US20210140286A1

US20210140286A1 - Systems and methods of removing stagnant liquid from a hydrocarbon well

Info

Publication number: US20210140286A1
Application number: US17/095,440
Authority: US
Inventors: Daniel D. Croce; Luis E. Zerpa
Original assignee: Colorado School of Mines
Current assignee: Colorado School of Mines
Priority date: 2019-11-12
Filing date: 2020-11-11
Publication date: 2021-05-13

Abstract

The present invention is generally directed to systems and methods of removing liquids from hydrocarbon wells with liquid loading problems. More specifically, the present invention provides an intermittent gas lift system to remove stagnant liquid from hydrocarbon wells. The system includes a gas inlet port for gas to be injected into the well at a relatively low volume. The injected gas travels to a distal end of a lift tube inserted within a production tubing and then lifts or carries liquid up the lift tube to the surface.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority under 35 U.S.C. § 119(e) to U.S. Provisional Patent Application Ser. No. 62/934,412 filed Nov. 12, 2019, which is incorporated herein in its entirety by reference.

FIELD

The present invention is generally directed to systems and methods of removing stagnant liquid from a hydrocarbon well with liquid loading problems. More specifically, the present invention is related to an intermittent gas lift system to remove stagnant liquid from liquid loaded hydrocarbon wellbores. The systems and methods of the present invention can be used with a well which includes a horizontal segment and that produces oil, dry gas or a gas and condensate mixture.

BACKGROUND

The recent boom of oil and gas production in the United States has resulted in a large increase in the number of horizontal wells. From 2010 to 2017, the number of horizontal wells in the U.S. increased by nearly 220 percent and in 2017 there were over 234,000 productive horizontal wells in the U.S. During the same period, the number of vertical wells decreased by approximately 3 percent per year.
Unfortunately, horizontal wells generally have a relatively short production life compared to vertical (or “conventional”) completions. Despite their large initial productivity, nearly 10 percent of the horizontal wells in the U.S. become unproductive each year. The loss of such a large percentage of horizontal wells annually results in a large loss of revenue for operating companies and an increased ecological footprint as more wells are drilled to replace wells that are out of service or plugged and abandoned (P&A).
Operating a horizontal well can be very difficult. One challenge is caused by liquids in the reservoir that flow into and accumulate in the well. Over time, the liquids can stagnant in the well and obstruct the flow of fluids, including natural gas or oil. Gas tends to readily flow in the well due to its low density. However, produced liquids, such as condensate and water, tend to accumulate in the horizontal segment of the well due to gravity as water production increases and/or as downhole pressure decreases. It is difficult to lift liquids from horizontal sections of a well. Thus, the liquids can form a “slug” and significantly impede or prevent the flow of hydrocarbons from the reservoir into the wellbore.
Initially, hydrocarbons and other liquids from the reservoir enter the wellbore at a velocity and pressure sufficient to transport liquids to the surface. However, as pressure in the hydrocarbon reservoir near the wellbore drops, hydrocarbons entering the completion slow down. The slower flow of hydrocarbons does not have the capacity to carry liquids to surface. As liquids fall back in the vertical portion of the casing and tubing, the well may go from steady production to slug flow within only 3 to 4 years of operation. This slug flow pattern results in the accumulation of liquids until the well can no longer flow, causing a continuous accumulation of liquids or “liquid loading”. Liquid loading leads to reductions in well production, intermittent flow, no-flow, mechanical equipment fatigue and failure, and accelerated pipe corrosion. These problems may cause production from the well to drop below profitable limits, making the well a candidate to be plugged and abandoned.
Liquid loading is a substantial problem in horizontal wells in shale formations. Shale formations typically produce a large ratio of water compared to other formations. Moreover, the low permeability of shale formations reduces the velocity of hydrocarbons entering the wellbore which decreases the ability of the gas to carry liquids to the surface.
To avoid liquid loading problems and extend the operating life of a well, lift methods must effectively remove fluids from the entire wellbore, including the horizontal sections. Unfortunately, no artificial lift method is currently available to remove liquids that are stagnant in the horizontal/lateral sections of a well.
One method of dealing with liquid loading is to use artificial lift (AL) systems. Some AL systems were developed over 30 years ago for vertical wells. Unfortunately, recent experimental and field observations have indicated that AL systems are not as effective as expected in horizontal wells, or are cost prohibitive based on the required rig time needed for installation and equipment costs. Moreover, traditional AL systems have a poor performance record and fail sooner than expected, increasing operational expenditures and reducing hydrocarbon recovery.
Another system for responding to liquid loading is the Dual Lift System produced by Horizontal Lift Technologies and described in U.S. Pat. Nos. 7,748,443 and 8,037,941 which are each incorporated herein by reference in their entireties. The Dual Lift System requires gas lift valves to be installed in a vertical section of a well. In addition, gases injected into the well as part of the treatment by the Dual Lift System can contact the geologic formation and thus potentially causing formation damage.
Accordingly, there is an unmet need for systems and methods of removing stagnant liquid from liquid loaded hydrocarbon wellbores that is cost effective and which does not include the deficiencies of known systems.

SUMMARY

One aspect of the present invention is to provide a system and a method for improving the production of a hydrocarbon well that is loaded with liquid by intermittently injecting compressed gas to the bottom of the well to remove stagnant liquid from the well. In one embodiment, the gas is injected into the well at a relatively low rate. Specifically, in one embodiment, the gas is injected into production tubing at the surface at less than approximately 100 ft³/min, or less than approximately 10 ft³/min. In one embodiment, the gas is injected at a rate of between approximately 0.1 ft³/min and approximately 5 ft³/min. Optionally, the gas may be compressed air.
Another aspect of the present invention is a novel system and method of removing stagnant liquid from a well without installing gas lift valves in a vertical section of the well.
Still another aspect of the present invention is to provide a novel backsweep lift configured to remove stagnant liquid from a well. The backsweep lift can be installed in a well without removing production tubing previously installed in the well. In one embodiment, the backsweep lift of the present invention operates with a single lift tube deployed inside production tubing that has already been installed in the well. In some embodiments, a pretreatment solution may optionally be injected into the wellbore. The pretreatment solution is selected to reduce the surface tension of the stagnant liquid. In this manner, the pretreatment solution may enhance the ability of the gas to transport the stagnant liquid to the surface.
One aspect of the present invention is to provide a backsweep lift configured to reach a horizontal section of a well and operate regardless of the volumetric gas fraction of the fluids coming from the formation.
Another aspect is to provide systems and methods for removing stagnant liquid from a hydrocarbon well and which prevent gases and pretreatment solutions that are injected into the well from escaping from the production tubing and contacting the geologic formation. In this manner, the systems and methods of the present invention facilitate continuous influx of hydrocarbons into the wellbore from perforations in the geologic formation. Additionally, the integrity of the geologic formation is not compromised or contaminated with injected gases and/or pretreatment solutions. In one embodiment, a backsweep lift of the present invention includes a downhole check valve interconnected to a distal end of the production tubing that is operable to prevent injected gases and pretreatment solutions from escaping from the production tubing.
One aspect of the present invention is an intermittent gas lift system to remove stagnant liquid from a wellbore of a hydrocarbon well. The gas lift system comprises: (1) a downhole check valve interconnected to a lower end of a production tubing positioned within the wellbore; (2) a lift tube positioned within the production tubing which defines an annular space between an exterior surface of the lift tube and an interior surface of the production tubing; and (3) a gas inlet port interconnected to the production tubing at a wellhead portion of the hydrocarbon well such that gas injected through the gas inlet port travels down the annular space to a distal end of the lift tube in a horizontal section of the wellbore and then pushes liquid up the lift tube.
The downhole check valve prevents fluid from flowing out of the lower end of the production tubing. When the gas is injected through the gas inlet port into the annular space, pressure in the lower portion of the production tubing increases and the downhole check valve closes to prohibit fluid from a hydrocarbon reservoir proximate to the lower end of the production tubing from flowing into the production tubing. Additionally, when the injection of gas through the gas inlet port into the annular space stops, pressure in the lower portion of the production tubing decreases and the downhole check valve opens to permit fluid from a hydrocarbon reservoir proximate to the lower end of production tubing to flow into the production tubing.
In one embodiment, the gas is injected through the gas inlet port at a pressure of between approximately 100 psi and approximately 1,600 psi. Additionally, or alternatively, the gas can be injected through the gas inlet port at a rate of between approximately 0.1 ft³/min and approximately 50 ft³/min.
In one embodiment, the distal end of the lift tube is positioned within the horizontal section of the wellbore. Optionally, the distal end of the lift tube is spaced upstream from the lower end of the production tubing.
In one embodiment the gas lift system further comprises a solution inlet port at the wellhead portion of the hydrocarbon well. The solution inlet port can be connected to at least one of the production tubing and the lift tube. Accordingly, a pretreatment solution can be injected through the solution inlet port into at least one of the annular space and production tubing.
The gas lift system may optionally include a control system operable to automatically start the injection of gas into the gas inlet port when the control system determines that data from a sensor indicates the well is not producing hydrocarbons at a predetermined rate. The control system generally includes instructions stored on a memory. The instructions cause the control system to send instructions to components of the gas lift system.
Optionally, the gas lift system includes a multiphase flowmeter interconnected to the lift tube. In one embodiment, the multiphase flowmeter is positioned proximate to the wellhead. Additionally, or alternatively, the multiphase flowmeter may be positioned between the wellhead portion and a three-phase separator.
In one embodiment, the gas lift system includes a pressure sensor positioned within a horizontal section of the production tubing.
It is another aspect of the present invention to provide a method of removing stagnant liquid from a wellbore of a hydrocarbon well. The method generally includes, but is not limited to: (1) receiving first data from a sensor; (2) determining that the hydrocarbon well is not producing hydrocarbons at a predetermined rate; (3) injecting a gas into an annular space formed between an interior surface of a production tubing positioned within the wellbore and an exterior surface of a lift tube positioned within the production tubing; (4) receiving second data from the sensor indicating that liquid flowing in the lift tube at the surface includes some of the injected gas; and (5) stopping the injection of gas into the annular space. In one embodiment, the first data received by the sensor includes one or more of a pressure measured proximate to a bottom hole location and a pressure or a flow rate of hydrocarbons from the wellbore. The pressure or flow rate of may be measured at or near the surface.
In one embodiment the method further includes injecting a pretreatment solution into the wellbore. The pretreatment solution is optionally injected into the wellbore before the gas is injected. Optionally, the pretreatment solution is injected through at least one of the production tubing and the lift tube. The pretreatment solution can be injected into at least one of the annular space and directly into the lift tube.
In one embodiment, the method includes injecting the gas through a gas inlet port at a pressure of between approximately 100 psi and approximately 1,600 psi. Additionally, or alternatively, the method may optionally include injecting the gas through the gas inlet port at a rate of between approximately 0.1 ft³/min and 50 ft³/min. In one embodiment, the gas inlet port is interconnected to the production tubing at a wellhead portion of the hydrocarbon well.
Optionally, the method includes interconnecting a downhole check valve to a lower end of the production tubing.
In one embodiment, the method comprises positioning the lift tube within the production tubing. The method may also include positioning the lift tube within the production tubing such that a distal end of the lift tube is spaced upstream from a lower end of the production tubing.
Optionally, the method can be performed by a control system. The control system generally includes a non-transitory computer readable medium comprising a set of instructions stored thereon which, when executed by a processor of a control unit, cause the processor to execute the method of removing stagnant liquid from a wellbore of a hydrocarbon well.
Another aspect is a non-transitory computer readable medium comprising a set of instructions stored thereon which, when executed by a processor of a control unit, cause the processor to execute a method of removing stagnant liquid from a wellbore of a hydrocarbon well. The instructions comprise: (1) an instruction to receive first data from a sensor; (2) an instruction to determine that the hydrocarbon well is not producing hydrocarbons at a predetermined rate; (3) an instruction to inject a gas into an annular space formed between an interior surface of a production tubing positioned within the wellbore and an exterior surface of a lift tube positioned within the production tubing; (4) an instruction to receive second data from the sensor indicating that liquid flowing in the lift tube at the surface includes some of the injected gas; and (5) an instruction to stop the injection of gas into the annular space.
In one embodiment, the first data includes one or more of a pressure measured proximate to a bottom hole location and a pressure or a flow rate of hydrocarbons from the wellbore measured at or near the surface.
Optionally, the instructions include an instruction to at least one of a value and a pump to inject a pretreatment solution into the wellbore before injecting the gas. The instruction causes the pretreatment solution to be injected into at least one of the production tubing and the lift tube.
The Summary is neither intended nor should it be construed as being representative of the full extent and scope of the present disclosure. The present disclosure is set forth in various levels of detail in the Summary as well as in the attached drawings and the Detailed Description and no limitation as to the scope of the present disclosure is intended by either the inclusion or non-inclusion of elements, components, etc. in this Summary. Additional aspects of the present disclosure will become more clear from the Detailed Description, particularly when taken together with the drawings.
The phrases “at least one,” “one or more,” “or,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C,” “A, B, and/or C,” and “A, B, or C” means A alone, B alone, C alone, A and B together, A and C together, B and C together, or A, B and C together.
The term “a” or “an” entity refers to one or more of that entity. As such, the terms “a” (or “an”), “one or more,” and “at least one” can be used interchangeably herein. It is also to be noted that the terms “comprising,” “including,” and “having” can be used interchangeably.
Unless otherwise indicated, all numbers expressing quantities, dimensions, conditions, ratios, ranges, and so forth used in the specification and claims are to be understood as being modified in all instances by the term “about” or “approximately”. Accordingly, unless otherwise indicated, all numbers expressing quantities, dimensions, conditions, ratios, ranges, and so forth used in the specification and claims may be increased or decreased by approximately 5% to achieve satisfactory results. In addition, all ranges described herein may be reduced to any sub-range or portion of the range.
The use of “including,” “comprising,” or “having” and variations thereof herein is meant to encompass the items listed thereafter and equivalents thereof as well as additional items. Accordingly, the terms “including,” “comprising,” or “having” and variations thereof can be used interchangeably herein.
It shall be understood that the term “means” as used herein shall be given its broadest possible interpretation in accordance with 35 U.S.C., Section 112(f). Accordingly, a claim incorporating the term “means” shall cover all structures, materials, or acts set forth herein, and all of the equivalents thereof. Further, the structures, materials, or acts and the equivalents thereof shall include all those described in the Summary, Brief Description of the Drawings, Detailed Description, Abstract, and Claims themselves.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and constitute a part of the specification, illustrate embodiments of the disclosed system and together with the general description of the disclosure given above and the detailed description of the drawings given below, serve to explain the principles of the disclosed system(s) and device(s).

FIG. 1 is production schematic of a backsweep lift according to one embodiment of the present invention installed on a hydrocarbon well with a horizontal section and depicting the surface equipment used in conjunction with the backsweep lift;

FIG. 2 is a cross-sectional view of the horizontal section of the well taken along line 2-2 of FIG. 1 and illustrating a lift tube of the backsweep lift positioned within previously installed production tubing;

FIG. 3 is a schematic view illustrating a liquid buildup phase of a well in which the backsweep lift of FIG. 1 has been installed;

FIG. 4 is another schematic view illustrating gas being injected into the well of FIG. 3;

FIG. 5 is a schematic view illustrating liquid being blown out of the well of FIG. 3 during treatment of the well in accordance with the systems and methods of embodiments of the present invention;

FIG. 6 is yet another schematic view of the well of FIG. 3 illustrating operation of the well after the injection of gas ends;

FIG. 7 is a flow chart of a method of removing stagnant liquid from a wellbore according to one embodiment of the present invention;

FIG. 8 is a graph illustrating the production and pressure profile for one operating cycle of a backsweep lift of one embodiment of the present invention;

FIG. 9 is another graph of a production and pressure profile during one operating cycle of the backsweep lift according to one embodiment; and

FIG. 10 is a graph of recovery factor versus Reynolds number for different Eotvos numbers for one embodiment of the backsweep lift of the present invention.

The drawings are not necessarily to scale. In certain instances, details that are not necessary for an understanding of the disclosure or that render other details difficult to perceive may have been omitted. It should be understood, of course, that the disclosure is not necessarily limited to the embodiments illustrated herein. As will be appreciated, other embodiments are possible using, alone or in combination, one or more of the features set forth above or described below. For example, it is contemplated that various features and devices shown and/or described with respect to one embodiment may be combined with or substituted for features or devices of other embodiments regardless of whether or not such a combination or substitution is specifically shown or described herein.
The following is a listing of components according to various embodiments of the present disclosure, and as shown in the drawings:


Number	Description

2	Geologic formation/hydrocarbon reservoir
4	Well
6	Wellhead
8	Wellbore
10	Vertical section
12	Horizontal section
14	Fractures or perforations
16	Cement
20	Backsweep lift
22	Production casing
24	Casing vent line
26	Flow meter
28	Outer annular space
30	Production tubing
32	Lower end of the production tubing
34	Downhole check valve
35A	Open position of downhole check valve
35B	Closed position of downhole check valve
36	Inner annular space
38	Lift tube
40	Distal end of the lift tube
42	Production port
44	Gas inlet port
45	Gas line
46	Tank for compressed gas
48	Compressor
50	Gas flow meter
52	Injected gas
54	Solution inlet port
56	Solution check valve
58	Pump
60	Solution tank
62	Pretreatment solution
64	Three-phase separator
66	Control system
68	Sensor
68A	Surface sensor
68B	Downhole sensor
70	Method
72	Start
74	Received data from sensors
76	Determine whether well is producing sufficient level of
	hydrocarbons
78	Inject a pretreatment solution into the wellbore
80	Inject a gas into the wellbore
82	Receive data from a sensor
84	Determine whether to continue injection of the gas into the
	wellbore
86	Stop injection of gas
88	Liquid in well
88A	Liquid moving to the surface
88B	Liquid moving downwardly
90	Pressure drop in the horizontal inner annular space per unit
	length
92	Pressure drop within the horizontal tubing per unit length
94	Pressure drop within the vertical tubing per unit length
96	Production (bbl)
98	Liquid rate (gpm)
100	Pressure at heel (psi)
102	Pressure at toe (psi)
104	Production (bbl)
106	Pressure gradient (psi/ft)
110	Eotvos number (Eo) of approximately 12
112	Eotvos number (Eo) of approximately 22
114	Eotvos number (Eo) of approximately 49

DETAILED DESCRIPTION

Referring now to FIGS. 1-2, a backsweep lift 20 according to one embodiment of the present invention is generally illustrated. The backsweep lift 20 is shown interconnected to a well 4 in operable communication with a geologic formation 2. The well 4 generally includes a wellhead 6 at the surface and a wellbore 8 extending to the geologic formation. The wellbore includes a vertical section 10 and a generally horizontal section 12.
Production casing 22 within the wellbore 8 may optionally lined with cement 16. Perforations 14 formed through the production casing 22 and the cement 16 provide a pathway for hydrocarbons, such as gas and/or oil, to flow from a hydrocarbon reservoir within the geologic formation 2 and into the wellbore 8. In some embodiments, the geologic formation will be fractured to increase the permeability and production of hydrocarbons from the geologic formation.
Production tubing 30 is positioned within the production casing 22 and defines an outer annular space 28 within the wellbore 8. The production tubing 30 can be of any desired diameter. In one embodiment the production tubing 30 has an inner diameter of between approximately 2.0 inches to approximately 3.5 inches, or between approximately 2.3 inches and approximately 2.9 inches. The production tubing 30 is typically installed in the wellbore 8 before the backsweep lift 20 of the present invention is installed.
The backsweep lift 20 generally includes wellhead adaptations at the surface and a bottomhole assembly. A production line or lift tube 38 is positioned in the production tubing 30. The lift tube 38 extends from the surface down to the horizontal section 12 of the well 4. At the surface, the lift tube 38 can be connected to a tank and/or a three-phase separator 64. The size and configuration of the three-phase separator 64 is determined based on an estimate maximum daily flow from the well. In one embodiment, a distal end 40 of the lift tube 38 is positioned within the horizontal section 12 of the production tubing 30. Optionally, the distal end 40 of the lift tube 38 is spaced from a lower end 32 of the production tubing 30.
In one embodiment, the lift tube 38 can be deployed inside production tubing 30 that is already installed in the wellbore 8. For example, the lift tube 38 can be installed in the production tubing 30 without retrieving or extracting the production tubing 30 from the wellbore. In this manner, elements of the backsweep lift 20 of the present invention can be interconnected to (or installed in) the wellbore 8 faster, with less labor, and with less production downtime than prior art systems which require extraction of the production tubing from a wellbore. For example, some prior art systems require the installation of gas lift valves in the production tubing. Additionally, because the backsweep lift 20 of embodiments of the present invention requires only one lift tube 38 to be introduced into the wellbore 8, the risks of helical buckling experienced in prior art systems that require installation of two lines of tubing into the wellbore are reduced. Further, the single lift tube 38 used in one embodiment of the present disclosure reduces material costs of the backsweep lift compared to some prior art systems which require two sections of tubing to be installed in the production tubing.
The lift tube 38 has an outer diameter that is less than the inner diameter of the production tubing 30. Accordingly, the lift tube 38 defines a new or inner annular space 36 between an interior surface of the production tubing 30 and an exterior surface of the lift tube 38. Thus, gases and/or liquids injected from surface can flow through the inner annular space 36 down to the horizontal section 12.
Any suitable tubing may be used as the lift tube 38. Optionally, the lift tube 38 may be coiled tubing or “macaroni” tubing such as known to those of skill in the art. The lift tube 38 may optionally include one or more threaded joints. Alternatively, in one embodiment, the lift tube 38 may be one continuous piece of material. In one embodiment, the lift tube 38 has an inner diameter of between approximately 0.2 inches and approximately 1.0 inch or between approximately 0.4 inches and approximately 0.8 inches. In another embodiment, the inner diameter of the lift tube 38 is between approximately 0.25 inches and approximately 0.55 inches. Other dimensions and diameters are contemplated for the lift tube 38.
To operate with the existing production tubing 30, a downhole check valve 34 can be installed at the lower end 32 of the production tubing 30. In one embodiment, the distal end 40 of the lift tube 38 is spaced from the downhole check valve. More specifically, the distal end 40 of the lift tube 38 may be positioned a predetermined distance uphole (or upstream) from the lower end 32 of the production tubing 30.
Check valves 34 that are suitable for use with the backsweep lift 20 of the present invention are known to those of skill in the art. The downhole check valve 34 is configured to permit stagnant fluids from the production tubing 30 and/or the production casing 22 to enter into the lift tube 38. However, the downhole check valve 34 is operable to prohibit the discharge of fluids and/or gas from the production tubing 30 once a gas is injected at the surface at the wellhead 6. Specifically, in one embodiment, the downhole check valve 34 is configured to prevent gas injected from the surface from escaping from the inner annular space 36. In this manner, the production tubing 30 works as a containment chamber. More specifically, the backsweep lift 20 of the present invention can prevent or reduce the access of gases and/or liquids injected into the inner annular space 36 from entering the outer annular space 28 and contacting the production casing 22 and flowing into the perforations 14. As will be appreciated by one of skill in the art, gases and liquids injected into the inner annular space 36 to retrieve fluids that are stagnated in the horizontal section 12 of the well can contaminate or damage the geologic formation, alter the flow of hydrocarbons from the hydrocarbon reservoir, and cause other issues in operation of the well. Preventing contact of injected gases and liquids with the geologic formation is another benefit of the backsweep lift of embodiments of the present disclosure compared to some of the prior systems, including the Dual Lift System of Horizontal lift technologies, which allow injected gases to contact the geologic formation.
At the wellhead 6, the backsweep lift 20 presents two inlet ports 44, 54 and a production port 42. One of the inlet ports is a gas inlet port 44 to inject compressed gas into the production tubing 30. The gas inlet port 44 is connected to the production tubing 30. Accordingly, gas injected through the gas inlet port 44 can flow down to the horizontal section 12 along the inner annular space 36 between the production tubing 30 and the lift tube 38.
In one embodiment, the gas inlet port 44 is used to inject gas at a low volumetric flow rate. The backsweep lift of the present invention can inject any suitable gas through the gas inlet port. In one embodiment compressed air is injected through the gas inlet port. However, other gases or mixtures of gases may be used with the backsweep lift of embodiments of the present invention.
The pressure at which the gas is injected through the gas inlet port 44 is selected to cover the gravitational and frictional losses required for the gas to flow to the bottom of the completion and push stagnant liquid along the lift tube 38 up to surface. The gas can be injected through the gas inlet port 44 at a relatively high pressure. For example, in one embodiment, the gas is injected through the gas inlet port at a pressure of between approximately 20 psi and approximately 1,600 psi, or between approximately 500 psi and 900 psi. Additionally, or alternatively, in one embodiment of the present invention the gas is injected at a pressure of less than approximately 100 psi. More specifically, in one embodiment, the pressure of the injected gas is between approximately 20 psi and approximately 70 psi.
In one embodiment, gas is injected through the gas inlet port 44 at a rate of between approximately zero point one cubic feet per minute (0.1 ft³/min) to approximately 100 cubic feet per minute (100 ft³/min). In another embodiment, the gas is injected at a rate of greater than approximately 0.1 ft³/min and less than approximately 50 ft³/min, or less than approximately 25 ft³/min. In one embodiment, the gas is injected at a rate of between 0.1 ft³/min and approximately 5 ft³/min. One benefit of the low rate of gas injection is the reduction in loses due to friction and thus reduction of the gas pressure required at the surface.
The volume of gas required by the backsweep lift of the present invention is much less than used in current gas lift systems. For example, in one embodiment, the backsweep lift 20 of the present invention uses approximately 1/1000 as much gas as current gas lift systems. Specifically, some known gas lift systems require gas to be injected at much higher rates, such as greater than 500 ft³/min or up to one or more million cubic feet per day. By reducing the rate of gas injected into the well compared to other gas lift systems, the backsweep lift 20 of embodiments of the present invention decreases both capital expenditures and operational expenditures for the well operator. Further, less energy is required to pump the gas into the backsweep lift of the present embodiment compared to some other known system, reducing fuel and/or electricity costs.
In one embodiment, the backsweep lift includes a tank 46 to supply the gas to the gas inlet port 44 by a gas line 45. The gas tank 46 has a predetermined volume. More specifically, the gas tank 46 is configured to provide a volume of gas at sufficient pressure to cover the gravitational loss of the accumulated liquid column and also the frictional losses of the gas as it travels from the inner annular space 36 up the lift tube 38 back to the surface.
A pump or compressor 48 can be used to compress the gas in the tank 46. Optionally, a gas flow meter 50 may be installed between the tank 46 and the gas inlet port 44. The gas flow meter 50 is configured to control the rate of gas injected into the gas inlet port 44. In one embodiment, the gas flow meter is a thermal mass flowmeter. Other suitable gas flow meters that can be used with the backsweep lift 20 are known to those of skill in the art.
In one embodiment, the gas flow meter 50 is operable to measure one or more of the rate and the pressure at which the gas is injected into the gas inlet port 44. Additionally, or alternatively, the gas flow meter 50 can be used to control the rate and/or pressure at which the gas is injected through the gas inlet port 44 in such way that the flow inside the production tubing 30 is at a predetermined rate as described herein.
The second inlet port 54 is optional and is for the injection of a pretreatment solution into one or more of the production tubing 30 and/or the lift tube 38. The solution inlet port 54 can be connected to the well 4 through a surface check valve 56. The backsweep lift 20 can include one or more surface check valves 56 configured to permit the optional introduction of the pretreatment solution into the inner annular space 36 and/or the lift tube 38 to pretreat stagnant liquid in the system.
A pump 58 controls the rate at which the solution flows from a tank 60 to one or more of the solution inlet ports 54A, 54B. Accordingly, the pretreatment solution can flow down to the horizontal section 12 of the well to mix with liquids in the inner annular space 36 and the lift tube 38.
The surface check valve 56 may also be configured to prohibit flowback of recovered fluids and the pretreatment solution from the solution inlet port 54. In one embodiment the second inlet port 54 is a one-way valve known to those of skill in the art.
In one embodiment, the solution inlet port 54A is configured to inject the pretreatment solution into the inner annular space 36 between the production tubing 30 and the lift tube 38. Additionally, or alternatively, the solution inlet port 54B can optionally be configured to inject the pretreatment solution into the lift tube 38. In this manner, the pretreatment solution can flow from the surface down the lift tube 38 and to the distal end 40 of the lift tube.
The pretreatment solution 62 is selected to increase the surface tension between air (or another gas) and liquid. More specifically, the composition of the pretreatment solution 62 is selected to improve the lifting efficiency of the gas injected at surface such that more liquid is lifted to the surface.
In one embodiment, the pretreatment solution 62 is an electrolytic antisurfactant solution. The electrolytic antisurfactant solution can optionally include an antisurfactant agent to increase the surface tension between air (or another gas) and liquid. In one embodiment, the solution 62 can include one or more of an electrolytic or a saccharidic. In another embodiment, the pretreatment solution is a sodium chloride solution. In still another embodiment, the pretreatment solution includes a sucrose solution. Additionally, or alternatively, the solution can optionally have a high antisurfactant concentration. In one embodiment, the solution 62 may optionally include phosphorous. Testing of various solutions with the backsweep lift of the present invention indicates that saccharidic antisurfactants that include phosphorous increase the volume of liquids (such as water) removed by at least approximately 20 percent compared to pure water that has not been mixed with a pretreatment solution 62. Additionally, testing indicates that a saccharidic-phosphoric anti-surfactant pretreatment solution improves efficiency compared to other pretreatment solutions that were tested. More specifically, a saccharidic-phosphoric anti-surfactant pretreatment solution successfully achieved an increase in production at a volume that is 1/100 less than the volume required by an electrolytic surfactant or a simple saccharidic surfactant.
The backsweep lift 20 of one embodiment of the present invention can optionally include a control system 66. The control system generally includes a processor, a memory, a bus, and instructions stored in the memory. The instructions are operable to control one or more elements of the backsweep lift 20. More specifically, in one embodiment, the control system 66 is in communication with and can send instructions to activate elements of the backsweep lift. For example, the control system can automatically begin the injection of gas into the well 4 to remove stagnant liquid from the wellbore 8. In one embodiment, the control system 66 can send a signal to activate or deactivate the compressor 48. Additionally, or alternatively, the control system may send a signal to open or close a valve associated with the tank 46. In this manner, the control system can automatically inject gas into the well 4 to lift stagnant liquid from the wellbore. The control system may also control the rate at which the gas is injected by sending instructions to the gas flow meter 50. In one embodiment, the control system can optionally send a signal to the solution check valve 56 to permit the injection of a pretreatment solution into the well 4.
Suitable control systems are known to those of skill in the art. In one embodiment the control system is a personal computer. In another embodiment, the control system 66 is a personal computer running the MS Windows operating system. Optionally, the control system 66 can be a smart phone, a tablet computer, a laptop computer, and similar computing devices. In one embodiment, the control system 66 is a data processing system which includes one or more of, but is not limited to: at least one input device (e.g. a keyboard, mouse, or touch-screen); an output device (e.g. a display, a speaker); a graphics card; a communication device (e.g. an Ethernet card or wireless communication device); permanent memory (such as a hard drive); temporary memory (for example, random access memory); computer instructions stored in the permanent memory and/or the temporary memory, and a processor. The control system 66 may be any programmable logic controller (PLC). One example of a suitable PLC is a Controllogix PLC produced by Rockwell Automation, Inc., although other PLCs are contemplated for use with embodiments of the present invention.
In one embodiment, the backsweep lift 20 further comprises one or more sensors 68. The sensors 68 are operable to determine a pressure of gas at one or more locations of the well. Additionally, or alternatively, the sensors 68 can measure the volume or flow rate of a fluid, such as gas, at one or more locations.
Suitable sensors that can measure flow rates and the pressure of gas are known to those of skill in the art. The sensors 68 may include one or more of a helical bourdon tube gauge, a strain gauge, a quartz crystal gauge, a surface readout gauge, and a digital memory gauge. Additionally, or alternatively, the sensor 68 may be one or more of a spinner flowmeter, a torque flowmeter, and a cross-correlation flowmeters.
In one embodiment, a sensor 68A is positioned at the wellhead 6. The sensor 68A may be interconnected to the lift tube 38 at the surface. In one embodiment, the sensor 68A is a multiphase flowmeter. Suitable multiphase flowmeters are known to those of skill in the art.
Optionally, a sensor 68B can be interconnected to the lift tube 38 in the wellbore 8, such as within the horizontal section 12. In one embodiment, the sensor 68B is a pressure sensor. The pressure sensor 68B is optionally positioned within the production tubing 30.
The control system 66 may be in communication with one or more of the sensors 68. Additionally, or alternatively, the control system 66 may also be in communication with the flow meters 26, 50, the compressor 48, the pump 58, and the check valves 56A, 56B. In one embodiment, the control system 66 can automatically send a signal to a valve to inject gas from the tank 46 into the wellbore in response to data from a sensor. For example, in one embodiment, the control system 66 can monitor the flow rate and/or pressure of gas at the wellhead 6, such as with data from sensor 68A. When one or more of the flow rate and the pressure drop below a predetermined level, or drop by a predetermined amount or a predetermined percent, the control system 66 can send a signal to inject gas into the wellbore to lift stagnant liquid from the well. Optionally, the control system 66 can send a signal to inject a pretreatment solution into the wellbore.
The control system 66 can control the injection of gas and/or pretreatment solution into the well based on one or more of the pressure of gas at the surface and the volume of gas flowing through the lift tube 38. More specifically, the control system 66 can control the duration and frequency of the fluid loading in the well and also the periods during which compressed gas and pretreatment solutions are injected into the well. In this manner, the gas-to-liquid removal efficiency of the backsweep lift can be optimized resulting in the removal of more liquid per cycle, lower expenses due to operation of the gas compressor 48, and improved production of hydrocarbons from the well.
Referring now to FIGS. 3-6, operation of the backsweep lift 20 of one embodiment of the present disclosure is generally illustrated. FIG. 3 generally illustrates a liquid buildup phase. During the liquid buildup phase, hydrocarbon production through the production tubing 30 will generally decrease over time. The duration of the liquid buildup phase is determined by the flowrate incoming from the formation and the pressure loses registered in the perforations 14. The flowrate can be calculated from the inflow performance relationship if the permeability and flowing radius of the formation are known. The pressure drops in the formation are generally related to the type of cement and size and charge type of the perforating gun used. Otherwise, the pressure drop can be calculated from the time it takes for the formation to accumulate a certain volume of liquid on the lift tube 38. This volume is determined from the geometrical specifications of the completion and the pressure reached on the lift tube which is measured by the pressure transducer located in the toe (element 68B of FIG. 1).
As fluids 88 interfere with operation of the well 4, such as by obstructing or impeding the flow of hydrocarbons to the surface, a pretreatment solution 62 can optionally be injected through the solution inlet port 54 into the wellbore, as generally illustrated in FIG. 3. In one embodiment the pretreatment solution 62 is injected into the production tubing 30 and the inner annular space 36. The pretreatment solution can enter into the lift tube through the distal end 40 of the lift tube 38 in the horizontal section 12. Additionally, or alternatively, the pretreatment solution can be injected directly into the lift tube 38.
The pretreatment solution 62 flows in the inner annular space 36 and/or the lift tube 38 from the surface to the horizontal section 12 and the lower end 32 of the production tubing 30. As the pretreatment solution mixes with liquids 88 in the wellbore, including within the inner annular space 36, the surface tension of the stagnant liquid in the horizontal section 12 and within the lift tube 38 is increased to improve the recovery factor of the cycle. The reduction of the surface tension determines the shape and dimensions of the gas slug produced by the gas injected through the gas inlet port 44. By decreasing the surface tension of the stagnant liquid, the injected gas can form a bubble of a larger diameter. The larger diameter of the gas bubble improves the ability of the gas bubble to lift liquid as the gas bubble flows through the stagnant liquid.
As the liquid phase accumulates in the production casing 22 and the production tubing 30, the downhole check valve 34 at the end of the production tubing 30 is open 35A and allows the entrance of fluids (both gas and liquid) from the reservoir into the production tubing 30 and into the lift tube 38. However, the downhole check valve 34 prevents the pretreatment solution from flowing out of the production tubing and into the outer annular space 28.
The downhole check valve 34 remains open 35A since the pressure inside the lift tube 38 and production tubing 30 is lower than the pressure within the production casing 22. The lower pressure on the inner annular space 36 between the production tubing 30 and the lift tube 38 allows the pretreatment solution to enter the production tubing.
Referring now to FIG. 4, once a desired level of liquid is reached in the lift tube 38, gas 52 is injected from the surface through the gas inlet port 44. The injected gas 52 flows down to the level of the liquids along the inner annular space 36 between the production tubing 30 and the lift tube 38. In one embodiment, the control system 66 can determine a desired column of liquid has accumulated in the vertical section 10 of the wellbore 8 based on data from the sensor 68B (illustrated in FIG. 1) near the toe of the well.
In one embodiment, the flow rate at which the liquid travels will be proportional to the gas injection rate and the ratio between the cross-sectional areas of the gas injection line 45 and the inner annular space 36. Any type of gas may be injected into the well by the backsweep lift 20. For example, the injected gas 52 may be a natural gas or another hydrocarbon. In one embodiment, the injected gas 52 is produced by the well 4. Optionally, an inert gas is injected into the well. Additionally, or alternatively, the gas may be nonflammable. The gas may be a combination of two or more gases.
In one embodiment, the injected gas 52 is air. Although a gas 52 other than air may be injected into the wellbore in one embodiment of the present invention, no experimental or theoretical basis suggests that the use of a gas different than common air will improve results. More specifically, tests indicate that the use of air reduces inefficiencies due to its lower compressibility. In addition, the use of air as the injected gas 52 reduces operational costs due to its availability.
As the injected gas 52 travels down the inner annular space 36, the injected gas contacts the trapped or stagnant liquid 88, increasing the pressure in the production tubing 30 and closing 35B the downhole check valve 34. With the downhole check valve closed 35B, no more fluids can enter the production tubing 30 from the hydrocarbon reservoir. Additionally, the downhole check valve 34 prevents the injected gas 52 and the pretreatment solution 62 from entering the outer annular space 28 and accessing the production casing 22 and/or the hydrocarbon reservoir 2. The injected gas causes the pressure in the production tubing 30 to increase to a level that is greater than the pressure within the lift tube 38.
Referring now to FIG. 5, due to the pressure differential between the inner annular space 36 (which is at a high pressure) and the lift tube 38 (which is at a low pressure), the injected gas 52 pushes the stagnant liquid 88 into the lift tube 38 and up to surface. In this manner, the injected gas 52 commences a production stage of the cycle. For example, the injected gas will travel from the gas inlet port 44 through the inner annular space 36 and down to the distal end 40 of the lift tube 38. The injected gas will then enter the lift tube 38 and travel back up to the surface within the lift tube, pushing or carrying stagnant liquid 88 to the surface as the injected gas 52 rises and completes the cycle.
Referring now to FIG. 6, after a predetermined volume of liquid is recovered at the surface, the injection of gas is stopped. This volume can be calculated as a function of the maximum pressure available inside the production casing 22 and either the productivity index of the well or the characteristics of the reservoir (such as one or more of permeability, flow area, and viscosity of the produced fluids). These two inputs are used along with the internal diameter of the production casing 22 to calculate the maximum height of the column of liquid that will accumulate inside the completion. The length of this column, along with the horizontal distance at which the downhole check valve 34 is installed inside the production tubing 30, determines the volume expected at the surface per production cycle, as well as the time required to load the backsweep lift 20. If the hydrostatic pressure of the accumulated column plus the expected frictional loses caused by the combination of the dimensions of the completion, the properties of the fluid and the flowrate of the injected gas result in a larger pressure requirement than that available from the gas injection system 46 at surface, then the distance from the surface to the location of the check valve in the tubing, may be reduced by repositioning the downhole check valve 34. Additionally, or alternatively, the gas injection system of the backsweep lift 20 can be enlarged, such as by increasing the volume of the tank 46 and/or the capacity of the compressor 48.
In one embodiment, when the injected gas 52 starts to flow out at the surface with the liquids 88, the injection of gas through the gas inlet port 44 may be stopped. In one embodiment, the control system 66 can automatically stop the injection of gas when injected gas is detected in the liquid 88 flowing through the lift tube 38 at the surface. In one embodiment, the mixture of injected gas 52 in the liquid 88 can be detected by a sensor, such as a multiphase flow meter 68A located downstream from the three-phase separator 64. As the tail-end of the liquid slug reaches the sensor 68A, variations in the density of the fluid as well as intermittent flow readings are recorded by the sensor. The peak values of the density will be close to that of the liquid, while the lower values will resemble those of water. This behavior indicates that the nose or beginning of the gas slug has reached surface.
The liquid slug will travel at a changing velocity that is dependent upon the position of the liquid slug within the well and the well trajectory. More specifically, the liquid slug generally travels at a slower velocity in the horizontal section 12 until the gas slug reaches the vertical section 10 of the wellbore 8. Once the gas slug reaches the vertical section, the flowrate of the phases will accelerate due to the energy accumulated by the gas phase and the reduction of the size of the liquid column as the amount of liquid above the gas slug decreases as it is pushed out of the vertical section 10 of the well.
When the injection of gas into the gas inlet port 44 stops, the loss of pressure in the inner annular space 36 and the lift tube 38 results in the fallback 88B of fluids 88 remaining in the vertical section 10 of the lift tube. The decrease of pressure in the production tubing 30 also allows the downhole check valve 34 to reopen 35A as illustrated in FIG. 6. When the downhole check valve 34 is in the open position 35A, more fluid 88 from the hydrocarbon reservoir 2 can enter the production tubing 30 and the cycle restarts.
The time required to reach this point in the operation cycle of the backsweep lift 20 can be calculated from the gas injection rate, the volume of the inner annular space 36, and the volume of lift tube 38. This can be used as an input for the control system 66 to shut of the injection of gas through the gas inlet port 44. For example, the control system 66 can close the gas flow meter 50. In one embodiment, the control system 66 includes a machine learning algorithm and can use previous cycles to improve the determination of the build-up time and the gas injection time to further improve efficiency.
Referring now to FIG. 7, a method 70 of one embodiment of the present invention for removing stagnant liquid from a wellbore 8 is generally illustrated. While a general order of operations of the method 70 is shown in FIG. 7, it will be understood by one of skill in the art that the method 70 can include more or fewer operations and can arrange the order of the operations differently than those shown in FIG. 7. Although the operations of the method may be described sequentially, many of the operations may in fact be performed in parallel or concurrently. Generally, the method 70 starts with a start operation 72 and can loop one or more times. The method 70 can be executed as a set of computer-executable instructions executed by a computer system and encoded or stored on a computer readable medium. One example of the computer system may include, for example, the control system 66. An example of the computer readable medium may include, but is not limited to, a memory of the control system 66. Hereinafter, the method 70 shall be explained with reference to the backsweep lift 20 and components described in conjunction with FIGS. 1-6.
At operation 74, the control system 66 receives data from one or more sensors 26, 68 associated with the well. The sensors may indicate that a flow rate of the well has decreased by a predetermined amount or a predetermined percent. Additionally, or alternatively, the sensors may record pressure at one or more positions of the well.
At operation 76, the control system 66 can determine whether the well is producing hydrocarbons at a sufficient level or has become loaded with stagnant liquid. Specifically, the control system can determine if the well is or is not producing hydrocarbons at a predetermined level or rate. The data from the sensor may also indicate that the pressure at the surface is below a predetermined amount, has decreased by a predetermined amount, and/or has decreased by a predetermined percentage. When the control system determines the well is producing hydrocarbons at or above a predetermined level, method 70 loops YES to operation 74. In one embodiment, the predetermined level is associated with at least one of a flow rate and a pressure. Optionally, the pressure can be above approximately 5 PSI or above approximately 100 PSI. Alternatively, when the control system 66 determines the well is producing hydrocarbons below the predetermined level, method 70 continues NO to operation 78. In one embodiment, the control system will determine the well is producing hydrocarbons below the predetermined level when the pressure is less that approximately 25 PSI, or less than approximately 5 PSI. Additionally, or alternatively, the control system can determine the well is producing hydrocarbons below the predetermined level when the flow rate of hydrocarbons at the surface is less that approximately 25 cubic feet per minutes (CFM) or less than approximately 5 CFM.
In operation 78 the control system can optionally inject a pretreatment solution into the wellbore. The control system 66 can send a signal to open a valve associated with the solution inlet port 54. Optionally, the control system 66 will also activate the pump 58.
In operation 80, the control system can send a signal to begin the injection of gas into the wellbore 8 through the gas inlet port 44. In one embodiment, the control system will send the signal to a valve associated with the tank 46 and/or the gas inlet port 44 to start the injection of gas into the wellbore. Optionally, the control system 66 can send a signal to the gas flow meter 50 to control the rate and/or pressure of the gas injected. The control system 66 may also activate the compressor 48 if necessary.
In operation 82 the control system 66 can receive data from a sensor indicating that liquid is recovered from the lift tube 38 at the surface. The control system may also receive data on the volume of liquid recovered from the lift tube. Additionally, or alternatively, the control system 66 may optionally receive data indicating that gas injected into the wellbore through the gas inlet port 44 is being recovered from the lift tube 38 at the surface. In one embodiment, the control system 66 receives the data from one or more of the flow meter 26, sensor 68A, and a sensor associated with the three-phase separator 64.
In operation 84 the control system can determine whether the injection of gas into the wellbore should continue. More specifically, after a predetermined amount of liquid is recovered at the surface, the control system 66 can send a signal to stop the injection of gas into the wellbore in operation 86. The predetermined amount of liquid can be between approximately 1 barrel to approximately 50 barrels.
Additionally, or alternatively, the control system can optionally send the signal after a predetermined period of time has elapsed from when the injection of gas started in operation 80. For example, the control system 66 may send a signal to stop the injection of gas after approximately 30 minutes, after 1 hour, or after 2 hours.
In one embodiment, the control system can stop the injection of gas after a predetermined volume of gas has been injected into the well. For example, the control system can stop the injection of gas after approximately 10,000 ft³of gas has been injected. Alternatively, the control system can send the signal to stop the injection of gas after approximately 30,000 ft³, or approximately 100,000 ft³of gas has been injected. When the control system determines the injection of gas should stop, the method 70 continues NO to operation 86 and then loops back to operation 74 to begin another cycle of method 70. When the control system 66 determines the injection of gas should continue, the method loops back YES to operation 78 and the control system can optionally inject more solution and/or gas into the wellbore 8.

EXAMPLES

The backsweep lift 20 of one embodiment of the present invention was tested in a low-pressure loop that includes a vertical section and a horizontal section. The loop was instrumented using gas mass flow meters and liquid flow meters to control the gas supplied to the backsweep lift and measure the liquids produced respectively. The frictional and gravitational pressure drops were measured using digital transducers installed across the horizontal and vertical sections of the loop. All the data was logged using a digital unit connected to each of the measuring devices, sampling the information at a rate of one take per 0.08 seconds for each measuring device. The data obtained was used to model the operation of the backsweep lift 20 and predict the volumes of liquid removed from the completion and the injected gas-to-recovered liquid efficiency.
The performance of the backsweep lift of the present invention relies on the optimization of the sweeping effect of the injected gas (known as a Taylor bubble) as the injected gas pushes the liquids through the lift tube 38 to the surface. Generally, the relatively small diameter of the lift tube 38 improves the ability of the Taylor bubble formed by the injected gas to push liquid to the surface. The results are presented in terms of the Eötvös number (Eo) and the Reynolds number of the injected gas (Re). The Eötvös number relates the gravitational forces acting on the gas-liquid interface to the surface tension forces present between the two immiscible fluids and it is a function of liquid and gas density, surface tension between gas and liquid, and internal diameter. The Reynolds number measures the ratio of inertial to viscous forces for the Taylor bubble neglecting the film thickness.
It has been observed that the raise velocity of the gas (given by a Froude number) for the same liquid decreased as the Eötvös number decreased. The Froude number relates the inertial to the gravitational forces and measures the capacity of a body to displace over the surface of a liquid. In the case of multiphase flow, the Froude number addresses the ease with which one phase slides over another. Studies have shown that in the case of water, for Eo<70, the displacement of the Taylor bubble only depends on the surface tension. This occurs for a Morton number (Mo) (which relates the viscous to the surface tension forces) below 2E10-8 and to Eo numbers smaller than 50.
Other studies have shown that for a surface tension dominated area of a Taylor bubble, the rise velocity of the Taylor bubble is related to a certain shape of the nose and the diameter of the gas slug. As the Eo number of the Taylor bubble decreases, the roundness of the nose of the Taylor bubble changes towards a sharper angle. In the same sense, the clearance between the Taylor bubble and an interior surface of the lift tube 38 is reduced. This restricts the flow of the liquid film downwards as it enters the space with a sharper angle change, due to a more drastic flow area change.
When the Eo number is approximately 4.23, a zone of recirculation exists at the nose of the Taylor bubble which reduces a downward streamline of the liquid. Accordingly, when the Eo number is approximately 4.23, the Taylor bubble has little or no ability to rise in the liquid and access of fluids past the Taylor bubble is practically prevented, forbidding the gas phase to flow through the liquid column of the lift tube 38.
FIG. 8 is a graph showing the performance of the system for a line with an inner diameter of approximately 0.375 inches with air injected at approximately 45 psi at a rate of approximately 5 standard cubic feet per minute (scf/m). The logging device was set at a sampling rate of 0.08 seconds, therefore each timestep represents a 0.08 second lapse. The air injection starts around the timestep 280 (or 23.2 seconds after the data logging unit started taking data). Line 90 comprises closed circles and represents pressure drop per unit length (dP/dL) in the horizontal annular space or annulus. Line 92 includes X's and represents dP/dL in the horizontal tubing. The dp/dL in the vertical tubing is represented by line 94 comprising triangles. Finally, production is represented by line 96 which includes squares.
At timestep 280, the fluids begin to move, registering an increase in the pressure drop per unit length (dP/dL), presented in the lines 90, 92, and 94. The difference between the magnitude of the dP/dL of the horizontal tubing 92 and the vertical tubing 94 is due to the action of gravity against the flow in the vertical tubing. The difference between the dP/dL of the horizontal tubing 92 and the annulus 90 is due to the lower velocity occurring in the annulus.
At about 10 seconds after starting the injection of gas into the wellbore, the cumulative production (line 96) starts to increase, showing an inclined straight line that maintains up to about 40 seconds after the injection of air started (timestep 800). While the gas slug was still in the horizontal section, the frictional pressure drop in both the horizontal section of tubing (line 92) and the vertical section of the tubing (line 94) remains generally constant which is a product of a constant flowing velocity. This is caused by the constant hydrostatic pressure on the vertical section, which balances the pressure of the gas generating the flow at constant rate. Once the gas cleared the horizontal section and started to travel up through the vertical tubing, the hydrostatic pressure diminished, allowing an acceleration of the flow of the two phases, and so an exponential increase of the frictional pressure drop was recorded at approximately the 800th timestep or about 32 seconds after the cycle started.
It is hypothesized that the flow behaves as one big liquid slug, being pushed by a gas slug, which reflects the idea of a piston effect or plowing of the Taylor bubble as it travels along the production line. The undulations observed in the frictional pressure drop are a product of the slugging pattern that took place once the front of the Taylor bubble cleared the production line. Because the injection of gas into the system was cut once the Taylor bubble cleared the production line, the pressure of the gas decreased, which explains the declining trend of the pressure drop during the slug flow. The frictional pressure drop in the annulus (line 90) was several times lower than those seen in the horizontal and vertical sections of the tubing, since the cross-sectional area of the annular space was much larger than the cross-sectional area of the tubing.
FIG. 9 is another graph illustrating a production and a pressure profile for one operating cycle of the backsweep lift of one embodiment of the present invention with a lift tube 38 having an interior diameter of approximately 0.75 inches. During the cycle, air was injected at approximately 40 psi at a rate of approximately 0.1 scf/min. As shown in FIG. 9, the air injection started when the pressure at the toe 102 (represented with hollow circle data points) reached 6 psi, about 18 seconds after starting to record the data. This was the largest pressure that the pump could provide to the experimental loop, therefore the maximum column of accumulated liquid possible. As the gas pressure in the system starts to increase, the liquid pressure in the system starts to decrease, which is observed at about 19 seconds, as the pressure gradient or pressure drop per unit length in the system 106 (indicated by the hollow triangle data points) starts to reduce from the expected value of approximately 45 psi/ft (which is the water pressure gradient for that temperature). The pressure at the heel 100 (indicated by X data points) (read by a transducer above the column of water) starts to increase, which indicates the beginning of liquid flow past this point. After about 50 seconds of operation, the pressure drop per unit length (pressure gradient 106, which is represented by triangles) reaches its lowest values, indicating the compensation of the gravity of the column with the pressure supplied by the gas. From here to approximately the 105th second, the pressure gradient line 106 presents approximately steady state conditions, indicating the existence of single-phase flow. From approximately 50 seconds to approximately 105 seconds, the pressure lines 100 and 102 show approximately steady state behavior as well, and the readings from the liquid flowmeter 98 (indicated by hollow diamonds), remain generally constant as well. During the experiments, no gas was observed in the vertical section up to this point.
Once the gas slug reached the vertical section (after about 110 seconds), the pressure (100, 102) in the vertical lines started to decrease, while the liquid rate 98 accelerated. This shows the acceleration of the gas slug due to the reduction of the size of the liquid column on top of the gas slug. From this point on, the hydrostatic pressure and the gas pressure do not balance anymore, allowing the gas slug to flow faster. For this same reason, the trend of the production line 104 (represented by hollow squares) increases and the pressure drop per unit length 106 increases dramatically as the fluids start to travel on a slug flow pattern and then an annular flow pattern, as the gas accelerates due to a smaller liquid column on the vertical section of the completion. In the first slug flow pattern, the liquids arrive at the surface as intermittent pulses of gas and liquid as the gas clears the remaining liquids in the vertical section. In the second annular flow pattern, the liquids flow to surface along the pipe in a film covering the wall, while the gas travels at high speed through the center of the pipe. At this moment the gas valve was shut down to repeat the cycle.
The experimental results prove the piston-like behavior of the gas during the early times of the operation. As the Taylor bubble travels along the production line, before reaching the vertical section, nearly 80% of the production of the stagnant liquid occurs in single phase form. The remaining 20% of the production arrives in intermittent slugs and annular flow. The undulations observed in the frictional pressure drop are a product of the slugging pattern that took place once the front of the Taylor bubble reached the vertical section of the production line. When the Taylor bubble cleared the production line, injection of gas into the system was cut and the pressure of the gas decreased. This explains the declining trend of the pressure drop during the slug flow.
To observe the impact of the flowrate and the Eotvos number on the Recovery Factor, the experimental protocol was repeated several times for each test slot according to the experimental matrix. Each of the data points presented in FIGS. 8 and 9 represents the averaged results of eight operating cycles held at the same gas flowrate for tubing with the same inner diameter.
Referring now to FIG. 10, it can be observed that the lower the Reynolds number of the injected gas, the larger the recovery factor of the system. Most probably, the lower turbulence seen at low flowrates allows for a more stable Taylor bubble, and therefore a better seal between the gas and the wall.
Bubbles raising with higher velocities are less efficient at clearing stagnant liquid from the wellbore. More specifically, bubbles raising at higher velocities presented a zig-zagging shape and a large tear at the tail. The shape of the bubbles raising with higher velocities is inefficient and facilitates the backflow of liquids along the liquid film surrounding the Taylor bubble and reduces the sweeping capacity or piston effect of the Taylor bubble.
It can also be observed in FIG. 10 that the lower the Eo number, the higher the Recovery Factor of the system. Inferring from these results, the lower the Eo number, the better the sweeping or piston effect of the Taylor bubble and increased transport of stagnant liquid from the wellbore. The best results are obtained when closer to the critical Eo=4.4, which yields a Recovery Factor of up to 76%. Accordingly, a stable Taylor bubble improves the ability of the gas injected by the backsweep lift 20 of the present invention to move liquid through the lift tube 38. In one embodiment, the systems and methods of the present invention are configured to form a Taylor bubble in the lift tube with an Eötvös number of approximately Eo=4. In one embodiment, the backsweep lift 20 of the present invention injects gas into the wellbore such that a Taylor bubble formed in the lift tube 38 has an Eötvös number of between approximately 3.9 and approximately 4.7.
The backsweep lift of embodiments of the present invention provides many benefits compared to known artificial lift systems and methods. For example, embodiments of the backsweep lift of the present invention can be installed in a wellbore without removing existing tubing from the wellbore. Accordingly, the operational cost of the backsweep lift is lower than known artificial lift systems. Moreover, the backsweep lift can be installed quicker than known systems that require removal of existing tubing from the wellbore, decreasing the intervention time or “downtime” of the well required to install the backsweep lift. Further, the backsweep lift does not require installation of gas lift valves in the vertical section of the wellbore. Additionally, the backsweep lift of the present disclosure injects a lower volume of gas into the well compared to other intermittent gas lift systems. The gas injected into the well according to embodiments of the present invention does not contact the geologic formation.
While various embodiments of the system have been described in detail, it is apparent that modifications and alterations of those embodiments will occur to those skilled in the art. It is to be expressly understood that such modifications and alterations are within the scope and spirit of the present disclosure. Further, it is to be understood that the phraseology and terminology used herein is for the purposes of description and should not be regarded as limiting. The use of “including,” “comprising,” or “having” and variations thereof herein are meant to encompass the items listed thereafter and equivalents thereof, as well as, additional items.
The term “automatic” and variations thereof, as used herein, refers to any process or operation, which is typically continuous or semi-continuous, done without material human input when the process or operation is performed. However, a process or operation can be automatic, even though performance of the process or operation uses material or immaterial human input, if the input is received before performance of the process or operation. Human input is deemed to be material if such input influences how the process or operation will be performed. Human input that consents to the performance of the process or operation is not deemed to be “material.”
Aspects of the present disclosure may take the form of an embodiment that is entirely hardware, an embodiment that is entirely software (including firmware, resident software, micro-code, etc.) or an embodiment combining software and hardware aspects that may all generally be referred to herein as a “circuit,” “module,” or “system.” Any combination of one or more computer-readable medium(s) may be utilized. The computer-readable medium may be a computer-readable signal medium or a computer-readable storage medium.
A computer-readable storage medium may be, for example, but not limited to, an electronic, magnetic, optical, electromagnetic, infrared, or semiconductor system, apparatus, or device, or any suitable combination of the foregoing. More specific examples (a non-exhaustive list) of the computer-readable storage medium would include the following: an electrical connection having one or more wires, a portable computer diskette, a hard disk, a random access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or Flash memory), an optical fiber, a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing. In the context of this document, a computer-readable storage medium may be any tangible medium that can contain or store a program for use by or in connection with an instruction execution system, apparatus, or device.
A computer-readable signal medium may include a propagated data signal with computer-readable program code embodied therein, for example, in baseband or as part of a carrier wave. Such a propagated signal may take any of a variety of forms, including, but not limited to, electromagnetic, optical, or any suitable combination thereof. A computer-readable signal medium may be any computer-readable medium that is not a computer-readable storage medium and that can communicate, propagate, or transport a program for use by or in connection with an instruction execution system, apparatus, or device. Program code embodied on a computer-readable medium may be transmitted using any appropriate medium, including, but not limited to, wireless, wireline, optical fiber cable, RF, etc., or any suitable combination of the foregoing.
The terms “determine,” “calculate,” “compute,” and variations thereof, as used herein, are used interchangeably and include any type of methodology, process, mathematical operation or technique.
To provide additional background, context, and to further satisfy the written description requirements of 35 U.S.C. § 112, the following references are incorporated by reference herein in their entireties: Moreiras et al., Unified Drift Velocity Closure Relationship for Large Bubbles Rising in Stagnant Viscous Fluids in Pipes, Journal of petroleum Science and Engineering, Vol. 124, pp. 359-366, December 2014 (available at https://doi.org/10.1016/j.petrol.2014.09.006); Nickens et al., The Effects of Surface Tension and Viscosity on the Rise Velocity of a Large Gas Bubble in a Closed, Vertical Liquid-Filled Tube, International Journal of Multiphase Flow, Vol. 13, Issue 1, pp. 57-69, January-February 1987 (available at https://doi.org/10.1016/0301-9322(87)90007-3); White et al., The Velocity of Rise of Single Cylindrical Air Bubbles Through Liquids Contained in Vertical Tubes, Chemical Engineering Science, Volume 17, Issue 5, pp. 351-361, 1962 (available at https://doi.org/10.1016/0009-2509(62)80036-0); and Zheng et al., CFD Simulations of Hydrodynamic Characteristics in a Gas-Liquid Vertical Upward Slug Flow, International Journal of Heat and Mass Transfer, Vol. 50, Issues 21-22, pp. 4151-4165, October 2007 (available at https://doi.org/10. 1016/j.ijheatmasstransfer.2007.02.041).

Claims

What is claimed is:

1. An intermittent gas lift system to remove stagnant liquid from a wellbore of a hydrocarbon well, comprising:

a downhole check valve interconnected to a lower end of a production tubing positioned within the wellbore;

a lift tube positioned within the production tubing, wherein an annular space is formed between an exterior surface of the lift tube and an interior surface of the production tubing; and

a gas inlet port interconnected to the production tubing at a wellhead portion of the hydrocarbon well, wherein gas injected through the gas inlet port travels down the annular space to a distal end of the lift tube in a horizontal section of the wellbore and then pushes liquid up the lift tube.

2. The gas lift system of claim 1, wherein the distal end of the lift tube is spaced from the lower end of the production tubing.

3. The gas lift system of claim 1, wherein the downhole check valve prevents fluid from flowing out of the lower end of the production tubing.

4. The gas lift system of claim 3, wherein when gas is injected through the gas inlet port into the annular space, pressure in the lower portion of the production tubing increases and the downhole check valve closes to prohibit fluid from a hydrocarbon reservoir proximate to the lower end of the production tubing from flowing into the production tubing.

5. The gas lift system of claim 3, wherein when the injection of gas through the gas inlet port into the annular space stops, pressure in the lower portion of the production tubing decreases and the downhole check valve opens to permit fluid from a hydrocarbon reservoir proximate to the lower end of production tubing to flow into the production tubing.

6. The gas lift system of claim 1, further comprising a solution inlet port at the wellhead portion of the hydrocarbon well to inject a pretreatment solution into at least one of the annular space and production tubing.

7. The gas lift system of claim 6, wherein the solution inlet port is connected to at least one of the production tubing and the lift tube.

8. The gas lift system of claim 1, further comprising a control system operable to automatically start the injection of gas into the gas inlet port when the control system determines that data from a sensor indicates the well is not producing hydrocarbons at a predetermined rate.

9. The gas lift system of claim 1, wherein the distal end of the lift tube is within the horizontal section of the wellbore.

10. The gas lift system of claim 1, further comprising a multiphase flowmeter interconnected to the lift tube proximate to the wellhead.

11. The gas lift system of claim 10, wherein the multiphase flowmeter is positioned between the wellhead portion and a three-phase separator.

12. The gas lift system of claim 1, further comprising a pressure sensor positioned within a horizontal section of the production tubing.

13. A method of removing stagnant liquid from a wellbore of a hydrocarbon well, comprising:

receiving first data from a sensor;

determining that the hydrocarbon well is not producing hydrocarbons at a predetermined rate;

injecting a gas into an annular space formed between an interior surface of a production tubing positioned within the wellbore and an exterior surface of a lift tube positioned within the production tubing;

receiving second data from the sensor indicating that liquid flowing in the lift tube at the surface includes some of the injected gas; and

stopping the injection of gas into the annular space.

14. The method of claim 13, wherein the first data received by the sensor includes one or more of a pressure measured proximate to a bottom hole location and a pressure or a flow rate of hydrocarbons from the wellbore measured at or near the surface.

15. The method of claim 13, further comprising injecting a pretreatment solution into the wellbore through at least one of the production tubing and the lift tube.

16. The method of claim 15, wherein the pretreatment solution is injected into at least one of the annular space and directly into the lift tube.

17. The method of claim 13, further comprising interconnecting a downhole check valve to a lower end of the production tubing.

18. The method of claim 13, further comprising positioning the lift tube within the production tubing.

19. The method of claim 18, wherein a distal end of the lift tube is spaced upstream from a lower end of the production tubing.

20. A non-transitory computer readable medium comprising a set of instructions stored thereon which, when executed by a processor of a control unit, cause the processor to execute a method of removing stagnant liquid from a wellbore of a hydrocarbon well, comprising:

an instruction to receive first data from a sensor;

an instruction to determine that the hydrocarbon well is not producing hydrocarbons at a predetermined rate;

an instruction to inject a gas into an annular space formed between an interior surface of a production tubing positioned within the wellbore and an exterior surface of a lift tube positioned within the production tubing;

an instruction to receive second data from the sensor indicating that liquid flowing in the lift tube at the surface includes some of the injected gas; and

an instruction to stop the injection of gas into the annular space.