for handling high viscosity oils or solids, such as sand, which are present in many production wells. In addition, many wells which have become inoperative due to the inability of conventional systems to handle crude oil and gas mixtures or shear sensitive fluids may be returned to production. The present invention also allows compensation for changes in pressure, such as those that may be caused by gas bubbles.
The present invention may also be used in situations when gas lift efficiency is declining or electrical capacity is limited. Injection of water, with available electricity driving a subsurface injection pump, will make the gas lift system more efficient than a gas lift system that simply lifts all fluids to the ground surface (as well as providing the environmental and investment advantages previously described). This will result in a decrease in the amount of gas consumed for assisting in the function of producing the well.
Moreover, lifting hydrocarbons via gas lift (particularly when enough gas is present to make artificial lift systems other than gas lift less practical), while injecting water with the aforementioned pumps provides advantages inherent to gas lift over DOWS systems that do not employ gas lift.
The use of gas lift with an electrically-operated subsurface water injection pump may require less pressure to produce a high watercut well than by gas lift alone. This results in additional production capacity. In addition, the present invention also provides the alternative of employing both electricity and natural gas to produce a well in a more efficient manner than merely utilizing one system or the other for either lifting all fluids to the ground surface or functioning as a DOWS system.
Where a suitable injection zone is not available or when water is needed at the ground surface for other purposes, such as to generate steam or for waterflooding different zones, the present invention provides a simple method for utilizing downhole segregation of produced hydrocarbons and produced water such that the hydrocarbons and water may be produced to the ground surface in separate streams. The present invention also provides a simple system for providing source water for pressure maintenance or waterflooding nearby fields which do not have the potential of utilizing DOWS to lift water from suitable subterranean zones. In such an embodiment, the present invention allows for the minimization or elimination of surface equipment, such as "Free Water Knock Outs," fired heaters, separators, or emulsion treating chemicals.
The present invention provides an improved pump to enhance oil and water separation within the pump, preferably, at its outlet. The improved pump, at least partially, breaks any oil and water emulsion created by its pump section and causes separated water to be conducted radially outwardly, preferably in the pump outlet to the wall of the tubing outlet. The oil and any remaining emulsion may be located geometrically near the axis or center poition of the tubing. This radial distribution of the fluid results in what is generally known as "core annular flow," wherein the heavier water tends toward the outside of the wall of the tubing outlet while the oil tends to stay toward the central axis of the tubing outlet as the fluids flow through the tubing.
The promotion of core annular flow results in several advantages. Among these are: 1) reducing the effective viscosity of the emulsion; 2) reducing drag along the tubing wall; 3) reducing the "tightness" of the emulsion, thereby increasing the effectiveness of the separation facilities at the ground surface; 4) reducing the amount of chemical emulsion breaker and/or facilities required for separation; 5) increasing the throughput of the separation facilities without adding additional equipment; and 6) simplifying the equipment required for downhole separation. Core annular flow may, however, be relatively short lived if the viscosity of the inner (radial) fluid is much less than 1000 centipoise. Even if core annular flow cannot be sustained along the entire length of the outlet tubing to the ground surface, there are large advantages in separating the oil and water into two phases, rather than producing the mixture as a tight emulsion which is difficult and expensive to separate at the ground surface.
In the present invention, the preferred embodiments of the improved pump accelerate the oil/water emulsion in a tangential direction as it is exiting from the pump outlet. Separation occurs because of an increase in centrifugal force (which is generally discussed in terms of the gravitational constant or "g") which pulls the heavier fluid component (e.g., water) to the outside of the boundary of the device (e.g., tubing) and a corresponding increase in centripetal force which forces the lighter fluid component (e.g., oil) to the center or axis of the device. A major difference between using the pump system of the present invention from the use of conventional hydrocyclone separators is that in the present invention a single output tubing string transports the separated fluids in substantially core annular flow to the ground surface. This reduces the amount of, and complexity of, the equipment used downhole to separate the oil and water.
Moreover, the present invention overcomes the problems with conventional systems in that it substantially separates the emulsion of oil and water at the outlet of the pump. Furthermore, the present invention provides a pump that enhances the separation of produced oil and water downhole without requiring the injection of excess water from the ground surface.
Additional features and advantages of the invention will be set forth in the description that follows, and in part will be apparent from the description, or may be learned in practice of the invention. These descriptions and drawings are intended as illustrative of the invention, and not as limitative thereof.
Brief Description of the Drawings The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments of the invention and, together with the description, serve to explain the features, advantages, and principles of the invention.
Fig. 1 is a schematic side-elevation sectional view of an exemplary embodiment of the present invention; Fig. 2 is a schematic side-elevation sectional view of a second exemplary embodiment of the present invention;
Fig. 3 is a schematic side-elevation sectional view of a third embodiment of the present invention shown with an injection zone overlying a producing zone in the subterranean reservoir; Fig. 4 is a schematic side-elevation sectional view of a fourth exemplary embodiment of the present invention;
Fig. 5 is a schematic side-elevation sectional view of the embodiment of Fig. 4 employing a bypass conduit for re-injecting produced water into a disposal zone located above a producing zone; Fig. 6 is a schematic side-elevation sectional view of a fifth exemplary embodiment of the present invention;
Fig. 7 is a schematic side-elevation sectional view of a sixth exemplary embodiment of the present invention; Fig. 8 is a schematic side-elevation sectional view of a seventh exemplary embodiment of the present invention employing a rod pump to lift produced fluids to the ground surface and an electrical submersible pump for re-injecting produced water;
Fig. 9 is a schematic side-elevation sectional view of the embodiment of Fig. 8 employing a bypass conduit for re-injecting produced water into a disposal zone above a production zone;
Fig. 10 is a schematic side-elevation sectional view of an eighth exemplary embodiment of the present invention employing an electrical submersible pump for lifting produced fluids to the ground surface and a rod pump for re-injecting water; Fig. 11 is a schematic side-elevation sectional view of a ninth exemplary embodiment of the present invention;
Fig. 12 is a schematic side-elevation sectional view of the embodiment of Fig. 11 employing a bypass conduit for re-injecting produced water into a disposal zone located above a producing zone; Fig. 13 is a schematic side-elevation sectional view of a tenth exemplary embodiment of the present invention;
Fig. 14 is a schematic side-elevation sectional view of an eleventh exemplary embodiment of the present invention;
Fig. 15 is a schematic side-elevation sectional view of the embodiment of Fig. 14 employing a bypass conduit for re-injecting produced water into a disposal zone located above a producing zone;
Fig. 16 is a schematic side-elevation sectional view of a twelfth exemplary embodiment of the present invention; Fig. 17 is a schematic side-elevation view of a thirteenth exemplary embodiment of the present invention;
Fig. 18 is a schematic side-elevation view of an alternate embodiment of the thirteenth exemplary embodiment shown in Fig. 17; Fig. 19 is a schematic side-elevation view of a fourteenth exemplary embodiment of the present invention;
Fig. 20 is a schematic side-elevation view illustrating an exemplary electrical submersible progressive cavity pump suitable for use in the present invention;
Fig. 21 is a schematic side-elevation view illustrating an exemplary progressive cavity pump suitable for use in the present invention;
Fig. 22A is a schematic sectional view of a fifteenth exemplary embodiment of the present invention showing a pump with a pump outlet;
Fig. 22B is a schematic detailed view of an exemplary pump outlet according to the present invention; Fig. 23 A is a schematic sectional view of a sixteenth exemplary embodiment of the present invention showing a pump with a pump outlet; and
Fig. 23B is a schematic detailed view of an exemplary pump outlet according to the present invention.
Detailed Description of the Preferred Embodiments
Reference will now be made in detail to the present preferred embodiments of the invention, examples of which are illustrated in the accompanying drawings. The exemplary embodiments of this invention are shown in some detail, although it will be apparent to those skilled in the relevant art that some features which are not relevant to the invention may not be shown for the sake of clarity. Like reference numerals will be used to illustrate the same or similar elements in the figures.
Referring first to Fig. 1, there is illustrated, in a schematic side-elevation sectional view, an exemplary embodiment of the present invention and is represented generally by reference numeral 5. A casing 11 is shown extending from a ground surface 14 downwardly within a subterranean well through a hydrocarbon and water producing zone 12 and then to a water injection zone 19. It should be understood by one of ordinary skill in the art that injection zone 19 may alternatively be referred to as a disposal zone. It is preferable to have a long distance or an isolation zone 18 between producing zone 12 and injection zone 19. As shown in Fig. 1, casing 11 has a producing interval, shown generally at 15, separated from an injection interval, shown generally at 17. Producing interval 15 is located adjacent to and in fluid flow communication with producing zone 12. In a similar manner, injection interval 17 is located adjacent to and in fluid flow communication with disposal, or injection zone 19. Producing interval 15 may preferably be for example, but is not limited to, perforations 15a with or without gravel packs in casing 11 as shown in Fig. 1. Alternatively, producing interval 15 may be, but is not limited to, a slotted liner with or without gravel packs, wire-wrapped screens with or without gravel packs, or pre-packed wire-wrapped screens. Likewise, injection interval 17 may preferably be, but is not limited to, perforations 17a with or without gravel packs in casing 11 as shown in Fig. 1. As an alternative, injection interval 17 may be a slotted liner with or without gravel packs, wire- wrapped screens with or without gravel packs, or pre-packed wire-wrapped screens. As a further alternative, instead of using injection interval 17, the excess water may be injected directly into an open hole (not shown) within the subterranean strata. Preferably, however, injection interval 17 will be perforations 17a.
It should be readily apparent to one skilled in the art that casing 11 may be provided with multiple producing intervals 15 and injection intervals 17 in communication with producing zone 12 and injection zone 19, respectively. Moreover, injection zone 19 can be the same formation as producing zone 12 provided that producing interval 15 and injection interval 17 are not communicating actively (i.e., fluid flow is isolated between producing interval 15 and injection interval 17). It should be understood by those of skill in the art, however, that fluids produced into casing 11 through producing interval 15 and water injected through injection interval 17 may influence the flow parameters of each other.
Casing 11 surrounds a tubing 24 which extends from ground surface 14 downwardly within casing 11. Tubing 24 preferably includes three tubing sections, 24a, 24b, and 24c. It should be apparent to one of ordinary skill in the art that tubing 24 may include any number of tubing sections depending, of course, upon the particular configuration of the well. A first pump 10 is disposed at an end of first tubing section 24a which extends from ground surface 14 downwardly within casing 11. Tubing section 24b extends between and is coupled to first pump 10 and a second pump 20. Second pump 20 is preferably disposed below first pump 10 in casing 11 on tubing 24, or more particularly, on second tubing section 24b. Tubing section 24c is coupled to second pump 20 and extends downwardly within casing 11 below a packer 16 disposed in casing 11.
First pump 10 and second pump 20 are shown in the embodiment of Fig. 1 uncoupled relative to each other. Particularly, first pump 10 is not drivingly coupled to second pump 20. First pump 10 and second pump 20 are preferably controlled by individual drives as will be described in more detail below. This configuration allows the individual pump rates to be separately controlled to respond to changing reservoir conditions. Moreover, individual rates of lift and injection can be separately controlled to optimize overall field performance. In the embodiment shown in Fig. 1, first pump 10 is an electrical submersible progressive cavity pump (ESPCP) and second pump 20 is an electrical submersible pump (ESP). An electrical submersible centrifugal pump is particularly preferred. In an alternate embodiment of the present invention, first pump 10 is an ESP and second pump 20 is an ESPCP.
As noted above, packer 16 is disposed within casing 11, preferably between producing interval 15 and injection interval 17. Casing 11 and packer 16 are configured to permit produced hydrocarbons and produced water to collect above packer 16. By
"produced hydrocarbons" is meant crude oil, gas, gas condensate, and various combinations thereof. Particularly, tubing 24, casing 11, and packer 16, together define casing/tubing annulus 26 that extends upward to ground surface 14. Hydrocarbons, such as oil or gas, and water flow or are "produced," into casing 11 through producing interval 15. The hydrocarbons and water segregate by gravity within casing/tubing annulus 26 forming a hydrocarbon/water interface 28. Gravity segregation, as used herein, is intended to describe the preservation of the isolation between produced hydrocarbons and water, as opposed to separation which indicates that a mixture is mechanically divided into separate fluids. Thus, the produced hydrocarbons and water are allowed to collect in annulus 26 above packer 16 and to segregate by gravity to form segregated produced water 23 below hydrocarbon/water interface 28 and segregated produced hydrocarbons and a small proportion or portion of produced water 25 above hydrocarbon water interface 28.
A first, or upper inlet 30 is preferably disposed in tubing 24, or more particularly, in an upper end of tubing section 24b, below first pump 10. First inlet 30 is disposed in a region of casing 11, or more particularly, in a region of casing/tubing annulus 26, where segregated hydrocarbons and only a small proportion or portion of water are expected to be present and preferably, adjacent hydrocarbon/water interface 28. As shown in the exemplary embodiment in Fig. 1, first inlet 30 may be sets of perforations 30a in tubing 24. Alternatively, first inlet 30 may be a port or multiple ports or other suitable mechanisms for conducting fluid flow. Preferably, however, first inlet 30 will be sets of perforations 30a. First inlet 30 is configured to permit produced hydrocarbons and any poition of water that has not segregated from the hydrocarbons 25 to enter first pump 10. The operation of first inlet 30 will be described in more detail below. A second, or lower inlet 13 is shown disposed in tubing 24, or more particularly, in a lower end of tubing section 24b, above second pump 20. Second inlet 13 is preferably disposed in a region of casing 11, or more particularly, in a region of casing/tubing annulus 26, where primarily only the heavier segregated produced water is present (i.e., inlet 13 is in fluid-flow communication primarily with segregated produced water 23). As shown in Fig. 1, second inlet 13 may be sets of perforations 13a in tubing 24 or second tubing section 24b. Second inlet 13 is configured to permit the segregated produced water from producing zone 12 to enter second pump 20 and to be injected into disposal zone 19 as will be discussed in more detail below. It may also be desirable, although not required, to dispose a tubing plug 38 in tubing 24, or more particularly second tubing section 24b, between first pump 10 and second pump 20, in order to maintain separation of the segregated produced hydrocarbons and a portion of the produced water 25 and the segregated produced water 23 within second tubing section 24b.
A first variable speed drive 36 may be disposed at ground surface 14 to provide power to and control the pump rate of first pump 10. First pump 10 is preferably coupled to first variable speed drive 36 by a first electrical line or cable 34. Similarly, a second variable speed drive 40 may be disposed at ground surface 14 to provide power to and control the pump rate of second pump 20. Second pump 20 is preferably coupled to second variable speed drive 40 by a second electrical line or cable 37. Reference will now be made to the operation of the first exemplary embodiment shown in Fig. 1. In operation, produced fluids (hydrocarbons and water) are produced from producing zone 12 via intervals 15 into casing 11 above packer 16 forming a column of produced hydrocarbons and water within casing/tubing annulus 26. The lighter produced fluids (mostly hydrocarbons 25) rise to the top of the column while the heavier fluids (mostly water 23) settle to the bottom of the column.
Segregated hydrocarbons and a small poition of water 25 then flow, or are "pulled," through first inlet 30 and into tubing 24 below first pump 10. First pump 10 then pumps the segregated hydrocarbons and a small poition of water 25 (as will be described in more detail with reference to Fig. 20) through tubing 24 to ground surface 14 where it is collected in a well-known manner. It is preferred that, during production, hydrocarbon/water interface 28 is maintained adjacent first inlet 30 in order to provide stabilized pumping conditions. In order to meet the capacity of first pump 10 and to ensure that hydrocarbon/water interface 28 is maintained adjacent first inlet 30, an upper poition of segregated produced water 23 (in addition to produced hydrocarbons and poition of produced water 25) may be "pulled" by first pump 10 through first inlet 30 and pumped to ground surface 14.
Simultaneously, segregated produced water 23 that has settled at the bottom of the casing/tubing annulus 26 flows through second inlet 13 and into second pump 20. The segregated water is then pumped, or injected, through the end of tubing section 24c and into casing 11 below packer 16 and thereafter into injection zone 19. It should be understood by one skilled in the art that first pump 10 and second pump 20 may include sensors (not shown) for flow rate, pressure, and temperature measurement or other types of control information which is transmitted to variable speed drives, 36 and 40. Thus, first pump 10 and second pump 20 are individually and independently controllable to provide maximum flexibility in selecting pump output to optimize reservoir performance and to allow conformance to changing reservoir conditions. Moreover, because first pump 10 and second pump 20 are separately controlled (i.e., first pump 10 is controlled by first variable speed drive 36 and second pump 20 is controlled by second variable speed drive 40), their respective pump output may be separately and independently varied to correspond to the changing reservoir conditions during production.
The entire combination of first pump 10 and second pump 20 may typically be about 30 feet to several hundred feet in length. Moreover, the distance from producing intervals 15 to packer 16, percentage of water cut and injection rate, and designed production rate can all be variables in deciding whether it is desirable to place second pump 20 just above packer 16 or higher in the well.
Reference will now be made to Fig. 2, wherein a second embodiment of the present invention is shown employing a single submersible electric motor 32 to separately provide power to and control first pump 10 and second pump 20. Like reference numerals will be used where appropriate to describe similar elements to those of the embodiment shown in Fig. 1.
In Fig. 2, motor 32 is shown disposed in casing 11, and more particularly, in tubing section 24b between first pump 10 and second pump 20. Preferably, motor 32 will be axially aligned with first pump 10 and second pump 20. Motor 32 includes an upper drive shaft 42 coupled to first pump 10 through a gearbox 32a. Additionally, a lower drive shaft 44 is coupled between motor 32 and second pump 20.
Variable speed drive 36 is disposed at ground surface 14 to provide power to motor 32 and to control the output of motor 32 (e.g., speed of rotation). Motor 32 is preferably coupled to variable speed drive 36 by electrical line or cable 34. The remaining elements shown in Fig. 2 have been described above with reference to Fig. 1, and for the sake of brevity are herein incorporated by reference.
Reference will now be made to the operation of the second exemplary embodiment shown in Fig. 2. In operation, produced fluids (hydrocarbons and water) are produced from producing zone 12 via intervals 15 into casing 11 above packer 16 forming a column of produced hydrocarbons and water within casing/tubing annulus 26. The lighter produced fluids (mostly hydrocarbons) rise to the top of the column while the heavier fluids (mostly water) settle to the bottom of the column.
Segregated hydrocarbons and a small poition of water 25 then flow through first inlet 30 and into tubing 24 below first pump 10. First pump 10, driven by motor 32 via gearbox 32a, pumps the segregated hydrocarbons and small poition of water 25 through tubing 24 to the ground surface 14 where it is collected in a well-known manner.
Simultaneously, segregated produced water 23 which has settled at the bottom of casing/tubing annulus 26 flows through second inlet 13 and into second pump 20. The segregated water is Jhen pumped, or injected through the end of tubing section 24c and into casing 11 below packer 16 and thereafter into injection zone 19.
Reference will now be made to Fig. 3, wherein a third embodiment of the present invention is shown in which third tubing section 24c is coupled to second pump 20 for injecting produced water into disposal zone 19 which is located above producing zone 12. In this embodiment, second pump 20 is preferably disposed at the end of tubing 24, or more particularly, at the end of second tubing section 24b.
As can be seen in Fig. 3, third tubing section 24c extends up casing/tubing annulus 26 and through a passage 16a in packer 16. A second packer 27 is disposed in casing 11 preferably above injection zone 19. Packer 16 and second packer 27 are configured to isolate injection zone 19 within casing 11 from both producing zone 12 and, for example, an isolated aquifer 40. Second inlet 13 is shown disposed on a lower end of second pump 20 such that segregated produced water 23 passing through second pump 20 may be used for cooling purposes. Tubing plug 38 may be disposed in tubing 24, or more particularly in second tubing section 24b, between first pump 10 and second pump 20 in order to isolate segregated hydrocarbons and portion of produced water 25 from segregated produced water 23 within tubing 24.
During operation of the system shown in Fig. 3, first pump 10 lifts segregated produced hydrocarbons and a poition of produced water 25 to ground surface 14 in the manner described above. At the same time, second pump 20 pumps segregated produced water 23 that enters second pump 20 through second inlet 13 through third tubing section 24c and thereafter into disposal zone 19 via injection interval 17.
Referring now to Fig. 4, there is illustrated, in a schematic side-elevation sectional view, a fourth exemplary embodiment of the present invention and is represented generally by reference numeral 5. A casing 11 is shown extending from a ground surface 14 downwardly within a subterranean well through a hydrocarbon and water producing or production zone 12 and then to a water injection zone 19. It should be understood by one of ordinary skill in the art that injection zone 19 may alternatively be referred to as a disposal zone. It is preferable to have a long distance or an isolation zone 18 between producing zone 12 and injection zone 19.
As shown in Fig. 4, casing 11 has a producing interval, shown generally at 15, separated from an injection interval, shown generally at 17. Producing interval 15 is located adjacent to and in fluid flow communication with producing zone 12. In a similar manner, injection interval 17 is located adjacent to and in fluid flow communication with disposal, or injection zone 19. Producing interval 15 may preferably be for example, but is not limited to, perforations 15a with or without gravel packs in casing 11 as shown in Fig. 4. Alternatively, producing interval 15 may be, but is not limited to, a slotted liner with or without gravel packs, wire-wrapped screens with or without gravel packs, or pre-packed wire- wrapped screens. Likewise, injection interval 17 may preferably be, but is not limited to, perforations 17a with or without gravel packs in casing 11 as shown in Fig. 4. As an alternative, injection interval 17 may be a slotted liner with or without gravel packs, wire- wrapped screens with or without gravel packs, or pre-packed wire-wrapped screens. As a further alternative, instead of using injection interval 17, the excess water may be injected directly into an open hole (not shown) within the subterranean strata. Preferably, however, injection interval 17 will be perforations 17a.
It should be readily apparent to one skilled in the art that casing 11 may be provided with multiple producing intervals 15 and injection intervals 17 in communication with producing zone 12 and injection zone 19, respectively. Moreover, injection zone 19 can be the same formation as producing zone 12 provided that producing interval 15 and injection interval 17 are not communicating actively (i.e., fluid flow is isolated between producing interval 15 and injection interval 17). It should be understood by those of skill in the art, however, that fluids produced into casing 11 through producing interval 15 and water injected through injection interval 17 may influence the flow parameters of each other.
Casing 11 surrounds a tubing 24 which extends from ground surface 14 downwardly within casing 11. A gas lift system, represented generally by reference numeral 100 is disposed in tubing 24. Gas lift system 100 preferably includes a gas lift mandrel 100a and a gas lift valve 100b disposed in gas lift mandrel 100a. Gas lift valve 100b is in fluid-flow communication with casing 11. Gas lift valve 100b is responsive to pressure and functions automatically to introduce gas from casing 11 as will be described in more detail below. It should be apparent to one of ordinary skill in the art that gas lift valve 100b may be fixed or secured within gas lift mandrel 100a. Alternatively, gas lift valve 100b may be insertable and removable from gas lift mandrel 100a. Particularly, gas lift valve 100b is preferably removable and retrievable from ground surface 14, for example, using wire line servicing equipment. A plurality of gas lift mandrels 100a and corresponding gas lift valves 100b may be employed in the present invention depending, of course, upon the particular operating conditions within the production well.
A pump 20 is disposed at a lower end of tubing 24 as shown in Fig. 4. Gas lift mandrel 100a (including gas lift valve 100b) and pump 20 are uncoupled relative to each other. Particularly, gas lift valve 100b is not drivingly coupled to pump 20. Gas lift valve 100b and pump 20 are preferably controlled individually as will be described in more detail below. This configuration allows the rates of pump 20 and gas lift system 100 to be separately controlled to respond to changing reservoir conditions. Moreover, individual rates of lift and injection can be separately controlled to optimize overall field performance. In the embodiment shown in Fig. 4, pump 20 is an electrical submersible pump (ESP). An electrical submersible centrifugal pump is particularly preferred. Alternately, pump 20 is an electrical submersible progressive cavity pump.
A packer 16 is disposed within casing 11, preferably between producing interval 15 and injection interval 17. In addition, a second packer (not shown for the sake of clarity) may be disposed within casing 11 and preferably below the lowest gas lift mandrel 100a disposed in tubing 24. Casing 11 and packer 16 are configured to permit produced hydrocarbons and produced water to collect above packer 16. By "produced hydrocarbons" is meant crude oil, gas, gas condensate, and various combinations thereof. Particularly, tubing 24, casing 11, and packer 16, together define a casing/tubing annulus 26 that extends upward to ground surface 14. Hydrocarbons, such as oil or gas, and water flow or are "produced," into casing 11 through producing interval 15. The hydrocarbons and water segregate by gravity within casing-tubing annulus 26 forming a hydrocarbon/water interface 28. "Gravity segregation," as used herein, is intended to describe the preservation of the isolation between produced hydrocarbons and water, as opposed to separation which indicates that a mixture is mechanically divided into separate fluids. Thus, the produced hydrocarbons and water are allowed to collect in annulus 26 above packer 16 and to segregate by gravity to form segregated produced water 23 below hydrocarbon/water interface 28, and hydrocarbons and a small poition or proportion of produced water 25 above hydrocarbon/water interface 28.
A first, or upper inlet 30 is preferably disposed in tubing 24 below gas lift mandrel 100a. First inlet 30 is preferably disposed in a region of casing 11, or more particularly, in a region of casing/tubing annulus 26, where segregated hydrocarbons and only a small amount of water are expected to be present and preferably, adjacent hydrocarbon/water interface 28. As shown in the exemplary embodiment in Fig. 4, first inlet 30 may be sets of perforations 30a in tubing 24. Alternatively, first inlet 30 may be a port or multiple ports or other suitable mechanism for conducting fluid flow, such as check valves. Preferably, however, first inlet 30 will be sets of perforations 30a. First inlet 30 is configured to permit the produced hydrocarbons and any small portion of water that has not segregated from the hydrocarbons to enter gas lift system 100. The operation of first inlet 30 will be described in more detail below.
Pump 20, as shown in Fig. 4, is disposed at a lower end of tubing 24. A second or lower inlet 13 is shown disposed in tubing 24 above pump 20. Second inlet 13 is preferably disposed in a region of casing 11, or more particularly, in a region of casing/tubing annulus 26, where primarily only the heavier segregated produced water is present (i.e., inlet 13 is in fluid-flow communication primarily with segregated produced water 23). As shown in Fig. 4, second inlet 13 may be sets of perforations 13a in tubing 24. Second inlet 13 is configured to permit the segregated produced water from the production zone 12 to enter pump 20 which will be described in more detail below.
Preferably, tubing 24 extends below packer 16 in casing 11 to permit segregated produced water 23 to be injected into injection zone 19. A tubing plug 38 may be disposed in tubing 24 between gas lift mandrel 100a and pump 20 in order to isolate segregated hydrocarbons and a portion of produced water 25 from segregated produced water 23 within tubing 24.
A variable speed drive 22 may be disposed at ground surface 14 to provide power to and control the pump rate of pump 20. Variable speed drive 22 is electrically connectable to pump 20 via an electrical line or cable 21. Reference will now be made to the operation of the fourth exemplary embodiment shown in Fig. 4. In operation, produced fluids (hydrocarbons and water) are produced from production zone 12 via intervals 15 into casing 11 above packer 16, thereby forming a column of produced hydrocarbons and water within casing/tubing annulus 26. The lighter produced fluids (mostly hydrocarbons 25) rise to the top of the column while the heavier fluids (mostly water 23) settle to the bottom of the column.
The initial gas pressure of the formation causes segregated hydrocarbons and a small portion of produced water 25 to flow through first inlet 30 and into tubing 24. The segregated hydrocarbons and a small portion of produced water 25 continue to flow through tubing 24 to ground surface 14 where it is collected in a conventional manner. As formation pressure is depleted, gas may be introduced into casing 11. Gas lift valve 100b disposed in gas lift mandrel 100a is in fluid flow communication with casing 11. Gas lift valve 100b is pressure responsive and opens automatically in response to changing pressure within casing 11. Gas lift valve 100b allows gas from casing 11 to enter tubing 24 as necessary to decrease the density of produced hydrocarbons and poition of produced water 25. This density reduction induces the upwardly flowing produced hydrocarbons and poition of produced water 25 to continue flowing upwardly until they reach ground surface 14. It is preferred that, during production, hydrocarbon/water interface 28 is maintained adjacent first inlet 30 in order to provide stabilized conditions. Simultaneously, segregated produced water which has settled at the bottom of casing tubing annulus 26 flows through second inlet 13 and into pump 20. The segregated water is then pumped or injected through the end of tubing 24 and into casing 11 below packer 16 and thereafter into injection zone 19. It should be understood by one skilled in the art that pump 20 may include sensors (not shown) for flow rate, pressure, and temperature measurement or other types of control information which is transmitted to variable speed drive 22. Thus, pump 20 is individually and independently controllable from gas lift valve 100b to provide maximum flexibility in selecting pump output to optimize reservoir performance and to allow conformance to changing reservoir conditions. Moreover, because gas lift valve 100b and pump 20 are separately controlled (i.e., gas lift valve 100b is automatically responsive to changes in casing pressure, and pump 20 is controlled by variable speed drive 22), their respective fluid outputs may be separately and independently varied to correspond to the changing reservoir conditions during production.
The entire combination of gas lift system 100 and pump 20 may typically be about 30 feet to several hundred feet in length. Moreover, the distance from producing interval 15 to packer 16, percentage of water cut and injection rate, and designed production rate can all be variables in deciding whether it is desirable to place pump 20 just above packer 16 or higher in the well.
Reference will now be made to Fig. 5, wherein a bypass conduit 36 is shown coupled to pump 20 for injecting produced water into disposal zone 19 which is located above producing zone 12. As can be seen in Fig. 5, bypass conduit 36 extends up casing/tubing annulus 26 and through a passage 16a in packer 16. A second packer 27 is disposed in casing 11 preferably above injection zone 19. Packer 16 and second packer 27 are configured to isolate injection zone 19 within casing 11 from both producing zone 12 and, for example, an isolated aquifer 40. A tubing plug 38 may be disposed in tubing 24 between gas lift mandrel 100a and pump 20 in order to isolate segregated hydrocarbons and a portion of produced water 25 from segregated produced water 23 within tubing 24.
During operation of the system shown in Fig. 5, gas lift valve 100b disposed in gas lift mandrel 100a induces upwardly flow of segregated produced hydrocarbons and a small proportion or portion of produced water 25 to ground surface 14 in the manner described above with reference to Fig. 4. At the same time, pump 20 pumps segregated produced water 23 that enters pump 20 through second inlet 13 through bypass conduit 36 and thereafter into disposal zone 19 via injection interval 17. Reference will now be made to Fig. 6, wherein a fifth exemplary embodiment of the present invention is shown employing a rod-driven progressive cavity pump as pump 20. Like reference numerals will be used where appropriate to describe similar elements to those of the embodiment shown in Fig. 4.
In Fig. 6, a sucker rod string 9 is disposed within tubing 24. Rod string 9 extends from ground surface 14 downwardly through an opening 38a in tubing plug 38 and is coupled to pump 20. Tubing plug 38 may be disposed in tubing 24 above pump 20 and below gas lift mandrel 100a in order to isolate segregated produced hydrocarbons and a poition of produced water 25 from segregated produced water 23 in tubing 24. Rod string 9 is rotated by a motor 8 located at the ground surface 14. As rod string 9 is rotated by motor 8, pump 20 likewise is rotated. Detail of this rotation will be described in more detail with reference to Fig. 21. The remaining elements shown in Fig. 6 have been described above and for the sake of brevity, such descriptions are herein incorporated by reference.
Reference will now be made to the operation of the fifth exemplary embodiment shown in Fig. 6. In operation, produced fluids (hydrocarbons and water) are produced from production zone 12 via interval 15 into casing 11 above packer 16 forming a column of produced hydrocarbons and water within casing/tubing annulus 26. The lighter produced fluids (mostly hydrocarbons 25) rise to the top of the column while the heavier fluids (mostly water 23) settle to the bottom of the column. The initial pressure of the formation causes segregated hydrocarbons and a small poition of produced water 25 to flow through first inlet 30 and into tubing 24. The segregated hydrocarbons and a small poition of produced water 25 continue to flow through tubing 24 to ground surface 14 where it is collected in a conventional manner. As formation pressure is depleted, gas may be introduced into casing 11. Gas lift valve 100b disposed in gas lift mandrel 100a is in fluid flow communication with casing 11. Gas lift valve 100b is pressure responsive and opens automatically in response to changing pressure within casing 11 to introduce gas from casing 11 into tubing 24 thereby decreasing the density of produced hydrocarbons and poition of produced water 25 within tubing 24. The decrease in density induces the upwardly flowing produced hydrocarbons and poition of produced water 25 to continue flowing upwardly until it reaches ground surface 14. It is preferred that, during production, hydrocarbon/water interface 28 is maintained adjacent first inlet 30 in order to provide stabilized conditions.
Simultaneously, segregated produced water which has settled at the bottom of casing/tubing annulus 26 flows through second inlet 13 and into pump 20. Rotation of motor 8, and likewise pump 20, causes the segregated produced water 23 to be pumped or injected (as will described in more detail with reference to Fig. 21) through the end of tubing 24 and into casing 11 below packer 16 and thereafter into injection zone 19.
Reference will now be made to Fig. 7, wherein a sixth exemplary embodiment of the present invention is shown employing a surface-driven rod pump as pump 20. Like reference numerals will be used where appropriate to describe similar elements to those of the embodiments shown in Figs. 4 and 6.
A sucker rod string 9 is disposed in tubing 24. Rod string 9 extends to ground surface 14 where it is reciprocated through an upstroke and a downstroke by pump drive 8 located at ground surface 14. Rod string 9 is coupled to pump 20. As rod string 9 is reciprocated through an upstroke and a downstroke by pump drive 8, pump 20 reciprocates through an upstroke and a downstroke. Second inlet 13 is preferably disposed in tubing 24 below pump 20. The remaining elements have been described above and, for the sake of brevity, such descriptions are herein incorporated by reference. Reference will now be made to the operation of the embodiment shown in Fig. 7.
During the upstroke of pump 20, segregated produced water 23 flows through second inlet 13 and into tubing 24 below pump 20. Preferably, pump 20 is not configured with a traveling valve disposed therein and pump 20 is sealingly disposed within tubing 24. Because the pump 20 preferably is not configured with a traveling valve and pump 20 is sealingly disposed within tubing 24, produced water 23 will not pass through pump 20 (i.e., pump 20 will act as a piston within tubing 24). During the downstroke, produced water 23 in tubing 24 below pump 20 is forced or injected through the end of tubing 24 below packer 16, into casing 11, and thereafter into injection zone 19. Simultaneously, segregated produced hydrocarbons and portion of produced water 25 that has not settled to the bottom, flow into first inlet 30 upwardly through tubing 24 to ground surface 14. The upwardly flow of segregated produced hydrocarbons and poition of produced water 25 may be induced by gas lift valve 100b in the same manner as described above.
It should be understood by one of ordinary skill in the art that the segregated hydrocarbons and portion of produced water 25 is separated from the segregated produced water 23 within tubing 24 via pump 20 acting as a piston. Alternatively, a tubing plug 38 may be placed above pump 20 in tubing 24 to provide a secondary separator.
Referring now to Fig. 8, there is illustrated, in a schematic side-elevation sectional view, a seventh exemplary embodiment of the present invention and is represented generally by reference numeral 5. A casing 11 is shown extending from a ground surface 14 downwardly within a subterranean well through a hydrocarbon and water producing zone 12 and then to a water injection zone 19. It should be understood by one of ordinary skill in the art that injection zone 19 may alternatively be referred to as a disposal zone. It is preferable to have a long distance or an isolation zone 18 between producing zone 12 and injection zone 19.
As shown in Fig. 8, casing 11 has a producing interval, shown generally at 15, separated from an injection interval, shown generally at 17. Producing interval 15 is located adjacent to and in fluid flow communication with producing zone 12. In a similar manner, injection interval 17 is located adjacent to and in fluid flow communication with disposal, or injection zone 19. Producing interval 15 may preferably be for example, but is not limited to, sets of perforations 15a with or without gravel packs in casing 11 as shown in Fig. 8. Alternatively, producing interval 15 may be, but is not limited to, a slotted liner with or without gravel packs, wire-wrapped screens with or without gravel packs, or pre-packed wire-wrapped screens. Likewise, injection interval 17 may preferably be, but is not limited to, sets of perforations 17a with or without gravel packs in casing 11 as shown in Fig. 8. As an alternative, injection interval 17 may be a slotted liner with or without gravel packs, wire- wrapped screens with or without gravel packs, or pre-packed wire-wrapped screens. As a further alternative, instead of using injection interval 17, the excess water may be injected directly into an open hole (not shown) within the subterranean strata. Preferably, however, injection interval 17 will be sets of perforations 17a.
It should be readily apparent to one skilled in the art that casing 11 may be provided with multiple producing intervals 15 and injection intervals 17 in communication with producing zone 12 and injection zone 19, respectively. Moreover, injection zone 19 can be the same formation as producing zone 12 provided that producing interval 15 and injection interval 17 are not communicating actively (i.e., fluid flow is isolated between producing interval 15 and injection interval 17). It should be understood by those of skill in the art, however, that fluids produced into casing 11 through producing interval 15 and water injected through injection interval 17 may influence the flow parameters of each other.
Casing 11 surrounds a tubing 24 which extends from ground surface 14 downwardly within casing 11. A first pump 10 may be sealingly disposed in tubing 24 and a second pump 20 may be coupled to a lower end of tubing 24 as shown in Fig. 8. First pump 10 and second pump 20 are uncoupled relative to each other. Particularly, first pump 10 is not drivingly coupled to second pump 20. First pump 10 and second pump 20 are preferably controlled by individual drives as will be described in more detail below. This configuration allows the individual pump rates to be separately controlled to respond to changing reservoir conditions. Moreover, individual rates of lift and injection can be separately controlled to optimize overall field performance. In the embodiment shown in Fig. 8, first pump 10 is a surface-driven rod pump and second pump 20 is an electrical submersible pump (ESP). An electrical submersible centrifugal pump (ESP) is particularly preferred. It should be apparent to one skilled in the art that first pump 10 could include any type of rod pump (including, for example, but not limited to, insert, tubing, and various American Petroleum Institute (API) pump types) to provide needed flexibility for varying conditions such as sand, gas, and corrosive conditions. It should be apparent to one of ordinary skill in the art that very little, if any, fluid can pass between the outer sealing edges of first pump 10 and tubing 24. Any conventional sealing mechanism may be used to provide the seal between first pump 10 and tubing 24, including, but not limited to, o-rings or slip rings.
A first, or upper inlet 30 is preferably disposed in tubing 24 below first pump 10. First inlet 30 is preferably disposed in a region of casing 11, or more particularly, in a region of a casing/tubing annulus 26, where segregated hydrocarbons and only a small amount of water are expected to be present. As shown in the exemplary embodiment in Fig. 8, first inlet 30 may be sets of perforations 30a in tubing 24. Alternatively, first inlet 30 may be a port or multiple ports or other suitable mechanism for conducting fluid flow, such as check valves. Preferably, however, first inlet 30 will be sets of perforations 30a. First inlet 30 is configured to permit the produced hydrocarbons and any small poition of water that has not segregated from the hydrocarbons to enter first pump 10. The operation of first inlet 30 will be described in more detail below.
A sucker rod string 9 is also disposed within tubing 24. Rod string 9 extends to ground surface 14 where it is reciprocated through an upstroke and a downstroke by a conventional pump drive 8 located at ground surface 14. Rod string 9 is coupled to first pump 10. As rod string 9 is reciprocated through an upstroke and a downstroke by pump drive 8, first pump 10 reciprocates through an upstroke and a downstroke.
A packer 16 is disposed within casing 11, preferably between producing interval 15 and injection interval 17. Casing 11 and packer 16 are configured to permit produced hydrocarbons and produced water to collect above packer 16. By "produced hydrocarbons" is meant crude oil, gas, gas condensate, and various combinations thereof. Particularly, tubing 24, casing 11, and packer 16, together define casing/tubing annulus 26 that extends upward to ground surface 14. Hydrocarbons, such as oil or gas, and water flow or are
"produced," into casing 11 through producing interval 15. The hydrocarbons and water segregate by gravity within casing-tubing annulus 26 forming a hydrocarbon/water interface
28. "Gravity segregation," as used herein, is intended to describe the preservation of the isolation between produced hydrocarbons and water, as opposed to separation which indicates that a mixture is mechanically divided into separate fluids. Thus, the produced hydrocarbons and water are allowed to collect in annulus 26 above packer 16 and to segregate by gravity to form segregated produced water 23 below hydrocarbon/water interface 28, and hydrocarbons and a portion of produced water 25 above hydrocarbon/water interface 28. If, during production, pump capacity exceeds water production capacity of producing zone 15, then the operator may decrease the pump speed, change the sheaves, put the pump on a timer, or add surface water into casing/tubing annulus 26 in order to maintain production.
Second pump 20, as shown in Fig. 8, may be disposed at a lower end of a first tubing section 24a of tubing 24. Second pump 20 preferably includes a pump section 20a, a seal section 20b, and a motor 20c, which is preferably disposed above pump section 20a. A second or lower inlet 13 is shown disposed on a second tubing section 24b of tubing 24 and between seal section 20b and motor 20c and above pump section 20a. Alternatively, second inlet 13 may be disposed in tubing 24 above motor 20c. Second inlet 13 is preferably disposed in a region of casing 11, or more particularly, in a region of casing/tubing annulus 26, where primarily only the heavier segregated produced water is present (i.e., inlet 13 is in fluid-flow communication primarily with segregated produced water 23). As shown in Fig. 8, second inlet 13 may be sets of perforations 13a in tubing 24 or second tubing section 24b. Second inlet 13 is configured to permit the segregated produced water from the production zone 12 to enter second pump 20 and/or to provide cooling to motor 20c which will be described in more detail below. Preferably, tubing 24 includes a third tubing section 24c which may be coupled to second pump 20. Third tubing section 24c extends below packer 16 in casing 11 to permit segregated produced water 23 to be injected into injection zone 19.
A variable speed drive 22 may be disposed at ground surface 14 to provide power to and control the pump rate of second pump 20, an ESP. Variable speed drive 22 is electrically connectable to motor 20c of the ESP via an electrical line or cable 21.
Reference will now be made to the operation of the seventh exemplary embodiment shown in Fig. 8. In operation, produced fluids (hydrocarbons and water) are produced from production zone 12 via intervals 15 into casing 11 above packer 16 thereby forming a column of produced hydrocarbons and water within casing/tubing annulus 26. The lighter produced fluids (mostly hydrocarbons 25) rise to the top of the column while the heavier fluids (mostly water 23) settle to the bottom of the column.
During the upstroke of first, or rod pump 10, segregated hydrocarbons and a small poition of water 25 flow through first inlet 30 and into tubing 24 below first pump 10. A traveling valve (not shown) disposed in first pump 10 is open during the upstroke which permits the segregated hydrocarbons and portion of water to flow through first pump 10 to form a column of produced fluid 32 above first pump 10. As the upstroke continues, a portion of the column of produced fluid 32 is conducted or lifted to ground surface 14 and collected in a conventional manner. It is preferred that, during production, hydrocarbon/water interface 28 is maintained adjacent first inlet 30 in order to provide stabilized pumping conditions. In order to meet the capacity of first pump 10 and to ensure that hydrocarbon/water interface 28 is maintained adjacent first inlet 30, an upper portion of segregated produced water 23 (in addition to produced hydrocarbons and poition of produced water 25) may be "pulled" by first pump 10 through first inlet 30 and pumped to ground surface 14.
Simultaneously, during the upstroke and downstroke of first pump 10, segregated produced water which has settled at the bottom of casing/tubing annulus 26 flows through second inlet 13 and into second pump, or ESP 20. The segregated water is then injected through the end of tubing section 24c and into casing 11 below packer 16 and thereafter into injection zone 19.
It should be understood by one skilled in the art that second pump 20 (ESP) may include sensors for flow rate, pressure, and temperature. As noted above, the ESP may be variably controlled by variable speed drive 22 thereby allowing maximum flexibility in selecting pump output to optimize reservoir performance and to allow conformance to changing reservoir conditions. Moreover, because first pump 10 and second pump 20 are separately and independently controlled (i.e., first pump 10 controlled by pump drive 8 and second pump 20 controlled by variable speed drive 22), their respective pump output may be separately and independently varied to correspond to the changing reservoir conditions during production. The entire combination of first pump 10 and second pump 20 may typically be about
30 feet to several hundred feet in length. Moreover, the distance from producing interval 15 to packer 16, percentage of water cut and injection rate, and designed production rate can all be variables in deciding whether it is desirable to place second pump 20 just above packer 16 or higher in the well. Reference will now be made to Fig. 9, wherein a bypass conduit 36 is shown coupled to second pump (ESP) 20 for injecting produced water into a disposal zone 19 which is located above production zone 12. In this embodiment, second pump 20 is preferably disposed at the end of tubing 24 in an inverted position relative to the position in the embodiment shown in Fig. 8 (i.e., motor 20c disposed below pump section 20a in the embodiment shown in Fig. 9). Inlet 13 is preferably disposed in tubing 24 below pump section 20a.
As can be seen in Fig. 9, bypass conduit 36 extends up casing/tubing annulus 26 and through a passage 16a in packer 16. A second packer 27 is disposed in casing 11 preferably above injection zone 19. Packers 16 and 27 are configured to isolate injection zone 19 within casing 11 from both producing zone 19 and, for example, an isolated aquifer 40.
A tubing plug 38 may be disposed in tubing 24 between first pump 10 and second pump 20 in order to isolate segregated hydrocarbons and a portion of the produced water 25 from segregated produced water 23 within tubing 24. During operation of the system shown in Fig. 9, the first, or rod pump 10 lifts segregated produced hydrocarbons and a poition of the produced water 25 to the ground surface 14 in the manner described above with reference to Fig. 8. At the same time, second pump (ESP) 20 pumps segregated produced water 23 that enters second pump 20 through second inlet 13 through bypass conduit 36 and thereafter into disposal zone 19 via injection interval 17.
Reference will now be made to Fig. 10, wherein an eighth exemplary embodiment of the present invention is shown employing second pump 20 for lifting produced fluids to the ground surface and first pump 10 for re-injecting water. Such a combination would be highly efficient for lifting a large volume of produced hydrocarbons to the ground surface while injecting a small volume of produced water. Like reference numerals will be used where appropriate to describe similar elements to those of the embodiment shown in Fig. 8.
In Fig. 10, first pump 10 is shown disposed in tubing 24, which extends below packer 16 in casing 11. Second pump 20 is shown suspended from a branch conduit 34 or what is generally referred to in the art as a "Y-tool". First pump 10 is preferably a surface driven rod pump which has been modified by removing the traveling valve such that the pump acts as a piston within tubing 24 (the operation of first pump 10 will be described in more detail below). Second pump 20 is preferably an electrical submersible pump. The remaining elements shown in Fig. 10 have been described above and, for the sake of brevity, such descriptions are herein incorporated by reference.
Reference will now be made to the operation of the eighth exemplary embodiment shown in Fig. 10. In operation, produced fluids (hydrocarbons and water) are produced from production zone 12 via interval 15 into casing 11 above packer 16 forming a column of produced hydrocarbons and water within casing/tubing annulus 26. The lighter produced fluids (mostly hydrocarbons) rise to the top of the column while the heavier fluids (mostly water) settle to the bottom of the column.
During the upstroke of first, or rod pump 10, segregated produced water 23 flows through second inlet 13 and into tubing 24 below first pump 10. Because the traveling valve has been removed from first pump 10 and first pump 10 is sealingly disposed within tubing 24, produced water 23 will not pass through first pump 10 (i.e., first pump 10 will act as a piston within tubing 24). During the downstroke, produced water 23 in tubing 24 below first pump 10 is forced or injected through the end of tubing 24 below packer 16, into casing 11, and thereafter into injection zone 19. Simultaneously, segregated hydrocarbons, and a poition of the produced water 25 that has not settled to the bottom, flow into first inlet 30 into second pump 20. Second pump 20 pumps the segregated produced hydrocarbons and portion of produced water 25 through Y-tool 34 and tubing 24 to ground surface 14 where it is collected in a well-known manner.
It should be understood by one of ordinary skill in the art that the segregated hydrocarbons and poition of produced water 25 is separated from the segregated produced water 23 within tubing 24 via first pump 10 acting as a piston. Alternatively, a tubing plug (not shown) may be placed above first pump 10 in tubing 24 to provide a secondary separator.
Referring now to Fig. 11, there is illustrated, in a schematic side-elevation sectional view, a ninth exemplary embodiment of the present invention and is represented generally by reference numeral 5. A casing 11 is shown extending from a ground surface 14 downwardly within a subterranean well through a hydrocarbon and water producing or production zone 12 and then to a water injection zone 19. It should be understood by one of ordinary skill in the art that injection zone 19 may alternatively be referred to as a disposal zone. It is preferable to have a long distance or an isolation zone 18 between producing zone 12 and injection zone 19.
As shown in Fig. 11, casing 11 has a producing interval, shown generally at 15, separated from an injection interval, shown generally at 17. Producing interval 15 is located adjacent to and in fluid flow communication with producing zone 12. In a similar manner, injection interval 17 is located adjacent to and in fluid flow communication with disposal, or injection zone 19. Producing interval 15 may preferably be for example, but is not limited to, perforations 15a with or without gravel packs in casing 11 as shown in Fig. 11. Alternatively, producing interval 15 may be, but is not limited to, a slotted liner with or without gravel packs, wire-wrapped screens with or without gravel packs, or pre-packed wire-wrapped screens. Likewise, injection interval 17 may preferably be, but is not limited to, perforations 17a with or without gravel packs in casing 11 as shown in Fig. 11. As an alternative, injection interval 17 may be a slotted liner with or without gravel packs, wire- wrapped screens with or without gravel packs, or pre-packed wire- wrapped screens. As a further alternative, instead of using injection interval 17, the excess water may be injected directly into an open hole (not shown) within the subterranean strata. Preferably, however, injection interval 17 will be perforations 17a.
It should be readily apparent to one skilled in the art that casing 11 may be provided with multiple producing intervals 15 and injection intervals 17 in communication with producing zone 12 and injection zone 19, respectively. Moreover, injection zone 19 can be the same formation as producing zone 12 provided that producing interval 15 and injection interval 17 are not communicating actively (i.e., fluid flow is isolated between producing interval 15 and injection interval 17). It should be understood by those of skill in the art, however, that fluids produced into casing 11 through producing interval 15 and water injected through injection interval 17 may influence the flow parameters of each other.
Casing 11 surrounds a tubing 24 which extends from ground surface 14 downwardly within casing 11. A first pump 10 is disposed in tubing 24 and a second pump 20 may be disposed in a lower end of tubing 24 as shown in Fig. 11. Alternatively, first pump 10 may be coupled to tubing 24 by any suitable method such as threaded connections. In such an embodiment, it should be apparent to one of ordinary skill in the art that tubing 24 would preferably comprise two tubing sections. The first tubing section extends downwardly with casing 11 and is coupled to one end of first pump 10. The second tubing section is coupled to the other end of first pump 10 and extends downwardly within casing 11. Second pump 20, as described above, may be disposed within tubing 24, or more particularly in the second tubing section, below first pump 10. First pump 10 and second pump 20 are uncoupled relative to each other. Particularly, first pump 10 is not drivingly coupled to second pump 20. First pump 10 and second pump 20 are preferably controlled by individual drives as will be described in more detail below. This configuration allows the individual pump rates to be separately controlled to respond to changing reservoir conditions. Moreover, individual rates of lift and injection can be separately controlled to optimize overall field performance. In the embodiment shown in Fig. 11, first pump 10 is a surface rod-driven progressive cavity pump (RD-PCP) and second pump 20 is an electrical submersible progressive cavity pump (ESPCP). Alternately, first pump 10 could be an electrical submersible progressive cavity pump powered by the same or different variable speed drive (as will be described in more detail below) that provides power to second pump 20.
A packer 16 is disposed within casing 11, preferably between producing interval 15 and injection interval 17. Casing 11 and packer 16 are configured to permit produced hydrocarbons and produced water to collect above packer 16. By "produced hydrocarbons" is meant crude oil, gas, gas condensate, and various combinations thereof. Particularly, tubing 24, casing 11, and packer 16, together define casing/tubing annulus 26 that extends upward to ground surface 14. Hydrocarbons, such as oil or gas, and water flow or are "produced," into casing 11 through producing interval 15. The hydrocarbons and water segregate by gravity within casing-tubing annulus 26 forming a hydrocarbon/water interface 28. "Gravity segregation," as used herein, is intended to describe the preservation of the isolation between produced hydrocarbons and water, as opposed to separation which indicates that a mixture is mechanically divided into separate fluids. Thus, the produced hydrocarbons and water are allowed to collect in annulus 26 above packer 16 and to segregate by gravity to form segregated produced water 23 below hydrocarbon water interface 28, and hydrocarbons and a small poition or proportion of produced water 25 above hydrocarbon/water interface 28.
A first, or upper inlet 30 is preferably disposed in tubing 24 below first pump 10. First inlet 30 is preferably disposed in a region of casing 11, or more particularly, in a region of a casing/tubing annulus 26, where segregated hydrocarbons and only a small amount of water are expected to be present and preferably, adjacent hydrocarbon water interface 28. As shown in the exemplary embodiment in Fig. 11, first inlet 30 may be sets of perforations 30a in tubing 24. Alternatively, first inlet 30 may be a port or multiple ports or other suitable mechanism for conducting fluid flow. Preferably, however, first inlet 30 will be sets of perforations 30a. First inlet 30 is configured to permit the produced hydrocarbons and any small portion of water that has not segregated from the hydrocarbons to enter first pump 10. The operation of first inlet 30 will be described in more detail below.
A sucker rod string 9 is also disposed within tubing 24. Rod string 9 extends to ground surface 14 where it is rotated by a motor 8 located at ground surface 14. Preferably, motor 8 is coupled to a drive head (not shown) and rod string 9 is coupled to the drive head in a manner which is well-known to one of ordinary skill in the art. Rod string 9 is coupled to first pump 10. As rod string 9 is rotated by motor 8, first pump 10 likewise is rotated. Detail of this rotation will be described in more detail with reference to Fig. 21.
Second pump 20, as shown in Fig. 11, is disposed in a lower end of tubing 24. A second or lower inlet 13 is shown disposed in tubing 24 above pump 20. Second inlet 13 is preferably disposed in a region of casing 11, or more particularly, in a region of casing/tubing annulus 26, where primarily only the heavier segregated produced water is present (i.e., inlet 13 is in fluid-flow communication primarily with segregated produced water 23). As shown in Fig. 11, second inlet 13 may be sets of perforations 13a in tubing 24. Second inlet 13 is configured to permit the segregated produced water from the production zone 12 to enter second pump 20 which will be described in more detail below.
Preferably, tubing 24 extends below packer 16 in casing 11 to permit segregated produced water 23 to be injected into injection zone 19. A tubing plug 38 may be disposed in tubing 24 between first pump 10 and second pump 20 in order to isolate segregated hydrocarbons and a portion of produced water 25 from segregated produced water 23 within tubing 24.
A variable speed drive 22 may be disposed at ground surface 14 to provide power to and control the pump rate of second pump 20. Variable speed drive 22 is electrically connectable to second pump 20 via an electrical line or cable 21. Likewise as noted above, motor 8 is disposed at ground surface 14 to provide power to and control the pump rate of first pump 10. In an embodiment where first pump 10 is also an electrical submersible progressive cavity pump, variable speed drive 22 can be used to provide power to first pump 10, or a second variable speed drive can be used. Reference will now be made to the operation of the ninth exemplary embodiment shown in Fig. 11. In operation, produced fluids (hydrocarbons and water) are produced from production zone 12 via intervals 15 into casing 11 above packer 16, thereby forming a column of produced hydrocarbons and water within casing/tubing annulus 26. The lighter produced fluids (mostly hydrocarbons 25) rise to the top of the column while the heavier fluids (mostly water 23) settle to the bottom of the column.
During rotation of first pump 10, segregated hydrocarbons and a small portion of produced water 25 flow or are "pulled" through first inlet 30 and into tubing 24 below first pump 10. First pump 10 then pumps the segregated hydrocarbons and a small poition of produced water 25 (as will be described in more detail with reference to Fig. 21) through tubing 24 to ground surface 14 where it is collected in a conventional manner. It is preferred that, during production, hydrocarbon/water interface 28 is maintained adjacent first inlet 30 in order to provide stabilized pumping conditions. In order to meet the capacity of first pump 10 and to ensure that hydrocarbon/water interface 28 is maintained adjacent first inlet 30, an upper portion of segregated produced water 23 (in addition to produced hydrocarbons and portion of produced water 25) may be "pulled" by first pump 10 through first inlet 30 and pumped to ground surface 14.
Simultaneously, segregated produced water which has settled at the bottom of casing/tubing annulus 26 flows through second inlet 13 and into second pump 20. The segregated water is then pumped or injected (as will be described in more detail with reference to Fig. 21) through the end of tubing 24 and into casing 11 below packer 16 and thereafter into injection zone 19.
It should be understood by one skilled in the art that first pump 10 and second pump 20 may include sensors (not shown) for flow rate, pressure, and temperature measurement or other types of control information which is transmitted to motor 8 and/or variable speed drive 22. Thus, first pump 10 and second pump 20 are individually and independently controllable to provide maximum flexibility in selecting pump output to optimize reservoir performance and to allow conformance to changing reservoir conditions. Moreover, because first pump 10 and second pump 20 are separately controlled (i.e., first pump 10 is controlled by motor 8 and second pump 20 is controlled by variable speed drive 22), their respective pump output may be separately and independently varied to correspond to the changing reservoir conditions during production.
The entire combination of first pump 10 and second pump 20 may typically be about 30 feet to several hundred feet in length. Moreover, the distance from producing interval 15 to packer 16, percentage of water cut and injection rate, and designed production rate can all be variables in deciding whether it is desirable to place second pump 20 just above packer 16 or higher in the well.
Reference will now be made to Fig. 12, wherein a bypass conduit 36 is shown coupled to second pump 20 for injecting produced water into disposal zone 19 which is located above producing zone 12. As can be seen in Fig. 12, bypass conduit 36 extends up casing/tubing annulus 26 and through a passage 16a in packer 16. A second packer 27 is disposed in casing 11 preferably above injection zone 19. Packer 16 and second packer 27 are configured to isolate injection zone 19 within casing 11 from both producing zone 12 and, for example, an isolated aquifer 40. Second inlet 13 is shown disposed on a lower end of second pump 20 such that segregated produced water 23 passing through second pump 20 may be used for cooling purposes.
A tubing plug 38 may be disposed in tubing 24 between first pump 10 and second pump 20 in order to isolate segregated hydrocarbons and a poition of produced water 25 from segregated produced water 23 within tubing 24.
During operation of the system shown in Fig. 12, first pump 10 lifts segregated produced hydrocarbons and a small proportion or portion of produced water 25 to ground surface 14 in the manner described above with reference to Fig. 11. At the same time, second pump 20 pumps segregated produced water 23 that enters second pump 20 through second inlet 13 through bypass conduit 36 and thereafter into disposal zone 19 via injection interval 17.
Reference will now be made to Fig. 13, wherein a tenth exemplary embodiment of the present invention is shown employing second pump 20 for lifting produced fluids to the ground surface and first pump 10 for re-injecting water. Like reference numerals will be used where appropriate to describe similar elements to those of the embodiment shown in
Fig. 11.
In Fig. 13, first pump 10 is shown disposed in tubing 24, which extends below packer
16 in casing 11. Second pump 20 is shown disposed in a branch conduit 34 or what is generally referred to in the art as a "Y-tool". First pump 10 is preferably a surface rod-driven progressive cavity pump. Because first pump 10, or the surface rod-driven progressive cavity pump, is being used to pump in a downward direction, it is preferable to dispose a thrust bearing (not shown) at the top of first pump 10 since the force on the rotor (which will be described in more detail below) is upward. Second pump 20 is preferably an electrical submersible progressive cavity pump. First inlet 30 is disposed in branch conduit 34 below second pump 20 and second inlet 13 is disposed in tubing 24 above first pump 10. The remaining elements shown in Fig. 13 have been described above and for the sake of brevity, such descriptions are herein incorporated by reference.
Reference will now be made to the operation of the tenth exemplary embodiment shown in Fig. 13. In operation, produced fluids (hydrocarbons and water) are produced from production zone 12 via interval 15 into casing 11 above packer 16 forming a column of produced hydrocarbons and water within casing/tubing annulus 26. The lighter produced fluids (mostly hydrocarbons 25) rise to the top of the column while the heavier fluids (mostly water 23) settle to the bottom of the column. During rotation of first pump 10, segregated produced water 23 flows through second inlet 13 and into tubing 24 above first pump 10. First pump 10 then forces or injects segregated produced water 23 through the end of tubing 24 below packer 16, into casing 11, and thereafter into injection zone 19. Simultaneously, segregated produced hydrocarbons and a portion of produced water 25 that has not settled to the bottom, flow into first inlet 30 into second pump 20. Second pump 20 pumps the segregated produced hydrocarbons and portion of produced water 25 through Y-tool 34 and tubing 24 to ground surface 14 where it is collected in a well-known manner. Alternatively, the segregated produced hydrocarbons could be produced up casing/tubing annulus 26 to ground surface 14 if sufficient pressure exists in the reservoir.
Tubing plug 38 may be disposed in tubing 24 above first pump 10 and preferably below the intersection of Y-tool 34 and tubing 24 in order to isolate segregated produced hydrocarbons and a poition of produced water 25 from segregated produced water 23 in tubing 24. Referring now to Fig. 14, there is illustrated, in a schematic side-elevation sectional view, an eleventh exemplary embodiment of the present invention and is represented generally by reference numeral 5. A casing 11 is shown extending from a ground surface 14 downwardly within a subterranean well through a hydrocarbon and water producing or production zone 12 and then to a water injection zone 19. It should be understood by one of ordinary skill in the art that injection zone 19 may alternatively be referred to as a disposal zone. It is preferable to have a long distance or an isolation zone 18 between producing zone 12 and injection zone 19.
As shown in Fig. 14, casing 11 has a producing interval, shown generally at 15, separated from an injection interval, shown generally at 17. Producing interval 15 is located adjacent to and in fluid flow communication with producing zone 12. In a similar manner, injection interval 17 is located adjacent to and in fluid flow communication with disposal, or injection zone 19. Producing interval 15 may preferably be for example, but is not limited to, perforations 15a with or without gravel packs in casing 11 as shown in Fig. 14. Alternatively, producing interval 15 may be, but is not limited to, a slotted liner with or without gravel packs, wire-wrapped screens with or without gravel packs, or pre-packed wire-wrapped screens. Likewise, injection interval 17 may preferably be, but is not limited to, perforations 17a with or without gravel packs in casing 11 as shown in Fig. 14. As an alternative, injection interval 17 may be a slotted liner with or without gravel packs, wire- wrapped screens with or without gravel packs, or pre-packed wire-wrapped screens. As a further alternative, instead of using injection interval 17, the excess water may be injected directly into an open hole (not shown) within the subterranean strata. Preferably, however, injection interval 17 will be perforations 17a.
It should be readily apparent to one skilled in the art that casing 11 may be provided with multiple producing intervals 15 and injection intervals 17 in communication with producing zone 12 and injection zone 19, respectively. Moreover, injection zone 19 can be the same formation as producing zone 12 provided that producing interval 15 and injection interval 17 are not communicating actively (i.e., fluid flow is isolated between producing interval 15 and injection interval 17). It should be understood by those of skill in the art, however, that fluids produced into casing 11 through producing interval 15 and water injected through injection interval 17 may influence the flow parameters of each other.
Casing 11 surrounds a tubing 24 which extends from ground surface 14 downwardly within casing 11. A first pump 10 is coupled to tubing 24, or more particularly, to an end of tubing section 24a by any suitable method such as threaded connections. Preferably, a second tubing section 24b extends between, and is coupled to, first pump 10 and second pump 20. Alternatively, first pump 10 may be disposed within tubing 24, or more particularly, first tubing section 24a. In such an embodiment, second pump 20 may be coupled at one end of first tubing section 24a thereby eliminating second tubing section 24b. First pump 10 and second pump 20 are uncoupled relative to each other. Particularly, first pump 10 is not drivingly coupled to second pump 20. First pump 10 and second pump 20 are preferably controlled by individual drives as will be described in more detail below. This configuration allows the individual pump rates to be separately controlled to respond to changing reservoir conditions. Moreover, individual rates of lift and injection can be separately controlled to optimize overall field performance.
In the embodiment shown in Fig. 14, first pump 10 is a surface rod-driven progressive cavity pump (RD-PCP) and second pump 20 is an electrical submersible pump
(ESP). An electrical submersible centrifugal pump is particularly preferred.
A packer 16 is disposed within casing 11, preferably between producing interval 15 and injection interval 17. Casing 11 and packer 16 are configured to permit produced hydrocarbons and produced water to collect above packer 16. By "produced hydrocarbons" is meant crude oil, gas, gas condensate, and various combinations thereof. Particularly, tubing 24, casing 11, and packer 16, together define casing/tubing annulus 26 that extends upward to ground surface 14. Hydrocarbons, such as oil or gas, and water flow or are "produced," into casing 11 through producing interval 15. The hydrocarbons and water segregate by gravity within casing-tubing annulus 26 forming a hydrocarbon/water interface 28. "Gravity segregation," as used herein, is intended to describe the preservation of the isolation between produced hydrocarbons and water, as opposed to separation which indicates that a mixture is mechanically divided into separate fluids. Thus, the produced hydrocarbons and water are allowed to collect in annulus 26 above packer 16 and to segregate by gravity to form segregated produced water 23 below hydrocarbon water interface 28, and hydrocarbons and a small portion or proportion of produced water 25 above hydrocarbon/water interface 28. 6δ
A first, or upper inlet 30 is preferably disposed in tubing 24 below first pump 10. First inlet 30 is preferably disposed in a region of casing 11, or more particularly, in a region of a casing/tubing annulus 26, where segregated hydrocarbons and only a small amount of water are expected to be present and preferably, adjacent hydrocarbon/water interface 28. As shown in the exemplary embodiment in Fig. 14, first inlet 30 may be sets of perforations 30a in tubing 24. Alternatively, first inlet 30 may be a port or multiple ports or other suitable mechanism for conducting fluid flow. Preferably, however, first inlet 30 will be sets of perforations 30a. First inlet 30 is configured to permit the produced hydrocarbons and any small portion of water that has not segregated from the hydrocarbons to enter first pump 10. The operation of first inlet 30 will be described in more detail below.
A sucker rod string 9 is also disposed within tubing 24. Rod string 9 extends to ground surface 14 where it is rotated by a motor 8 located at ground surface 14. Rod string 9 is coupled to first pump 10. As rod string 9 is rotated by motor 8, first pump 10 likewise is rotated. Detail of this rotation will be described in more detail with reference to Fig. 21. Second pump 20, as shown in Fig. 14, may be disposed at a lower end of tubing 24, or more particularly, second tubing section 24b. Second pump 20 preferably includes a pump section 20a, a seal section 20b, and a motor 20c, which is preferably disposed above pump section 20a. A second or lower inlet 13 is shown disposed on second pump 20 between seal section 20b and motor 20c and above pump section 20a. Alternatively, second inlet 13 may be disposed in second tubing section 24b above motor 20c. Second inlet 13 is preferably disposed in a region of casing 11, or more particularly, in a region of casing/tubing annulus 26, where primarily only the heavier segregated produced water is present (i.e., inlet 13 is in fluid-flow communication primarily with segregated produced water 23). As shown in Fig. 14, second inlet 13 may be sets of perforations 13a. Second inlet 13 is configured to permit the segregated produced water from the production zone 12 to enter second pump 20 which will be described in more detail below.
Preferably, tubing 24 includes a third tubing section 24c which may be coupled to second pump 20. Third tubing section 24c preferably extends below packer 16 in casing 11 to permit segregated produced water 23 to be injected into injection zone 19. A tubing plug 38 may be disposed in second tubing section 24b between first pump 10 and second pump 20 in order to isolate segregated hydrocarbons and portion of produced water 25 from segregated produced water 23 within tubing 24, or more particularly, within second tubing section 24b. A variable speed drive 22 may be disposed at ground surface 14 to provide power to and control the pump rate of second pump 20. Variable speed drive 22 is electrically connectable to motor 20c of second pump 20 via an electrical line or cable 21. Likewise as noted above, motor 8 is disposed at ground surface 14 to provide power to and control the pump rate of first pump 10. Reference will now be made to the operation of the eleventh exemplary embodiment shown in Fig. 14. In operation, produced fluids (hydrocarbons and water) are produced from production zone 12 via intervals 15 into casing 11 above packer 16, thereby forming a column of produced hydrocarbons and water within casing/tubing annulus 26. The lighter produced fluids (mostly hydrocarbons 25) rise to the top of the column while the heavier fluids (mostly water 23) settle to the bottom of the column.
During rotation of first pump 10, segregated hydrocarbons and a small portion of produced water 25 flow or are "pulled" through first inlet 30 and into tubing 24 below first pump 10. First pump 10 then pumps the segregated hydrocarbons and a small poition of produced water 25 (as will be described in more detail with reference to Fig. 21) through tubing 24 to ground surface 14 where it is collected in a conventional manner. It is preferred that, during production, hydrocarbon/water interface 28 is maintained adjacent first inlet 30 in order to provide stabilized pumping conditions. In order to meet the capacity of first pump 10 and to ensure that hydrocarbon/water interface 28 is maintained adjacent first inlet 30, an upper portion of segregated produced water 23 (in addition to produced hydrocarbons and poition of produced water 25) may be "pulled" by first pump 10 through first inlet 30 and pumped to ground surface 14.
Simultaneously, segregated produced water which has settled at the bottom of casing/tubing annulus 26 flows through second inlet 13 and into second pump 20. The segregated water is then injected through the end of tubing section 24c and into casing 11 below packer 16 and thereafter into injection zone 19.
It should be understood by one skilled in the art that first pump 10 and second pump 20 may include sensors (not shown) for flow rate, pressure, and temperature measurement or other types of control information which is transmitted to motor 8 and/or variable speed drive 22. Thus, first pump 10 and second pump 20 are individually and independently controllable to provide maximum flexibility in selecting pump output to optimize reservoir performance and to allow conformance to changing reservoir conditions. Moreover, because first pump 10 and second pump 20 are separately controlled (i.e., first pump 10 is controlled by motor 8 and second pump 20 is controlled by variable speed drive 22), their respective pump output may be separately and independently varied to correspond to the changing reservoir conditions during production.
The entire combination of first pump 10 and second pump 20 may typically be about 30 feet to several hundred feet in length. Moreover, the distance from producing interval 15 to packer 16, percentage of water cut and injection rate, and designed production rate can all be variables in deciding whether it is desirable to place second pump 20 just above packer 16 or higher in the well.
Reference will now be made to Fig. 15, wherein a bypass conduit 36 is shown coupled to second pump 20 for injecting produced water into disposal zone 19 which is located above producing zone 12. In this embodiment, second pump 20 is preferably disposed at the end of tubing 24, or more particularly, second tubing section 24b, in an inverted position relative to the position in the embodiment shown in Fig. 14 (i.e., motor 20c is disposed below pump section 20a in the embodiment shown in Fig. 15). Inlet 13 is preferably disposed on second pump 20 below pump section 20a. As can be seen in Fig. 15, bypass conduit 36 extends up casing/tubing annulus 26 and through a passage 16a in packer 16. A second packer 27 is disposed in casing 11 preferably above injection zone 19. Packer 16 and second packer 27 are configured to isolate injection zone 19 within casing 11 from both producing zone 12 and, for example, an isolated aquifer
40. A tubing plug 38 may be disposed in tubing 24 between first pump 10 and second pump 20 in order to isolate segregated hydrocarbons and a portion of produced water 25 from segregated produced water 23 within tubing 24.
During operation of the system shown in Fig. 15, first pump 10 lifts segregated produced hydrocarbons and a portion of produced water 25 to ground surface 14 in the manner described above with reference to Fig. 14. At the same time, second pump 20 pumps segregated produced water 23 that enters second pump 20 through second inlet 13 through bypass conduit 36 and thereafter into disposal zone 19 via injection interval 17.
Reference will now be made to Fig. 16, wherein a twelfth exemplary embodiment of the present invention is shown employing second pump 20 for lifting produced fluids to the ground surface and first pump 10 for re-injecting water. Like reference numerals will be used where appropriate to describe similar elements to those of the embodiment shown in Fig. 14.
In Fig. 16, first pump 10 is shown coupled to first tubing section 24a and second tubing section 24b. Second tubing section 24b extending below packer 16 in casing 11. Second pump 20 is shown suspended from a branch conduit 34, or what is generally referred to in the art as a "Y-tool," which is coupled to tubing 24, or more particularly, to first tubing section 24a. First pump 10 is preferably a surface rod-driven progressive cavity pump. Second pump 20 is preferably an electrical submersible pump, more preferably, an electrical submersible centrifugal pump. First inlet 30 is preferably disposed on second pump 20. Alternatively, first inlet 30 may be disposed in branch conduit 34. Second inlet 13 is preferably disposed in first tubing section 24a above first pump 10. The remaining elements shown in Fig. 16 have been described above and for the sake of brevity, such descriptions are herein incorporated by reference. Reference will now be made to the operation of the twelfth exemplary embodiment shown in Fig. 16. In operation, produced fluids (hydrocarbons and water) are produced from production zone 12 via interval 15 into casing 11 above packer 16 forming a column of produced hydrocarbons and water within casing/tubing annulus 26. The lighter produced fluids (mostly hydrocarbons 25) rise to the top of the column while the heavier fluids (mostly water 23) settle to the bottom of the column.
During rotation of first pump 10, segregated produced water 23 flows through second inlet 13 and into tubing 24 above first pump 10. First pump 10 then forces or injects segregated produced water 23 through the end of tubing 24 below packer 16, into casing 11, and thereafter into injection zone 19. Simultaneously, segregated produced hydrocarbons and a portion of produced water 25 that has not settled to the bottom, flow into first inlet 30 into second pump 20. Second pump 20 pumps the segregated produced hydrocarbons and portion of produced water 25 through Y-tool 34 and tubing 24 to ground surface 14 where it is collected in a well-known manner. Alternatively, the segregated produced hydrocarbons could be produced up casing/tubing annulus 26 to ground surface 14 if sufficient pressure exists in the reservoir.
Tubing plug 38 may be disposed in tubing 24 between second inlet 13 or first pump 10 and first inlet 30 or the intersection of Y-tool 34 and tubing 24 in order to isolate segregated produced hydrocarbons and a portion of produced water 25 from segregated produced water 23 in tubing 24.
Reference will now be made to Fig. 17, wherein a thirteenth exemplary embodiment of the present invention is shown employing a first pump 10 coupled to a first tubing 24 and a second pump 20 coupled to a second tubing 29. Tubing 24 and tubing 29 are preferably coupled to suitable fluid collection mechanisms (not shown), such as tanks or pipelines, at ground surface 14. First pump 10 may be an electrical submersible pump, an electrical submersible progressive cavity pump, or any other suitable downhole pump. Similarly, second pump 20 may be an electrical submersible pump, an electrical submersible progressive cavity pump, or any other suitable downhole pump. First pump 10 is not drivingly coupled to second pump 20. A first variable speed drive 36 may be disposed at ground surface 14 to provide power to and control the pump rate of first pump 10. First pump 10 is preferably coupled to first variable speed drive 36 by a first electrical line or cable 34. Similarly, a second variable speed drive 40 may be disposed at ground surface 14 to provide power to and control the pump rate of second pump 20. Second pump 20 is preferably coupled to second variable speed drive 40 by a second electrical line or cable 37.
A casing 11 is shown extending from ground surface 14 downwardly within the subterranean well through a hydrocarbon and water producing zone 12. Casing 11 has a producing interval, shown generally at 15, located adjacent to and in fluid flow communication with producing zone 12. As described above, producing interval 15 may be sets of perforations 15a. A mechanical sealing device, or "seal" 16 is shown disposed within casing 11, preferably below second pump 20. Seal 16 may preferably be a bridge plug, a packer, or other suitable mechanical sealing device used when encroachment of water from downhole in casing 11 is a problem. It should be understood by one of ordinary skill in the art that packer 16 may not be required if water encroachment is not a problem or if conditions within the well permit produced hydrocarbons and produced water to sufficiently collect in casing 11 and to segregate under the influence of gravity. Casing 11, seal 16, tubing 24, and tubing 29, together define casing/tubing annulus 26 that extends upward to ground surface 14. Hydrocarbons, such as oil or gas, and water flow or are "produced," into casing 11 through producing interval 15. The hydrocarbons and water segregate by gravity within casing/tubing annulus 26 forming a hydrocarbon/water interface 28. Thus, the produced hydrocarbons and water are allowed to collect in annulus 26 above seal 16 and to segregate by gravity to form segregated produced water 23 below hydrocarbon/water interface 28 and segregated produced hydrocarbons and a small proportion or portion of produced water 25 above hydrocarbon/water interface 28.
A first, or upper inlet 30 is preferably disposed at a lower end of first pump 10. First inlet 30 is preferably disposed in a region of casing 11, or more particularly, in a region of casing/tubing annulus 26, where segregated hydrocarbons and only a small proportion or portion of water 25 are expected to be present and preferably, adjacent hydrocarbon/water interface 28. First inlet 30 is preferably sets of perforations 30a. The operation of first inlet 30 will be described in more detail below.
A second, or lower inlet 13 is shown disposed at a lower end of second pump 20. Second inlet 13 is preferably disposed in a region of casing 11, or more particularly, in a region of casing/tubing annulus 26, where primarily only the heavier segregated produced water 23 is present (i.e., inlet 13 is in fluid-flow communication primarily with segregated produced water 23). Second inlet 13 is preferably sets of perforations 13a.
Reference will now be made to the operation of the exemplary embodiment shown in Fig. 17. In operation, produced fluids (hydrocarbons and water) are produced from producing zone 12 via intervals 15 into casing 11 above seal 16 forming a column of produced hydrocarbons and water within casing/tubing annulus 26. The lighter produced fluids (mostly hydrocarbons 25) rise to the top of the column while the heavier fluids (mostly water 23) settle to the bottom of the column. Segregated hydrocarbons and a small portion of water 25 then flow through first inlet
30 and into first pump 10. First pump 10 then pumps the segregated hydrocarbons and small portion of water 25 through tubing 24 to ground surface 14 where it is collected in a well- known manner. It is preferred that, during production, hydrocarbon/water interface 28 is maintained adjacent first inlet 30 in order to provide stabilized pumping conditions. In order to meet the capacity of first pump 10 and to ensure that hydrocarbon/water interface 28 is maintained adjacent first inlet 30, an upper portion of segregated produced water 23 (in addition to produced hydrocarbons and poition of produced water 25) may be "pulled" by first pump 10 through first inlet 30 and pumped to ground surface 14. Simultaneously, segregated produced water 23 which has settled at the bottom of casing/tubing annulus 26 flows or is "pulled" into second inlet 13 and into second pump 20. The segregated water is then pumped through tubing 29 to ground surface 14 where it is also collected in a well-known manner. Reference will now be made to Fig. 18, wherein an alternate embodiment of the embodiment of Fig. 17 is shown. In this embodiment, second pump 20 is shown preferably disposed in second tubing 29 whereas first pump 10 is shown coupled to first tubing 24 as described above. Second pump 20 may be a surface-driven rod pump or alternately, a surface rod-driven progressive cavity pump. Alternatively, first pump 10 could be disposed in first tubing 24 and second pump 20 could be coupled to second tubing 29 as described above. Similarly, in this arrangement, first pump 10 could be a surface-driven rod pump or a surface rod-driven progressive cavity pump. As a further alternative, first pump 10 and second pump 20 could be disposed in tubing 24 and tubing 29, respectively.
It should be apparent to one of ordinary skill in the art that any type of rod pump (including, for example, but not limited to, insert, tubing, and various American Petroleum Institute (API) pump types) may be used to provide flexibility for varying conditions within the producing well. As shown in Fig. 18, second pump, or rod pump 20 is preferably sealingly disposed in second tubing 29. Second, or lower inlet 13 is preferably disposed in tubing 29 below second pump 20 and is disposed in a region of casing 11 where segregated produced water is expected to be present.
A sucker rod string 9 is also disposed in second tubing 29. Rod string 9 extends to ground surface 14 where it is reciprocated through an upstroke and a downstroke by a conventional pump drive (not shown). As rod string 9 is reciprocated through an upstroke and a downstroke, second pump 20 reciprocates through an upstroke and a downstroke. Reference will now be made to the operation of the alternate exemplary embodiment shown in Fig. 18 employing a surface-driven rod pump as second pump 20. In operation, produced fluids (hydrocarbons and water) are produced from production zone 12 via intervals 15 into casing 11 above optional packer 16 thereby forming a column of produced hydrocarbons and water within casing/tubing annulus 26. The lighter produced fluids
(mostly hydrocarbons 25) rise to the top of the column while the heavier fluids (mostly water 23) settle to the bottom of the column.
During the upstroke of second, or rod pump 20, segregated produced water flows through second inlet 13 and into second tubing 29 below second pump 20. A traveling valve (not shown) disposed in second pump 20 is open during the upstroke which permits the segregated produced water to flow through second pump 20 to form a column of produced water 32 above second pump 20. As the upstroke continues, a poition of the column of produced water 32 is conducted or lifted to ground surface 14 and collected in a conventional manner. Simultaneously, during the upstroke and downstroke of second pump 20, segregated produced hydrocarbons and portion of produced water 25 flow through first inlet 30 and into first pump 10. The segregated produced hydrocarbons and portion of produced water 25 are then lifted to ground surface 14 through first tubing 24 as described above with reference to Fig. 17. Second pump 20 may also be a surface rod-driven progressive cavity pump. In such an embodiment, second pump 20 is preferably disposed within second tubing 29. Alternatively, it should be apparent to one of ordinary skill in the art that second pump, or surface rod-driven progressive cavity pump could be coupled to second tubing 29 by any suitable method, such as threaded connections. In such an embodiment, it should be /o apparent to one of ordinary skill in the art that second tubing 29 would preferably comprise two tubing sections. The first tubing section extends downwardly within casing 11 and is coupled to one end of second pump 20. The second tubing section is coupled to the other end of second pump 20 and extends downwardly within casing 11. As described above sucker rod string 9 is disposed within second tubing 29 and extends to ground surface 14 where it is preferably rotated by a conventional motor (not shown). As rod string 9 is rotated, second pump 20 is likewise rotated and results in flow of fluids through second pump 20.
Reference will now be made to the operation of the alternate exemplary embodiment shown in Fig. 18 employing a surface rod-driven progressive cavity pump as second pump 20. In operation, produced fluids (hydrocarbons and water) are produced from production zone 12 via intervals 15 into casing 11 above optional packer 16 thereby forming a column of produced hydrocarbons and water within casing/tubing annulus 26. The lighter produced fluids (mostly hydrocarbons 25) rise to the top of the column while the heavier fluids (mostly water 23) settle to the bottom of the column.
During rotation of second pump 20, segregated produced water flows through second inlet 13 and into second tubing 29 below second pump 20. Second pump 20 then pumps the segregated produced water 23 (as is described below with respect to the rotor 26 and stator 22 arrangement of the progressive cavity pump shown in Fig. 21) through second tubing 29 to ground surface 14 where it is collected in a conventional manner.
Simultaneously, during rotation of second pump 20, segregated produced hydrocarbons and portion of produced water 25 flow through first inlet 30 and into first pump 10. The segregated produced hydrocarbons and portion of produced water 25 are then lifted to ground surface 14 through first tubing 24 as described above with reference to Fig. 17.
Reference will now be made to Fig. 19, wherein a fourteenth exemplary embodiment of the present invention is shown employing a first pump 10 and a second pump 20 coupled to a first tubing 24. First pump 10 and second pump 20 may be coupled to tubing 24 by any suitable method, such as threaded connections. Alternatively, first pump 10 may be disposed in first tubing 24 as described and shown above with reference to Fig. 18. First pump 10 may be an electrical submersible pump, a surface-driven rod pump, a surface rod-driven progressive cavity pump, an electrical submersible progressive cavity pump, or any other suitable downhole pump. Second pump 20 may be an electrical submersible pump, an electrical submersible progressive cavity pump, or any other suitable downhole pump.
As shown in Fig. 19, a first variable speed drive 36 may preferably be disposed at ground surface 14 to provide power to and control the pump rate of first pump 10. First pump 10 is preferably coupled to first variable speed drive 36 by a first electrical line or cable 34. Similarly, a second variable speed drive 40 may preferably be disposed at ground surface 14 to provide power to and control the pump rate of second pump 20. Second pump 20 is preferably coupled to second variable speed drive 40 by a second electrical line or cable 37. Alternatively, if a surface-driven rod pump or a surface rod-driven progressive cavity pump is employed as first pump 10, then first pump 10 will be driven in the manner described above with reference to Fig. 18.
An optional seal 16 is shown disposed within casing 11, preferably below second pump 20. As noted above, it should be understood by one of ordinary skill in the art that seal 16 may not be required if water encroachment is not a problem or if conditions within the well permit produced hydrocarbons and produced water to sufficiently segregate by gravity within casing 11. A second seal or packer 27 is disposed in casing 11. Second seal 27 divides casing 11 into an upper portion 11a and a lower portion lib. Second seal 27, casing 11, and tubing 24 together define a casing/tubing annulus 26 in the upper portion 11a of casing 11. Hydrocarbons, such as oil or gas, and water flow or are "produced," into casing 11 through producing interval 15. The hydrocarbons and water segregate by gravity within the lower portion lib of casing 11 forming a hydrocarbon/water interface 28. Thus, the produced hydrocarbons and water are allowed to collect in casing 11 above seal 16 and to segregate by gravity to form segregated produced water 23 below hydrocarbon/water interface 28 and segregated produced hydrocarbons and a small proportion or poition of produced water 25 above hydrocarbon/water interface 28.
A branch conduit 34, or what is commonly referred to in the art as a "Y-tool," is shown coupled to tubing 24 and second tubing 29. Tubing 29 preferably extends upwardly through, and terminates above, second seal 27. Tubing 29 may be coupled to second seal or packer 27 by any suitable method. A tubing plug 38 may preferably be disposed in tubing 24 between first pump 10 and second pump 20, and more preferably, above the intersection of branch conduit 34 and tubing 24 in order to isolate segregated produced hydrocarbons and poition of produced water 25 from segregated produced water 23 in tubing 24 and branch conduit 34.
As shown in Fig. 19, tubing 24 is coupled to first pump 10 and extends to ground surface 14 where it is coupled to suitable fluid collection mechanisms (not shown) such as tanks or pipelines. A first, or upper inlet 30 is preferably disposed in tubing 24 below first pump 10. First inlet 30 is preferably disposed in a region of casing 11 where segregated hydrocarbons and only a small proportion or portion of water 25 are expected to be present and preferably, adjacent hydrocarbon/water interface 28. The operation of first inlet 30 will be described in more detail below.
A second, or lower inlet 13 is shown disposed at a lower end of second pump 20. Second inlet 13 is preferably disposed in a region of casing 11 where primarily only the heavier segregated produced water 23 is present (i.e., inlet 13 is in fluid-flow communication primarily with segregated produced water 23).
Reference will now be made to the operation of the exemplary embodiment shown in Fig. 19. In operation, produced fluids (hydrocarbons and water) are produced from producing zone 12 via intervals 15 into casing 11 above seal 16 forming a column of produced hydrocarbons and water within casing 11. The lighter produced fluids (mostly hydrocarbons 25) rise to the top of the column while the heavier fluids (mostly water 23) settle to the bottom of the column.
In the embodiment shown in Fig. 19, segregated hydrocarbons and a small portion of water 25 then flows or is "pulled" through first inlet 30 and into first pump 10. First pump 10 then pumps the segregated hydrocarbons and small portion of water 25 through tubing 24 to ground surface 14 where it collected in a well-known manner.
Simultaneously, segregated produced water 23 which has settled at the bottom of casing 11 flows or is "pulled" through second inlet 13 and into second pump 20. The segregated water is then pumped through branch conduit 34 and tubing 29 to just above second seal or packer 27. Thereafter, the water flows through casing/tubing annulus 26 to ground surface 14 where it is collected in a well-known manner. It should be understood by one of ordinary skill in the art that the water may flow through casing 11 above second packer 27 to ground surface 14 under the influence of reservoir pressure, pressure caused by pumping of fluid through tubing 29, or a combination of both. Use of two separate tubing strings, 24 and 29 (Fig. 17 and 18) or, additionally, casing/tubing annulus 26 (Fig. 19) to lift produced hydrocarbons and produced water to ground surface 14 is preferable when there are no suitable downhole zones in which to inject produced water 23. Alternatively, such an arrangement is preferable when water is needed at ground surface 14 for purposes, such as steam generation or for waterflooding different zones. Such a system also provides economic and environmental benefits in that less surface equipment (e.g., "Free Water Knock Outs," fired heaters, separators, and emulsion treating chemicals) is needed.
Reference will now be made to Fig. 20, which is provided to illustrate a schematic partial view of an exemplary electrical submersible progressive cavity pump (ESPCP) suitable for use with the present invention, represented generally as reference numeral 7. An exemplary electrical submersible progressive cavity pump suitable for use with the present invention is shown in U.S. Patent No. 3,677,665, the entirety of which is incorporated herein by reference. When used with the present invention, ESPCP 7 is preferably coupled to tubing 24 as described above, however, ESPCP 7 may also be disposed within tubing 24. The ESPCP preferably comprises a helically shaped rotor 26 and a stator 22. Rotor 26, which is the ESPCP' s only moving part, is usually in the shape of a single external helix with a round cross section. Rotor 26 is normally plated with a hardened surface coating for abrasion resistance in the presence of sand, formation residue chips, or the like. Stator 22 is generally formed of a very firm, but elastomeric compound (such as synthetic rubber) and usually has a double internal helix. Its external shape is generally cylindrical and therefore provides a surface which may be bonded to a pump body. Rotor 26 is suspended in stator 22 and may be powered (i.e., rotated) by an electrical submersible motor 48 via a gear reduction drive 46 which is used preferably as a conventional speed reducer. A flex shaft 42 and a seal section 44 are coupled together and located between rotor 26 and gear reduction drive 46.
In operation, as internal helical pump rotor 26 is turned by motor 48, a series of cavities are formed between the helices of rotor 26 and stator 22 beginning at the intake end and progressing, with the rotary motion, to the output end. The progressive cavities cause fluid to be pumped from the input end to the output end. If rotor 26 is chosen to have a right hand pitch helix, then a vertical pump placed in a well will input fluid into its lower end 33 and output fluid from its upper end 31 with right hand rotation. Conversely, if rotor 26 is chosen to have a left hand pitch helix, then a vertical pump placed in a well will input fluid from its upper end 31 and output the fluid from its lower end 33.
Reference will now be made to Fig. 21, which is provided to illustrate a schematic partial view of an exemplary progressive cavity pump suitable for use with the present invention, represented generally as reference numeral 7. When used with the present invention, progressive cavity pump 7 is preferably mounted in tubing 24. The progressive cavity pump preferably comprises two components: a helically shaped rotor 26 and a stator 22. Rotor 26, which is the progressive cavity pump's only moving part, is usually in the shape of a single external helix with a round cross section. Rotor 26 is normally plated with a hardened surface coating for abrasion resistance in the presence of sand, formation residue chips, or the like. Stator 22 is generally formed of a very firm, but elastomeric compound (such as synthetic rubber) and usually has a double internal helix. Its external shape is generally cylindrical and therefore provides a surface which may be bonded to a pump body. Rotor 26 is suspended in stator 22 and may be powered by an electrical motor via a gear reduction drive (such as motor 8 located at ground surface 14 as shown in Fig. 6). The progressive cavity pump (electrical or rod-driven) is highly efficient when compared to other oil field pumps in common usage. For example, a typical electrical- powered submersible centrifugal pump is from about 25% to 45% efficient. A hydraulic jet pump usually runs from about 15% to 30% efficient. Sucker rod powered mechanical pumps generally run from about 45% to 50% efficient. Conversely, progressive cavity pumps usually run from about 70% to 95% efficient. The progressive cavity pump can also handle solids or very heavy crude oil where more delicate electric pump impellers, electric motors or gearboxes on sucker rod pumping units fail. While a hydraulic jet pump can efficiently operate in high solids environment, its operating efficiency is only about one third of the progressive cavity pump. Progressive cavity pumps that are commercially available can operate at production rates of up to 5,200 barrels of fluid per day from shallow wells. Progressive cavity pumps are capable of operating at depths up to about 5,000 feet, with fluid density from 6 to 45 American Petroleum Institute (API) degrees gravity, at temperatures up to 300°F/150°C and in salty, sandy and high viscosity fluids. However, at such depths the volume of fluid produced would be less than producing from shallow wells. Referring now to Figure 22A, there is illustrated, in a schematic sectional view, a fifteenth exemplary embodiment of the present invention and is represented generally by the reference numeral 101. A pump, shown generally by the reference numeral 50, preferably includes a pump section 110. Pump 50 is preferably an electrical submersible pump, and more preferably, an electrical submersible centrifugal pump. In such an embodiment, pump section 110 preferably includes a series, or plurality, of impeller or centrifugal pump stages, each pump stage including one or more impellers. In an alternate embodiment of the present invention, pump 50 is an electrical submersible progressive cavity pump. In such an embodiment, pump section 110 includes one or more progressive cavity pump stages, each of which includes a rotor and a stator. An exemplary electrical submersible progressive cavity pump suitable for use with the present invention is shown in U.S. Patent No. 3,677,665, the entirety of which is incorporated herein by reference. In a further alternate embodiment of the present invention, pump 50 is an axial flow pump. In such an embodiment, pump section 110 preferably includes one or more axial flow stages, each of which preferably includes an impeller and a stator, or a rotor and a stator. Exemplary axial flow pumps suitable for use with the present invention are shown in U.S. Patent Nos. 5,562,405 and 5,755,554, the entirety of both of which are incorporated herein by reference. Pump section 110 is preferably driven by an electric motor which is encased within a motor section 140 at the lower end of pump 50. Preferably, motor or motor section 140 is disposed below pump section 110. The placement of motor 140 will, of course, depend on various factors, such as the size of motor 140 or the dimensions of the producing well.
A pump outlet 130 is shown disposed at an upper end 260 of pump section 110 and preferably in fluid flow communication with pump section 110. It should be understood by one skilled in the art that the present invention embraces the use of more than one pump outlets 130. For example, it may be necessary to use two or more pump outlets 130 in order to provide separation of the oil and water which results in substantially core annular flow as will be described in more detail below.
A transition conduit 120 is shown connected to pump outlet 130 and in fluid flow communication therewith. Transition conduit 120 may preferably be connected or attached at its inlet 220 to a housing 130a of pump outlet 130 by any suitable method, such as, but not limited to, welding or via threaded connections. Additionally, transition conduit 120 may preferably be connected at its outlet 240 to a fluid outlet conduit 160 by any suitable method. As shown in Fig. 22A, transition conduit 120 preferably tapers from a larger cross- sectional area at inlet 220 to a smaller cross-sectional area at outlet 240. This reduction in surface area causes produced fluids which flow into inlet 220 of transition conduit 120 from pump outlet 130 to be accelerated in a tangential direction which will be described in more detail below. Preferably, transition conduit 120 is conical in shape and therefore the surface areas at inlet 220 and outlet 240 are circular. It should, however, be apparent to one of ordinary skill in the art that transition conduit 120 may be other suitable shapes as long as the further tangential acceleration of the produced fluids flowing through transition conduit 120 can be maintained. Fluid outlet conduit 160, as noted above, is preferably connected to transition conduit
120 by any suitable method. Fluid outlet conduit 160 may be a production tubing string which extends from the ground surface downwardly through the well. Fluid outlet conduit 160 is in fluid flow communication with transition conduit 120 thereby providing a flow path to the ground surface for the separated produced fluids which will be described in more detail below. Pump 50 may also be suspended in the production well from fluid outlet conduit 160.
An inlet 150 is preferably disposed at a lower end 280 of pump section 110. As shown in the exemplary embodiment in Fig. 22A, inlet 150 may be sets of perforations 150a. Alternatively, inlet 150 may be a port or multiple ports or other suitable mechanisms for conducting fluid flow. Preferably, however, inlet 150 will be sets of perforations 150a. Inlet 150 is configured to permit the produced fluids to enter pump section 110 which will be described in more detail below.
Reference will now be made to the operation of the embodiment as shown in Figs. 22A and 22B. In Fig. 22B, pump outlet 130 is shown in more detail, but still schematically. A drive shaft 170 is shown (in partial view) extending from motor 140 into pump outlet 130 where it is connectable to preferably a pair of rotating vanes 190. It should be understood by one of ordinary skill in the art that any number of rotating vanes 190 may be used, for example, one, two, or more than two, depending on the amount of fluid acceleration desired and the physical limitations of pump 50. As shown in Fig. 22B, rotating vanes 190 are preferably rectangular in shape but it should be apparent that other shapes are embraced by the present invention.
As produced fluids (i.e., hydrocarbons and water) are withdrawn from a subterranean reservoir, the produced fluids are drawn into pump section 110 of pump 50 through perforations 150a. The produced fluids are transported through pump section 110 in a well- known manner. The produced fluids exiting pump section 110 enter pump outlet 130 in an axial direction (as shown by arrows 220 in Fig. 22B). Once inside pump outlet 130, the rotation of vanes 190 causes the produced fluids entering axially from below to be tangentially accelerated in the direction of arrows 200 and simultaneously forced to inlet 220 of transition conduit 120. As the produced fluids are forced through transition conduit 120 toward outlet 240, or narrower end of transition conduit 120, the reduction in diameter of conical transition conduit 120 causes further tangential acceleration of the fluids.
The further tangential acceleration of the produced fluids within transition conduit 120 increases the centripetal and centrifugal forces, or "g" forces, acting on the produced fluids. This tends to cause separation of the produced oil and water as they are forced toward outlet 240. The heavier water tends toward the outside or wall of outlet conduit 160 while the oil and any remaining oil/water emulsion stay toward the central axis of outlet conduit 160. This separates the produced fluids into substantially a core annular flow regime of the oil and water in outlet conduit 160. The separated produced fluids continue up outlet conduit 160 to the ground surface where they may be collected in a suitable manner.
Reference will now be made to Fig. 23A, where a sixteenth exemplary embodiment of the present invention is shown schematically. Like reference numerals will be used where appropriate to describe similar elements to those of the embodiment shown in Figs. 22A and 22B.
Referring to Figure 23A, there is illustrated, in a schematic sectional view, a sixteenth exemplary embodiment of the present invention and is represented generally by the reference numeral 100. A pump, shown generally by the reference numeral 50, preferably includes a pump section 110. Pump 50 is preferably an electrical submersible pump and pump section 110 preferably includes a series, or plurality, of impeller or centrifugal pump stages, the configuration of which would be readily apparent to one of skill in the art. In a manner similar to that discussed with respect to Figs. 22A and 22B, pump 50 can also be an electrical submersible progressive cavity pump or a weir pump. Pump section 110 is preferably driven by an electric motor that is encased within motor section 140 at the lower end of pump 50. Preferably, motor or motor section 140 is disposed below pump section 110. In addition, inlet 150 is preferably disposed at a lower end of pump section 110.
An alternate embodiment of pump outlet 130 is shown disposed at upper end 260 of pump section 110 and preferably in fluid flow communication with pump section 110.
Transition conduit 120 is also shown connected to a housing 130a of pump outlet 130 and in fluid flow communication therewith.
As noted above with respect to Fig. 22A, and as shown in Fig. 23A, transition conduit 120 preferably tapers from a larger cross-sectional area at inlet 220 to a smaller o cross-sectional area at outlet 240. This reduction in surface area causes produced fluids which flow into the inlet 220 of transition conduit 120 from pump outlet 130 to be accelerated in a tangential direction which will be described in more detail below.
Fluid outlet conduit 160 is provided and is preferably connected to transition conduit 120 by any suitable method. Fluid outlet conduit 160 may be a production tubing string which extends from the ground surface downwardly through the well. Fluid outlet conduit 160 is in fluid flow communication with transition conduit 120 thereby providing a flow path for the separated produced fluids to the ground surface which will be described in more detail below. The pump 50 may also be suspended in the production well from fluid outlet conduit 160.
Reference will now be made to the operation of the sixteenth exemplary embodiment as shown in Figs. 23A and 23B. In Fig. 23B, pump outlet 130 is shown in more detail, but still schematically. An output nozzle 290, in fluid flow communication with pump section 110, is disposed in pump outlet 130 as shown in Fig. 23B. Nozzle 290 is configured to accelerate the produced fluids entering pump outlet 130 from pump section 110 in a substantially tangential direction which will be described below. It should be understood by one of ordinary skill in the art that a plurality of nozzles may be employed in the present invention depending, of course, upon the particular characteristics of the producing well. As produced fluids (i.e., hydrocarbons and water) are withdrawn from a subterranean reservoir, the produced fluids are drawn into pump section 110 through perforations 150a. The produced fluids are transported through the plurality of pump stages disposed in pump section 110 in a suitable manner. As the produced fluids exit pump section 110 and enter pump outlet 130, nozzle 290 disposed therein accelerates the produced fluids in a tangential direction, as shown by arrows 200, within pump outlet 130. Simultaneously, the produced fluids are forced towards inlet 220 of transition conduit 120. As the produced fluids are forced through transition conduit 120 toward outlet 240, or narrower end of transition conduit 120, the reduction in diameter of conical transition conduit 120 causes further tangential acceleration of the fluids resulting in separation of the produced fluids and substantially core annular flow through outlet conduit 160 to the ground surface as described above.
As described above, the present invention provides a simple method and apparatus for providing flexibility and reliability in lifting produced hydrocarbons and only a portion of the produced water to the ground surface while simultaneously injecting excess produced water subsurface, or alternatively, lifting excess produced water to the ground surface. It should be apparent that the present invention may be used to increase efficiency and production, to lower production, injection, and equipment costs, and to extend the overall commercial life of hydrocarbon producing fields. Moreover, the present invention significantly reduces the disturbance to and impact on the natural environment while improving the economics of hydrocarbon recovery. The apparatus and method of the present invention reduces the amount of land disturbance, such as less earthwork, erosion, and spills. In addition, the present invention reduces the amount of surface facilities required such as tanks, separators, and surface handling equipment. With less and/or smaller surface equipment, there would be fewer leaking valves and connections as well as reduced chemical handling, storage, and use. Through use of the present invention, fewer single-use injection wells and associated facilities, pumps, and injection lines are needed. The present invention can also reduce the need for produced water trucking or transportation. Further, because less water is lifted to the ground surface, the evaporation and exposure of water-soluble hydrocarbons to the atmosphere is minimized. In reservoirs wherein the excess water has a moderate to high hydrogen sulfide content, exposure of the hydrogen sulfide to the surrounding environment may also be minimized or eliminated. Moreover, with less equipment at the ground surface, noise or other air pollution from such equipment may be minimized. Waterfloods or pressure maintenance projects could utilize less fresh water. Fewer spills from corrosion, overflowing tanks, or other equipment failures are other benefits. Further, there is less need for isolated wastewater disposal sites and fewer wellbores penetrating aquifers. Smaller offshore platforms are possible as well. The present invention can also result in less electrical power and associated costs which allows for more efficient recovery of natural hydrocarbon resources and extended life for marginal wells and fields. The present invention could also provide pressure maintenance or waterflooding as a byproduct of production.
Conclusion
While various embodiments of the present invention have been described above, it should be understood that they have been presented by way of example only, and not limitation. Thus, the breadth and scope of the present invention should not be limited by any of the above-described exemplary embodiments, but should be defined only in accordance with the following claims and their equivalents.

Claims

We claim:
1. An apparatus for selectively lifting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water below the ground surface, the apparatus comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; a first pump and a second pump disposed in said casing wherein said first pump is not drivingly coupled to said second pump; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate by gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter one of said first and said second pump; and a second inlet for permitting the segregated produced water to enter the other of said first and said second pump.
2. An apparatus according to claim 1, wherein said one of said first and said second pump is a rod pump and said other of said first and said second pump is an ESP.
3. An apparatus according to claim 1 , wherein said one of said first and said second pump is an ESP and said other of said first and said second pump is a rod pump.
4. A downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface, the system comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; a rod pump and an electrical submersible pump (ESP) disposed in said casing; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate by gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter one of said rod and said ESP pump; and a second inlet for permitting the segregated produced water to enter the other of said rod and ESP pump.
5. A method for selectively lifting fluids, including produced hydrocarbons and a portion of produced water from a subterranean well, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water, subsurface, the subterranean well traversing a producing zone and an injection zone, the method comprising: allowing produced water and produced hydrocarbons to collect and to segregate above a packer disposed in a casing in the subterranean well; controlling a first pump to lift the segregated produced hydrocarbons and a small portion of the produced water to the ground surface; and controlling a second pump independently of the first pump to inject the segregated produced water into an injection zone.
6. An apparatus for selectively lifting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water below the ground surface, the apparatus comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; an electrical submersible progressive cavity pump and an electrical submersible pump disposed in said casing; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter one of said electrical submersible progressive cavity pump and said electrical submersible pump; and a second inlet for permitting the segregated produced water to enter the other of said electrical submersible progressive cavity pump and said electrical submersible pump.
7. An apparatus according to claim 6, further comprising: means for independently controlling the output of said electrical submersible progressive cavity pump and said electrical submersible pump.
8. An apparatus according to claim 7, wherein said means for independently controlling comprises a variable speed drive.
9. An apparatus according to claim 8, wherein said means for independently controlling further comprises a motor.
10. A downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface, the system comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; an electrical submersible progressive cavity pump and an electrical submersible pump disposed in said casing, wherein said electrical submersible progressive cavity pump is not drivingly coupled to said electrical submersible pump; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter said electrical submersible progressive cavity pump; and a second inlet for permitting the segregated produced water to enter said electrical submersible pump.
11. A downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface, the system comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; an electrical submersible progressive cavity pump and an electrical submersible pump disposed in said casing, wherein said electrical submersible progressive cavity pump is not drivingly coupled to said electrical submersible pump; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter said electrical submersible pump; and a second inlet for permitting the segregated produced water to enter said electrical submersible progressive cavity pump.
12. A method for selectively lifting fluids, including produced hydrocarbons and a portion of produced water from a subterranean well, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water, subsurface, the subterranean well traversing a producing zone and an injection zone, the method comprising: allowing produced water and produced hydrocarbons to collect and to segregate above a packer disposed in a casing in the subterranean well; controlling one of an electrical submersible progressive cavity pump and electrical submersible pump to lift the segregated produced hydrocarbons and a portion of the produced water to the ground surface; independently controlling the other of said electrical submersible progressive cavity pump and electrical submersible pump to inject the segregated produced water into the injection zone.
13. An apparatus for selectively lifting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water below the ground surface, the apparatus comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; a gas lift system and a pump disposed in said casing; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are 9o configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to be lifted to the ground surface, said first inlet in fluid-flow communication with said gas lift system; and a second inlet for permitting the segregated produced water to enter said pump and thereafter to be injected into the injection zone.
14. An apparatus according to claim 13, wherein said gas lift system comprises a gas lift mandrel and a gas lift valve disposed in said gas lift mandrel, said gas lift valve in fluid-flow communication with said casing.
15. An apparatus according to claim 13, wherein said pump is an electrical submersible pump.
16. An apparatus according to claim 13, wherein said pump is an electrical submersible progressive cavity pump.
17. An apparatus according to claim 13, wherein said pump is a rod-driven progressive cavity pump.
18. A downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface, the system comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; a gas lift system and an electrical submersible pump disposed in said casing, wherein said gas lift system and said electrical submersible pump are independently controlled; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to be lifted to the ground surface, said first inlet in fluid-flow communication with said gas lift system; and a second inlet for permitting the segregated produced water to enter said electrical submersible pump and thereafter to be injected into the injection zone.
19. A downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface, the system comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; a gas lift system and an electrical submersible progressive cavity pump disposed in said casing, wherein said gas lift system and said electrical submersible progressive cavity pump are independently controlled; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to be lifted to the ground surface, said first inlet in fluid-flow communication with said gas lift system; and a second inlet for permitting the segregated produced water to enter said electrical submersible progressive cavity pump and thereafter to be injected into the injection zone.
20. A downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface, the system comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; a gas lift system and a rod-driven progressive cavity pump disposed in said casing, wherein said gas lift system and said rod-driven progressive cavity pump are independently controlled; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to be lifted to the ground surface, said first inlet in fluid-flow communication with said gas lift system; and a second inlet for permitting the segregated produced water to enter said rod-driven progressive cavity pump and thereafter to be injected into the injection zone.
21. A downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface, the system comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; a gas lift system and a rod pump disposed in said casing, wherein said gas lift system and said rod pump are independently controlled; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to be lifted to the ground surface, said first inlet in fluid-flow communication with said gas lift system; and a second inlet for permitting the segregated produced water to enter said rod pump and thereafter to be injected into the injection zone.
22. A method for selectively lifting fluids, including produced hydrocarbons and a poition of produced water from a subterranean well, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water, subsurface, the subterranean well traversing a producing zone and an injection zone, the method comprising: allowing produced water and produced hydrocarbons to collect and to segregate above a packer disposed in a casing in the subterranean well; controlling a gas lift system to induce flow of the segregated produced hydrocarbons and a small portion of the produced water to the ground surface; and independently controlling a pump to inject the segregated produced water into an injection zone.
23. An apparatus for selectively lifting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water below the ground surface, the apparatus comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; a first progressive cavity pump and a second progressive cavity pump disposed in said casing; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter one of said first progressive cavity pump and said second progressive cavity pump; and a second inlet for permitting the segregated produced water to enter the other of said first progressive cavity pump and said second progressive cavity pump.
24. An apparatus according to claim 23, wherein said first progressive cavity pump is a rod-driven progressive cavity pump and said second progressive cavity pump is an electrical submersible progressive cavity pump.
25. An apparatus according to claim 23, wherein said first and said second progressive cavity pumps are electrical submersible progressive cavity pumps.
26. An apparatus according to claim 24, wherein the pump output of said rod- driven progressive cavity pump and said electrical submersible progressive cavity pump may be separately controlled.
27. An apparatus according to claim 24, wherein said rod-driven progressive cavity pump is not drivingly coupled to said electrical submersible progressive cavity pump.
28. A downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface, the system comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; a rod-driven progressive cavity pump and an electrical submersible progressive cavity pump disposed in said casing, wherein said rod-driven progressive cavity pump is not drivingly coupled to said electrical submersible progressive cavity pump; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter said rod-driven progressive cavity pump; and a second inlet for permitting the segregated produced water to enter said electrical submersible progressive cavity pump.
29. A downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface, the system comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; a first electrical submersible progressive cavity pump and a second electrical submersible progressive cavity pump disposed in said casing; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter one of said first and second electrical submersible progressive cavity pumps; and a second inlet for permitting the segregated produced water to enter the other of said first and second electrical submersible progressive cavity pumps.
30. A downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface, the system comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; a rod-driven progressive cavity pump and an electrical submersible progressive cavity pump disposed in said casing, wherein said rod-driven progressive cavity pump is not drivingly coupled to said electrical submersible progressive cavity pump; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter said electrical submersible progressive cavity pump; and a second inlet for permitting the segregated produced water to enter said rod-driven progressive cavity pump.
31. A method for selectively lifting fluids, including produced hydrocarbons and a portion of produced water from a subterranean well, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water, subsurface, the subterranean well traversing a producing zone and an injection zone, the method comprising: allowing produced water and produced hydrocarbons to collect and to segregate above a packer disposed in a casing in the subterranean well; controlling one of a rod-driven progressive cavity pump and electrical submersible progressive cavity pump to lift the segregated produced hydrocarbons and portion of the produced water to the ground surface; and independently controlling the other of said rod-driven progressive cavity pump and electrical submersible progressive cavity pump to inject the segregated produced water into the injection zone.
32. A method for selectively lifting fluids, including produced hydrocarbons and a portion of produced water from a subterranean well, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water, subsurface, the subterranean well traversing a producing zone and an injection zone, the method comprising: allowing produced water and produced hydrocarbons to collect and to segregate above a packer disposed in a casing in the subterranean well; controlling a first electrical submersible progressive cavity pump to lift the segregated produced hydrocarbons and portion of the produced water to the ground surface; and controlling a second electrical submersible progressive cavity pump to inject the segregated produced water into the injection zone.
33. A downhole oil and water separation system comprising: a casing having an interval, said casing extending from a ground surface downwardly such that said interval communicates with a producing zone; a first progressive cavity pump and a second progressive cavity pump disposed in said casing; a packer disposed within said casing, wherein said casing and said packer are configured to permit produced hydrocarbons and produced water to collect above said packer whereby the produced hydrocarbons and the produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons to enter one of said first progressive cavity pump and said second progressive cavity pump; and lϋo a second inlet for permitting the segregated produced water to enter the other of said first progressive cavity pump and said second progressive cavity pump.
34. An apparatus for selectively lifting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water below the ground surface, the apparatus comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; a rod-driven progressive cavity pump and an electrical submersible pump disposed in said casing; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter one of said rod-driven progressive cavity pump and said electrical submersible pump; and a second inlet for permitting the segregated produced water to enter the other of said rod-driven progressive cavity pump and said electrical submersible pump.
35. An apparatus according to claim 34, wherein the pump output of said rod- driven progressive cavity pump and said electrical submersible pump may be separately controlled.
36. An apparatus according to claim 34, wherein said rod-driven progressive cavity pump is not drivingly coupled to said electrical submersible pump.
37. A downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface, the system comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; a rod-driven progressive cavity pump and an electrical submersible pump disposed in said casing, wherein said rod-driven progressive cavity pump is not drivingly coupled to said electrical submersible pump; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter said rod-driven progressive cavity pump; and a second inlet for permitting the segregated produced water to enter said electrical submersible pump.
38. A downhole oil and water separation system for conducting produced fluids, including produced hydrocarbons and a portion of produced water, to a ground surface and injecting, without conducting to the ground surface, the remaining produced water below the ground surface, the system comprising: a casing having two spaced intervals and extending from the ground surface downwardly such that a first of said two spaced intervals communicates with a producing zone and a second of said two spaced intervals communicates with an injection zone; a rod-driven progressive cavity pump and an electrical submersible pump disposed in said casing, wherein said rod-driven progressive cavity pump is not drivingly coupled to said electrical submersible pump; a packer disposed within said casing between said first of said two spaced intervals and said second of said two spaced intervals, wherein said casing and said packer are configured to permit the produced fluids to collect above said packer whereby the produced hydrocarbons and produced water segregate under influence of gravity; a first inlet for permitting the segregated produced hydrocarbons and portion of the produced water to enter said electrical submersible pump; and a second inlet for permitting the segregated produced water to enter said rod-driven progressive cavity pump.
39. A method for selectively lifting fluids, including produced hydrocarbons and a portion of produced water from a subterranean well, to a ground surface and injecting, without lifting to the ground surface, the remaining produced water, subsurface, the subterranean well traversing a producing zone and an injection zone, the method comprising: allowing produced water and produced hydrocarbons to collect and to segregate above a packer disposed in a casing in the subterranean well; controlling one of a rod-driven progressive cavity pump and electrical submersible pump to lift the segregated produced hydrocarbons and a small portion of the produced water to the ground surface; and independently controlling the other of said rod-driven progressive cavity pump and electrical submersible pump to inject the segregated produced water into an injection zone.
40. A downhole oil and water separation system comprising: a casing having an interval, said casing extending from a ground surface downwardly such that said interval communicates with a producing zone so that produced hydrocarbons and produced water from the producing zone collect in said casing and segregate under influence of gravity; a first pump and a second pump disposed in said casing, wherein said first pump is not drivingly coupled to said second pump; a first inlet for permitting the segregated produced hydrocarbons to enter said first pump; and a second inlet for permitting the segregated produced water to enter said second pump.
41. A method for selectively lifting fluids, including produced hydrocarbons and produced water, from a subterranean well to a ground surface, the method comprising: allowing produced water and produced hydrocarbons to collect and to segregate above a packer disposed in a casing in the subterranean well; controlling a first pump to lift the segregated produced hydrocarbons and a portion of the produced water through a first tubing to the ground surface; and independently controlling a second pump to lift the segregated produced water through a second tubing to the ground surface.
42. A pump for conducting produced fluids from a producing well to a ground surface comprising: a pump section comprising an upper end and a lower end; a pump outlet disposed at one end of said pump section and in fluid flow communication with said pump section; a transition conduit having an inlet and an outlet coupled to said pump outlet, wherein said pump outlet is configured to accelerate produced fluids in a tangential direction toward said transition conduit and wherein produced fluids exiting said transition conduit are in substantially core annular flow; and an outlet conduit in fluid flow communication with said transition conduit for conducting produced fluids to the ground surface.
43. A pump according to claim 42, wherein said pump outlet comprises a rotating vane, said rotating vane capable of causing produced fluids entering said pump outlet in an axial direction to be accelerated in a tangential direction toward the inlet of said transition conduit.
44. A pump according to claim 43, wherein said transition conduit tapers from a larger cross-sectional area at the inlet of said transition conduit to a smaller cross-sectional area at the outlet of said transition conduit, thereby causing the produced fluids to be further accelerated in the tangential direction.
45. A pump according to claim 42, wherein said pump outlet comprises a nozzle, said nozzle configured to cause produced fluids entering said pump outlet to be accelerated in a tangential direction toward the inlet of said transition conduit.
46. A pump according to claim 45, wherein said transition conduit tapers from a larger cross-sectional area at the inlet of said transition conduit to a smaller cross-sectional area at the outlet of said transition conduit, thereby causing the produced fluids to be further accelerated in the tangential direction.
47. A pump according to claim 42, wherein said pump section comprises an impeller.
48. A pump according to claim 42, wherein said pump section comprises a rotor and a stator.
49. A pump according to claim 48, wherein said rotor and said stator are disposed in an axial flow stage.
50. A pump according to claim 48, wherein said rotor and said stator are disposed in a progressive cavity pump stage.
51. A pump according to claim 42, wherein said pump section comprises an impeller and a stator.
52. A pump according to claim 42, wherein said pump section comprises a plurality of pump stages.
53. A method for conducting produced fluids, including hydrocarbons and water, from a producing well to a ground surface comprising the steps of: pumping produced fluids through a pump section into a pump outlet disposed at an end of the pump section; accelerating the produced fluids entering the pump outlet in a substantially tangential direction and towards an inlet of a transition conduit coupled to the pump outlet; forcing the accelerated produced fluids through the transition conduit thereby further accelerating the produced fluids in the tangential direction and increasing the centripetal and centrifugal forces acting on the produced fluids such that the produced hydrocarbons and produced water separate into substantially core annular flow; and conducting the separated hydrocarbons and water up an outlet conduit to the ground surface.
54. A method according to claim 53, wherein the accelerating step is performed using a rotating vane disposed in the pump outlet.
55. A method according to claim 53, wherein the accelerating step is performed using a nozzle disposed in the pump outlet.
PCT/US1998/019585 1997-08-22 1998-09-21 Dual injection and lifting system WO1999015755A2 (en)

Priority Applications (27)

Application Number Priority Date Filing Date Title
CA 2213631 CA2213631A1 (en) 1997-08-22 1997-08-22 Method and apparatus for reducing gas well production costs using improved downhole valves
US5973297P true 1997-09-23 1997-09-23
US5973497P true 1997-09-23 1997-09-23
US5973197P true 1997-09-23 1997-09-23
US5982797P true 1997-09-23 1997-09-23
US5978197P true 1997-09-23 1997-09-23
US5973397P true 1997-09-23 1997-09-23
US60/059,732 1997-09-23
US60/059,731 1997-09-23
US60/059,781 1997-09-23
US60/059,733 1997-09-23
US60/059,734 1997-09-23
US60/059,827 1997-09-23
US15414098A true 1998-09-17 1998-09-17
US09/154,142 1998-09-17
US09/154,137 1998-09-17
US09/154,141 US6092600A (en) 1997-08-22 1998-09-17 Dual injection and lifting system using a rod driven progressive cavity pump and an electrical submersible pump and associate a method
US09/154,143 1998-09-17
US09/154,138 US6105671A (en) 1997-09-23 1998-09-17 Method and apparatus for minimizing emulsion formation in a pumped oil well
US09/154,137 US6131660A (en) 1997-09-23 1998-09-17 Dual injection and lifting system using rod pump and an electric submersible pump (ESP)
US09/154,143 US6092599A (en) 1997-08-22 1998-09-17 Downhole oil and water separation system and method
US09/154,142 US6079491A (en) 1997-08-22 1998-09-17 Dual injection and lifting system using a rod driven progressive cavity pump and an electrical submersible progressive cavity pump
US09/154,140 1998-09-17
US09/154,139 US6123149A (en) 1997-09-23 1998-09-17 Dual injection and lifting system using an electrical submersible progressive cavity pump and an electrical submersible pump
US09/154,139 1998-09-17
US09/154,141 1998-09-17
US09/154,138 1998-09-17

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