US20110203792A1

US20110203792A1 - System, method and assembly for wellbore maintenance operations

Info

Publication number: US20110203792A1
Application number: US12/968,503
Authority: US
Inventors: Mark D. Looney; Robert S. Lestz; Stephen David Cassidy
Original assignee: Chevron USA Inc
Current assignee: Chevron USA Inc
Priority date: 2009-12-15
Filing date: 2010-12-15
Publication date: 2011-08-25
Also published as: CN102741500A; EA201290503A1; EP2513418A1; WO2011084497A1; CA2784496A1

Abstract

Methods for performing a wellbore maintenance operation on a system of wellbores used for improved oil recovery are disclosed. A plurality of wellbores are drilled and perforated to receive production fluids from a reservoir. The wellbores are fluidly connected to a production well that is drilled to a depth below the perforations of the wellbores. The production fluids drain and collect in the production well for delivery to the surface. A pump can be used for delivering the production fluids from the production well. During repair and maintenance operations, a fluid is injected into the production well for safely removing the pump components. The fluid is counterbalanced by the pressures in the connected wellbores such that the fluid does not rise above the perforations in the connected wellbores.

Description

CROSS-REFERENCE TO A RELATED APPLICATION

The present application for patent claims the benefit of U.S. Provisional Application bearing Ser. No. 61/286,520, filed on Dec. 15, 2009, which is incorporated by reference in its entirety.

TECHNICAL FIELD

This invention relates to oil field production apparatus and techniques, and more particularly, to such apparatus and techniques, including wellbore maintenance operations, for use in the production of low pressure wells.

BACKGROUND

In a typical five-spot producing pattern, four production wells are spaced around a production well that is centrally located. Each well operates independently. Rod pumps can be used to assist in lifting the production fluids, which are typically oil and water, to the surface. Pumps for artificial lift extend the field life by reducing the bottomhole pressure and thereby recovering more oil economically. Typically the bottom of the rod pumping string is placed above the producing interval in order to allow fluid separation and minimize the possibility of the string becoming stuck. Fluid levels should be above the pumping string intake to avoid “pounding the pump” which increases wear and reduces the life of the equipment. This in turn results in an increase of backpressure being placed on the reservoir due to the hydrostatic head. Minimizing this hydrostatic head would increase production rates and extend field life and reserves.
During fairly routine well maintenance operations, wells are often “killed” in order to safely remove and repair the rod strings. Killing a well involves injecting a high density, typically water based, fluid into the production well to provide sufficient hydrostatic pressure to keep the well from flowing. Oftentimes this fluid is displaced into the reservoir. In low pressure gas wells, rod pumps are used to keep water out of the reservoir as much as possible. If significant concentrations of water get into the reservoir, the pressure in the reservoir may not be high enough to move it back out. This often results in a significant effort to get these wells back producing. Sometimes the wells are never successfully returned to production.

SUMMARY

According to an aspect of the present invention, a method of performing a wellbore maintenance operation is disclosed. The method includes providing a drainage wellbore and a production wellbore. The drainage wellbore is perforated such that the drainage wellbore receives reservoir fluids from a producing zone of a subterranean reservoir. The production wellbore is in fluid communication with the drainage wellbore, such as through a drainage string, so that the reservoir fluids received by the drainage wellbore flow to the production wellbore. Fluid is injected into the production wellbore until the flow of the reservoir fluids from the drainage wellbore to the production wellbore is stopped. Maintenance is then performed on the production wellbore.
In one or more embodiments, fluid is injected into the production wellbore until the fluid level within the production wellbore is at an elevation above the elevation of the perforations in the drainage wellbore. In one or more embodiments, fluid injection is stopped prior to the fluid reaching the perforations in the drainage wellbore.
In one or more embodiments, at least two drainage wellbores are provided and fluid is injected into the production wellbore until the fluid level within the production wellbore is at an elevation above the perforations in the two drainage wellbores. In one or more embodiments, fluid injection is stopped prior to the fluid reaching any of the perforations in the two drainage wellbores.
In one or more embodiments, gas is injected into the drainage wellbore to force the fluid back up through production wellbore and allow the reservoir fluids received by the drainage wellbore to flow to the production wellbore. The reservoir fluids can then be produced from the production wellbore.
According to another aspect of the present invention, a method of performing a wellbore maintenance operation is disclosed. The method includes providing a system of wellbores including a drainage wellbore, a drainage string, and a production wellbore for producing reservoir fluids. The drainage wellbore includes a perforation such that the drainage wellbore receives reservoir fluids from a producing zone of a subterranean reservoir. The drainage string extends between the drainage wellbore and the production wellbore. Reservoir fluids received by the drainage wellbore flow through the drainage string to the production wellbore for production. A fluid is injected into the production wellbore until the hydrostatic pressure in the production wellbore is sufficient to stop the flow of the reservoir fluids received by the drainage wellbore from flowing to the production wellbore. Maintenance is then performed on the production wellbore.
In one or more embodiments, fluid is injected into the production wellbore until the fluid level within the production wellbore is at an elevation above the elevation of the perforations in the drainage wellbore. In one or more embodiments, fluid injection is stopped prior to the fluid reaching the perforations in the drainage wellbore.
In one or more embodiments, at least two drainage wellbores are provided and fluid is injected into the production wellbore until the fluid level within the production wellbore is at an elevation above the perforations in the two drainage wellbores. In one or more embodiments, fluid injection is stopped prior to the fluid reaching any of the perforations in the two drainage wellbores.
In one or more embodiments, gas is injected into the drainage wellbore to force the fluid back up through production wellbore and allow the reservoir fluids received by the drainage wellbore to flow to the production wellbore. The reservoir fluids can then be produced from the production wellbore.
According to another aspect of the present invention, a method of performing a wellbore maintenance operation is disclosed. The method includes providing a drainage wellbore and a production wellbore. The drainage wellbore receives reservoir fluids from a producing zone of a subterranean reservoir. The production wellbore is in fluid communication with the drainage wellbore such that the reservoir fluids received by the drainage wellbore flow to the production wellbore. A fluid is injected into the production wellbore until the hydrostatic pressure in the production wellbore is sufficient to stop the flow of the reservoir fluids received by the drainage wellbore from flowing to the production wellbore. Maintenance is then performed on the production wellbore. Gas is then injected into the drainage wellbore to force the fluid back up through production wellbore and allow the reservoir fluids received by the drainage wellbore to flow to the production wellbore. The reservoir fluids are then produced from the production wellbore.
In one or more embodiments, the drainage wellbore is in fluid communication with the producing zone of the reservoir through a perforation in the drainage wellbore. Fluid is injected into the production wellbore until the fluid level within the production wellbore is at an elevation above the elevation of the perforations in the drainage wellbore.
In one or more embodiments, the drainage wellbore is in fluid communication with the producing zone of the reservoir through a perforation in the drainage wellbore. Fluid injection is stopped prior to the fluid reaching the perforations in the drainage wellbore.
In one or more embodiments, at least two drainage wellbores are provided, each drainage wellbore being in fluid communication with the producing zone of the reservoir through a perforation in the drainage wellbore. Fluid is injected into the production wellbore until the fluid level within the production wellbore is at an elevation above the perforations in the two drainage wellbores.
In one or more embodiments, at least two drainage wellbores are provided, each drainage wellbore being in fluid communication with the producing zone of the reservoir through a perforation in the drainage wellbore. Fluid injection is stopped prior to the fluid reaching any of the perforations in the two drainage wellbores.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic, sectional view of a prior art arrangement of production wells extending into a reservoir having hydrocarbons.

FIG. 2 is a schematic, sectional view of an arrangement of wells extending into a reservoir having hydrocarbons according to an aspect of the present invention.

FIG. 3 is a schematic, sectional view of the arrangement of FIG. 2 for workover operations.

DETAILED DESCRIPTION

Referring to prior art FIG. 1, a plurality of production wells 11 are spaced for producing hydrocarbons from a reservoir 13. Production wells are spaced in a typical five-spot producing pattern, as shown in FIG. 1, for production of hydrocarbons from reservoir 13. Each well 11 operates independently in the five-spot pattern shown in FIG. 1. Each well 11 typically comprises a plurality of casing strings inserted into the well after being drilled and then cemented into place. The plurality of casing strings collectively define the outer boundary or outer casing 15 of well 11. For ease of illustration, the plurality of casing strings of outer casing 15 are represented in FIG. 1 as a single string of casing. After reaching the desired depth in reservoir 13, such that well 11 extends to oil sands 19—a portion of a reservoir having hydrocarbons, the outer casing is perforated. Forming perforations 17 allows fluid communication between oil sands 19 of reservoir 13 and the interior of well 11.
Each well 11 typically includes a string of production casing or tubing 21 that is carried within outer casing 15. Tubing 21 has an opening for receiving production fluids (typically oil, water, and gas) at its lower end. Packer seals 23 are positioned between production tubing 21 and casing 15 to force production fluids from reservoir 13 to flow through production tubing 21.
Pump assemblies 25, which have a rod pumping string positioned within production tubing 21, are used for communicating production fluids to the surface. For example, pump assemblies 25 can be used when the pressure associated with reservoir 13 is low and produced fluids do not flow to the surface. Pump assemblies 25 help to extend the life of wells 11.
Typically the bottom of the rod pumping string of pump assembly 25 is positioned above “the producing interval” in order to allow initial fluid separation between the gas and liquid phases of the production fluids, and to minimize the possibility of the string becoming stuck. It is preferable that the fluid levels of the liquids in the production fluids remain above the pumping string intake to avoid “pounding the pump” which increases wear and reduces the life of the equipment. Maintaining the liquid levels of the production fluids above the intake of pump assembly 25 increases the hydrostatic head within production tubing 21 which in turn results in backpressure being placed on reservoir 13. Reducing this hydrostatic head can further increase production rates and extend field life associated with reservoir 13.
Referring to FIG. 2, a plurality of drainage wellbores 27 extend to production depths within reservoir 13. Drainage wellbores 27 are spaced apart similar to the outer production wells 11 in the five-spot producing pattern of FIG. 1. Drainage wellbores 27 have perforations 29 formed in the respective outer casings 31 for receiving production fluids from reservoir 13. Perforation 29 associated with one drainage wellbore 27 can be at a different reservoir depth from perforation 29 of another drainage wellbore 27 for optimal hydrocarbon production. Each drainage wellbore 27 also includes packer seal 32 positioned within casing 31 above perforation 29.
Production well 11′ extends into reservoir 13 adjacent drainage wellbores 27. Production well 11′ is drilled and completed with substantially the same components as wells 11 in FIG. 1, except that production well 11′ extends deeper into reservoir 13 than drainage wellbores 27. A plurality of drainage strings 33 extend between a lower end portion of production well 11′ and drainage wellbores 27 so that production well 11′ is in fluid communication with drainage wellbores 27. Because lower end portion of production well 11′ is deeper than drainage wellbores 27, gravity helps production fluids from drainage wellbores 27 to collect within production well 11′ for collection with pump assembly 25′. Drainage strings 33 can be formed with directional drilling techniques when first drilling drainage wellbores 27 and production well 11′, or with directional drilling between existing wells in an older field. Drainage strings 33 preferably comprise a string of casing or tubing that is installed after drilling.
As shown in FIG. 2, pump assembly 25′ is disposed within production well 11′. Drainage wellbores 27 do not include pump assemblies 25′. This inherently reduces the amount of maintenance associated with the wells of the five-spot pattern shown in FIG. 2. Moreover, this also helps to reduce the cost and maintenance associated with pump assemblies 25 (FIG. 1) by only having a single pump assembly 25′ (FIG. 2). In FIG. 2, production well 11′ is positioned in the center of drainage wellbores 27. However, production well 11′ can be any of the positions in the five-spot pattern. Furthermore, drainage wells 27 and production well 11′ can be in other production patterns. In the system of FIG. 2, packer seals 32 can be cheaper packer seals since there is not a string of production tubing being sealed between outer casing 31. This also provides for additional cost savings and reduction of maintenance.
As shown in FIG. 2, production well 11′ can be without any perforations 17 such that production well 11′ is merely used for collecting and delivering production fluids from drainage wellbores 27. Not having any perforations within production well 11′ advantageously allows the rod pumping string of pump assembly 25′ to be set below the perforations in all of the other connecting drainage wellbores 27. This achieves the lowest possible bottom-hole pressure in the connecting wells by having a fluid level below the perforations while still maintaining fluid level over the rod string entry. In such a system, higher production rates can be achieved and additional reserves can be realized.
FIG. 3 illustrates how the assembly of the present invention is advantageous during workover operations. During workover operations on the well, the pump rod string of pump assembly 25′ is often removed. Additionally, pump rod string of pump assembly 25′ can be removed for maintenance and repair of pump assembly 25′, which is fairly routine.
As previously described, to perform such operations in conventional well arrangements, such as production wells 11 shown in FIG. 1, wells are often “killed” in order to safely pull the rod pumping string of pump assembly. “Killing” production well 11 (FIG. 1), typically involves injecting a high density, typically water-based, fluid into production well 11. This provides sufficient hydrostatic pressure to keep production well 11 from flowing (i.e., cease flow of production fluids into production well 11 through perforations 17). It is common for the injected fluid used for “killing” well 11 to get displaced into reservoir 13. In low pressure gas wells, such as production wells 11 shown in FIG. 1 and production well 11′ shown in FIG. 2, pump assemblies 25,25′ are used to keep water out of reservoir 13 as much as possible. Reducing backflow of water into reservoir 13 is important because if significant concentrations of water enter into reservoir 13, the pressure in reservoir 13 may not be high enough to move the water-based injected fluid back out. When the water-based injection fluid does flow into reservoir 13, this often results in a significant effort to get production well 11 producing again—sometimes production wells 11 are never successfully returned to production.
According to a method of the present invention, fluidly connected production well 11′ and drainage wellbores 27 act as the closed end of a manometer. In order to “kill” production well 11′ and drainage wellbores 27, fluid can be injected into the bore of production well 11′. As the fluid level of the injected fluid and the produced fluid collecting in production well 11′, drainage wellbores 27, and drainage strings 33 rises, the fluid compresses the separated gas above it in drainage wellbores 27. As seen in FIG. 3, fluid can be injected into production well 11′ until the fluid level within production well 11′ is at least above perforations 29 in all of drainage wellbores 27. The hydrostatic pressure in production well 11′ is balanced by the hydrostatic pressure of the fluid in drainage wellbores 27 plus the pressure of the compressed gas phase in drainage wellbores 27. As a result, the fluid level in drainage wellbores 27 is lower than in production well 11′, and the fluid can be kept below perforations 29. With the fluid (produced fluid and the water-based injected fluid) being below perforations 29, the risk of the fluids flowing into reservoir 13 is significantly reduced. Therefore, maintenance and repairs can be performed while production well 11′ is “killed,” while reducing the difficulties with returning production well 11′ to production.
Moreover, returning production well 11′ after maintenance is performed is simplified as gas can be injected into drainage wellbores 27 to push the fluid back up through production wellbore 11′. Accordingly, this reduces the likelihood of the “kill” fluid from entering perforations 29 and allows the reservoir fluids received by drainage wellbore 29 to resume flowing to production wellbore 11′. Accordingly, the reservoir fluids can then be produced again from the production wellbore.
While the invention has been shown in only some of its forms, it should be apparent to those skilled in the art that it is not so limited, but susceptible to various changes without departing from the scope of the invention.

Claims

1. A method of performing a wellbore maintenance operation, the method comprising:

(a) providing a drainage wellbore that is perforated with a perforation such that the drainage wellbore receives reservoir fluids from a producing zone of a subterranean reservoir;

(b) providing a production wellbore in fluid communication with the drainage wellbore such that the reservoir fluids received by the drainage wellbore flow to the production wellbore;

(c) injecting fluid into the production wellbore until the flow of the reservoir fluids from the drainage wellbore to the production wellbore is stopped; and

(d) performing maintenance on the production wellbore.

2. The method of claim 1, wherein the production wellbore is in fluid communication with the drainage wellbore through a drainage string that extends between the lower portions of the drainage wellbore and the production wellbore.

3. The method of claim 1, wherein the fluid is injected into the production wellbore in step (b) until the fluid level within the production wellbore is at an elevation above the elevation of the perforation in the drainage wellbore.

4. The method of claim 1, wherein the injecting of the fluid into the production wellbore in step (b) is stopped prior to the fluid level reaching the perforation in the drainage wellbore.

5. The method of claim 1, wherein:

at least two drainage wellbores are provided in step (a); and

the fluid is injected into the production wellbore in step (b) until the fluid level within the production wellbore is at an elevation above the perforations in the at least two drainage wellbores.

6. The method of claim 1, wherein:

at least two drainage wellbores are provided in step (a); and

the injecting of the fluid into the production wellbore in step (b) is stopped prior to the fluid level reaching any of the perforations in the at least two drainage wellbores.

7. The method of claim 1, further comprising:

(e) injecting a gas into the drainage wellbore to force the fluid back up through production wellbore and allow the reservoir fluids received by the drainage wellbore to flow to the production wellbore; and

(f) producing the reservoir fluids from the production wellbore.

8. A method of performing a wellbore maintenance operation, the method comprising:

(a) providing a system of wellbores comprising a drainage wellbore that is perforated with a perforation such that the drainage wellbore receives reservoir fluids from a producing zone of a subterranean reservoir, a production wellbore for producing the reservoir fluids, and a drainage string extending therebetween such that reservoir fluids received by the drainage wellbore flow through the drainage string to the production wellbore;

(b) injecting a fluid into the production wellbore until the hydrostatic pressure in the production wellbore is sufficient to stop the flow of the reservoir fluids received by the drainage wellbore from flowing to the production wellbore; and

(c) performing maintenance on the production wellbore.

9. The method of claim 8, wherein the fluid is injected into the production wellbore in step (b) until the fluid level within the production wellbore is at an elevation above the elevation of the perforation in the drainage wellbore.

10. The method of claim 8, wherein the injecting of the fluid into the production wellbore in step (b) is stopped prior to the fluid level reaching the perforation in the drainage wellbore.

11. The method of claim 8, wherein:

at least two drainage wellbores are provided in step (a); and

12. The method of claim 8, wherein:

at least two drainage wellbores are provided in step (a); and

13. The method of claim 8, further comprising:

(a) injecting a gas into the drainage wellbore to force the fluid back up through production wellbore and allow the reservoir fluids received by the drainage wellbore to flow to the production wellbore; and

(b) producing the reservoir fluids from the production wellbore.

14. A method of performing a wellbore maintenance operation, the method comprising:

(a) providing a drainage wellbore that receives reservoir fluids from a producing zone of a subterranean reservoir;

(c) injecting a fluid into the production wellbore until the hydrostatic pressure in the production wellbore is sufficient to stop the flow of the reservoir fluids from the drainage wellbore to the production wellbore;

(d) performing maintenance on the production wellbore;

(f) producing the reservoir fluids from the production wellbore.

15. The method of claim 14, wherein the production wellbore is in fluid communication with the drainage wellbore through a drainage string that extends between the lower portions of the drainage wellbore and the production wellbore.

16. The method of claim 14, wherein:

the drainage wellbore is in fluid communication with the producing zone of the reservoir through a perforation in the drainage wellbore; and

the fluid is injected into the production wellbore in step (b) until the fluid level within the production wellbore is at an elevation above the elevation of the perforation in the drainage wellbore.

17. The method of claim 14, wherein:

the injecting of the fluid into the production wellbore in step (b) is stopped prior to the fluid level reaching the perforation in the drainage wellbore.

18. The method of claim 14, wherein:

at least two drainage wellbores are provided in step (a), each of the drainage wellbores being in fluid communication with the producing zone of the reservoir through a perforation in the drainage wellbore; and

19. The method of claim 14, wherein: