Patent Application
20090183873
This invention relates generally to an apparatus and method for use in wellbores. More particularly, this invention relates to a wellbore apparatus and method for producing hydrocarbons and managing sand production.
This section is intended to introduce the reader to various aspects of art, which may be associated with exemplary embodiments of the present invention, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with information to facilitate a better understanding of particular techniques of the present invention. Accordingly, it should be understood that these statements are to be read in this light, and not necessarily as admissions of prior art.
The production of hydrocarbons, such as oil and gas, has been performed for numerous years. To produce these hydrocarbons, a production system may utilize various devices, such as sand control devices and other tools, for specific tasks within a well. Typically, these devices are placed into a wellbore completed in either cased-hole or open-hole completion. In cased-hole completions, wellbore casing is placed in the wellbore and perforations are made through the casing into subterranean formations to provide a flow path for formation fluids, such as hydrocarbons, into the wellbore. Alternatively, in open-hole completions, a production string is positioned inside the wellbore without wellbore casing. The formation fluids flow through the annulus between the subsurface formation and the production string to enter the production string.
When producing fluids from subterranean formations, especially poorly consolidated formations or formations weakened by increasing downhole stress due to wellbore excavation and fluids withdrawal, it is possible to produce solid material (for example, sand) along with the formation fluids. In some cases, formations may produce hydrocarbons without sand until the onset of water production from the formations. With the onset of water, these formations collapse or fail due to increased drag forces (water generally has higher viscosity than oil or gas) and/or dissolution of material holding sand grains together.
The sand/solids and water production typically results in a number of problems. These problems include productivity loss, equipment damage, and/or increased treating, handling and disposal costs. For example, the sand/solids production may plug or restrict flow paths resulting in reduced productivity. The sand/solids production may also cause severe erosion damaging equipment, which may create well control problems. When produced to the surface, the sand is removed from the flow stream and has to be disposed of properly, which increases the operating costs of the well. Water production also reduces productivity. For instance, because water is heavier than hydrocarbon fluids, it takes more pressure to move it up and out of the well. That is, the more water produced, the less pressure available to move the hydrocarbons, such as oil. In addition, water is corrosive and may cause severe equipment damage if not properly treated. Similar to the sand, the water also has to be removed from the flow stream and disposed of properly.
The sand/solids and water production may be further compounded with wells that have a number of different completion intervals and the formation strength may vary from interval to interval. Because the evaluation of formation strength is complicated, the ability to predict the timing of the onset of sand and/or water is limited. In many situations reservoirs are commingled to minimize investment risk and maximize economic benefit. In particular, wells having different intervals and marginal reserves may be commingled to reduce economic risk. One of the risks in these applications is that sand failure and/or water breakthrough in any one of the intervals threatens the remaining reserves in the other intervals of the completion.
While typical sand control, remote control technologies and interventions may be utilized, these approaches often drive the cost for marginal reserves beyond the economic limit. As such, a simple, lower cost alternative may be beneficial to lower the economic threshold for marginal reserves and to improve the economic return for certain larger reserve applications. Accordingly, the need exists for a well completion apparatus that provides a mechanism for managing the production of sand and water within a wellbore, while being able to maintain dimensional limitations.
Other related material may be found in at least U.S. Pat. No. 5,722,490; U.S. Pat. No. 6,125,932; U.S. Pat. No. 4,064,938; U.S. Pat. No. 5,355,949; U.S. Pat. No. 5,896,928; U.S. Pat. No. 6,622,794; U.S. Pat. No. 6,619,397; and International Patent Application No. PCT/US2004/01599. Further, additional information may also be found in Penberthy & Shaughnessy, SPE Monograph Series—“Sand Control”, ISBN 1-55563-041-3 (2002); Bennett et al., “Design Methodology for Selection of Horizontal Open-Hole Sand Control Completions Supported by Field Case Histories,” SPE 65140 (2000); Tiffin et al., “New Criteria for Gravel and Screen Selection for Sand Control,” SPE 39437 (1998); Wong G. K. et al., “Design, Execution, and Evaluation of Frac and Pack (F&P) Treatments in Unconsolidated Sand Formations in the Gulf of Mexico,” SPE 26563 (1993); T. M. V. Kaiser et al., “Inflow Analysis and Optimization of Slotted Liners,” SPE 80145 (2002); and Yula Tang et al., “Performance of Horizontal Wells Completed with Slotted Liners and Perforations,” SPE 65516 (2000).
In one embodiment, a system associated with the production of hydrocarbons is described. The system includes a first tubular member and a second tubular member at least partially enclosing the first tubular member disposed within a wellbore environment (e.g. a subsurface environment). The first tubular member has a non-permeable longitudinal section and a permeable longitudinal section, wherein the permeable longitudinal section has a first plurality of openings between a first central channel and a region external to the first tubular member. The second tubular member includes a non-permeable longitudinal section in substantial radial alignment with the permeable longitudinal section of the first tubular member and a permeable longitudinal section, wherein the permeable longitudinal section of the second tubular member is in substantial radial alignment with the non-permeable longitudinal section of the first tubular member and the permeable longitudinal section of the second tubular member is separated from the permeable longitudinal section of the first tubular member by a specific longitudinal distance. The specific longitudinal distance is calculated based on geometry, fluid, and sand properties of the wellbore environment. Also, the permeable longitudinal section of the second tubular member has a second plurality of openings between an internal region of the second tubular member and a region external to the second tubular member that allows particles having a particular size to pass therethrough. The system provides a flow path for hydrocarbons through the first tubular member.
In an alternative embodiment, a system associated with the production of hydrocarbons is described. The system includes a wellbore utilized to produce hydrocarbons from a subsurface reservoir, a production tubing string disposed within the wellbore, a perforated base pipe coupled to the production tubing string and disposed within the wellbore adjacent to the subsurface reservoir, and a tubular member at least partially enclosing the perforated base pipe. The perforated base pipe includes a non-permeable longitudinal section and a permeable longitudinal section, wherein the permeable longitudinal section has a plurality of slots between a central channel of the perforated base pipe and a region external to the perforated base pipe. The tubular member includes a non-permeable longitudinal section disposed adjacent to the permeable longitudinal section of the perforated base pipe and a permeable longitudinal section of the tubular member having a plurality of openings between an internal region of the tubular member and a region external to the tubular member that permits the passage of certain sized particles. Further, the permeable longitudinal section of the tubular member is disposed adjacent to the non-permeable longitudinal section of the perforated base pipe and the permeable longitudinal section of the tubular member is separated from the permeable longitudinal section of the perforated base pipe by a specific longitudinal distance, which is calculated based on geometry, fluid, and sand properties of the wellbore. The system further includes producing hydrocarbons from the perforated base pipe.
In another embodiment, a method associated with the production of hydrocarbons is described. The method includes measuring the geometry, fluid, and sand properties of a wellbore environment and calculating a specific longitudinal distance utilizing the measured properties. The method additionally includes providing a first tubular member, wherein the first tubular member comprises a non-permeable longitudinal section of the first tubular member and a permeable longitudinal section of the first tubular member that allows fluids to flow between a first central channel and a region external to the first tubular member; providing a second tubular member at least partially enclosing the first tubular member, wherein the second tubular member comprises a non-permeable longitudinal section of the second tubular member disposed adjacent to the permeable longitudinal section of the first tubular member and a permeable longitudinal section of the second tubular member that allows fluids and sand particles to flow between a second central channel and a region external to the second tubular member, and the permeable longitudinal section of the second tubular member; and disposing the non-permeable longitudinal section of the first tubular member adjacent to the permeable longitudinal section of the second tubular member, wherein the permeable longitudinal section of the first tubular member is separated from the permeable longitudinal section of the second tubular member by a specific longitudinal distance. Further, the method includes producing hydrocarbons from the first tubular member.
In an alternative embodiment, a system associated with the production of hydrocarbons is described. The system includes a first tubular member and a second tubular member at least partially enclosing the first tubular member. The first tubular member has a non-permeable longitudinal section and a permeable longitudinal section, wherein the permeable longitudinal section has a first plurality of openings between a first central channel and a region external to the first tubular member. The second tubular member includes a non-permeable longitudinal section in substantial radial alignment with the permeable longitudinal section of the first tubular member and a permeable longitudinal section, wherein the permeable longitudinal section of the second tubular member is in substantial radial alignment with the non-permeable longitudinal section of the first tubular member. Also, the permeable longitudinal section of the second tubular member has a second plurality of openings between an internal region of the second tubular member and a region external to the second tubular member that allows particles having a particular size to pass therethrough. Further, a plurality of axial partitions is disposed between the first and second tubular members to form a plurality of chambers therebetween. The system provides a flow path for hydrocarbons through the first tubular member.
The foregoing and other advantages of the present technique may become apparent upon reading the following detailed description and upon reference to the drawings in which:
In the following detailed description, the specific embodiments of the present invention are described in connection with its preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, it is intended to be illustrative only and merely provides a concise description of the exemplary embodiments. Accordingly, the invention is not limited to the specific embodiments described below, but rather; the invention includes all alternatives, modifications, and equivalents falling within the true scope of the appended claims.
The present technique describes a sand control device and method that may be utilized in a production system to enhance production of hydrocarbons from a well and/or enhance the injection of fluids or gases into the well. Under the present technique, a sand control device is configured to utilize “tortuous paths” and to promote the formation of sand bridges to plug relatively long linear channels, passages or compartments within a sand control device. Accordingly, when sand is produced, the sand bridges form to plugs sections of a well to block the flow of sand and water into the well from sand producing intervals or zones of the formation. While plugging is generally considered a problem in other sand control approaches, the present techniques promote plugging in a controlled manner for water producing intervals of the well. In fact, the plugging feature of present techniques may be used to plug off sand producing intervals (with or without water) protecting hydrocarbon production for other intervals within the well. Thus, the present techniques utilize compartments in the body of the device or relatively large compartments within the production casing to create sand bridges when water is produced.
Turning now to the drawings, and referring initially to
The floating production facility 102 is configured to monitor and produce hydrocarbons from the production intervals 108a-108n of the subsurface formation 107. The floating production facility 102 may be a floating vessel capable of managing the production of fluids, such as hydrocarbons, from subsea wells. These fluids may be stored on the floating production facility 102 and/or provided to tankers (not shown). To access the production intervals 108a-108n, the floating production facility 102 is coupled to a subsea tree 104 and control valve 110 via a control umbilical 112. The control umbilical 112 may be operatively connected to production tubing for providing hydrocarbons from the subsea tree 104 to the floating production facility 102, control tubing for hydraulic or electrical devices, and a control cable for communicating with other devices within the wellbore 114.
To access the production intervals 108a-108n, the wellbore 114 penetrates the sea floor 106 to a depth that interfaces with the production interval 108a-108n at different intervals within the wellbore 114. As may be appreciated, the production intervals 108a-108n, which may be referred to as production intervals 108, may include various layers or intervals of rock that may or may not include hydrocarbons and may be referred to as zones. The subsea tree 104, which is positioned over the wellbore 114 at the sea floor 106, provides an interface between devices within the wellbore 114 and the floating production facility 102. Accordingly, the subsea tree 104 may be coupled to a production tubing string 128 to provide fluid flow paths and a control cable (not shown) to provide communication paths, which may interface with the control umbilical 112 at the subsea tree 104.
Within the wellbore 114, the production system 100 may also include different equipment to provide access to the production intervals 108a-108n. For instance, a surface casing string 124 may be installed from the sea floor 106 to a location at a specific depth beneath the sea floor 106. Within the surface casing string 124, an intermediate or production casing string 126, which may extend down to a depth near the production interval 108, may be utilized to provide support for walls of the wellbore 114. The surface and production casing strings 124 and 126 may be cemented into a fixed position within the wellbore 114 to further stabilize the wellbore 114. Within the surface and production casing strings 124 and 126, a production tubing string 128 may be utilized to provide a flow path through the wellbore 114 for hydrocarbons and other fluids. Along this flow path, a subsurface safety valve 132 may be utilized to block the flow of fluids from the production tubing string 128 in the event of rupture or break above the subsurface safety valve 132. Further, packers 134a-134n may be utilized to isolate specific zones within the wellbore annulus from each other. The packers 134a-134n may include external casing packers, such as the SwellPacker™ (EZ Well Solutions) the MPas® Packer (Baker Oil Tools), or any other suitable packer for an open or cased hole well, as appropriate.
In addition to the above equipment, other devices or tools, such as sand control devices 138a-138n, may be utilized to manage the flow of particles into the production tubing string 128. The sand control devices 138a-138n, which may herein be referred to as sand control device(s) 138, may include slotted liners, stand-alone screens (SAS); pre-packed screens; wire-wrapped screens, membrane screens, expandable screens and/or wire-mesh screens. For exemplary purposes, the sand control devices 138 are herein described as being slotted basepipe with a perforated jacket, which is described further below in
As noted above, many wells have a number of completion intervals with the formation strength varying from interval to interval. Because the evaluation of formation strength is an uncertain science, the ability to predict the timing of the onset of sand and/or water is limited. Further, in many wells commingling of production intervals 108a-108n may be preferred to minimize investment risk and maximize economic benefit, which is particularly true for intervals with marginal reserves. A major risk in these applications is that sand failure and/or water breakthrough in any one interval threatens the remaining reserves in the well.
To address these concerns various sand and water control methods are commonly used. For instance, typical sand control methods include stand alone screens (also known as natural sand packs), gravel packs, frac packs and expandable screens. These methods limit sand production without increasing resistance to produced fluids, such as hydrocarbons. By themselves these sand control methods generally do not limit water production. Further, typical excess water control methods include cement squeezes, bridge plugs, straddle packer assemblies, and/or expandable tubulars and patches. In addition, some other wells may include chemical isolation methods, such as selective stimulation, relative permeability modifiers, gel treatments, and/or resin treatments. These methods are generally expensive, and utilize high risk interventions after the onset of water production.
Despite the variety of other methods utilized, available technology for controlling combined sand and water production is generally complex and expensive. Indeed, the high cost of conventional sand control, remote control technologies and intervention costs that are utilized to manage sand and water problems often drives cost for marginal projects beyond the economic limit for a given well or field. As such, a simple lower cost alternative is beneficial to lower the economic threshold for marginal reserves and to enhance the economic return for certain larger reserve applications. Accordingly, an exemplary sand control device 138 is shown in greater detail in
To begin,
To provide sand control, these slots 210 prevent or restrict the flow of particles, such as sand, from passing between the external region of the base pipe 202 and the central channel 208, as discussed below in greater detail. The slots 210 may be configured to prevent certain sized particles, such as sand, from passing between the central channel 208 and a region external to the base pipe 202. For instance, the slots 210 may be defined according to “Inflow Analysis and Optimization of Slotted Liners” and “Performance of Horizontal Wells Completed with Slotted Liners and Perforations.” See T. M. V. Kaiser et al., “Inflow Analysis and Optimization of Slotted Liners,” SPE 80145 (2002); and Yula Tang et al., “Performance of Horizontal Wells Completed with Slotted Liners and Perforations,” SPE 65516 (2000). It should also be noted that the sand control layer on base pipe 206 may be wire wrapped screen and/or mesh type screens instead of slots in other embodiments.
Further, as part of this configuration, the slots 210 may be positioned in groups along different longitudinal sections or portions of the base pipe 202. That is, the sections of the base pipe having the slots 210 may be referred to as permeable longitudinal sections 212a-212c, while the closed or non-slotted sections of the base pipe 202 may be referred to as non-permeable longitudinal sections 214a-214b. The distribution of these sections 212a-212c and 214a-214b may be varied to provide different flow paths into the central opening or channel 208, which is discussed further below.
Similar to the base pipe 202, the perforations 218 may be positioned in groups along different portions of the outer jacket 206. That is, sections of the outer jacket 206 having the perforations 218 may be referred to as permeable longitudinal sections 220a-220b, while the non-perforated sections of the outer jacket 206 may be referred to as non-permeable longitudinal sections 222a-222c. The distribution of these sections 220a-220b and 222a-222c may be varied to provide different flow paths into the central opening 216, which is discussed further below.
As discussed above, the sections 220a-220b and 222a-222c of the outer jacket 206 may be longitudinally aligned with specific sections 212a-212c and 214a-214b of the base pipe 202. For instance, permeable longitudinal sections 220a-220b of the outer jacket 206 may be aligned with the non-permeable longitudinal sections 214a-214b of the base pipe 202. Similarly, the non-permeable longitudinal sections 222a-222c of the outer jacket 206 may be aligned with the permeable longitudinal sections 212a-212c of the base pipe 202. In this configuration, the perforations 218 in the outer jacket 206 and slots 210 in the base pipe 202 may be offset by a specific distance, which may be referred to as a specific longitudinal distance, to divert the radial flow path through the openings 216 to a linear flow path along the axis of the base pipe 202 between the axial rods 204a-204h to the slots 210. At the slots 210, the flow is again diverted to a radial flow path through the slots 210 into the central channel 208. The distance of the linear flow path between the perforations 218 and the slots 210 (i.e. the “specific longitudinal distance”) is designed to provide the desired degree of plugging and isolation for the sand control device 138, which is discussed further below.
Beneficially, by providing slots 210 and perforations 218 in specific sections of the base pipe 202 and outer jacket 206, the flow paths may be relatively long to ensure the channels formed between the base pipe 202, axial rods 204a-204h and outer jacket 206 plug when sand is produced from the production interval. Unlike other approaches that use tortuous flow path concepts to increase erosion resistance of primary sand control devices and to manage pressure drop across completions for balancing flow profiles, the present embodiment uses longer linear flow paths to plug the compartment, not short flow paths, which may not plug the sand control device to prevent or restrict the flow of fluids. Accordingly, the tortuous flow path created by the distance separating the slots 210 and perforations 218 are utilized to plug off flow and associated water production to protect the remaining intervals in the well. That is, the perforations 218 of the outer jacket 206 are simply utilized to divert flow, while the slots 210 are the sand control device that blocks sand. As such, the present embodiment utilized the tortuous flow path to provide a mechanism that creates sand bridges to plug the flow path into the slots 210.
In addition, the present embodiment provides an automated mechanism for managing a sand control device without user intervention, high cost, risky intervention or without relying on expensive sensors to determine the conditions within the wellbore. As noted above, other approaches utilize mechanical and chemical techniques that rely upon user intervention to re-enter the wellbore, to actuate pre-installed downhole devices, to install shut off devices (plugs, patches etc) and/or to pump some chemical to block off the unwanted water producing interval. These active devices are complex and expensive to implement. However, the present embodiment is a passive shut-off device. In fact, the base pipe 202, axial rods 204a-204h and outer jacket 206 in this embodiment do not even have moving parts. As such, the plugging of the interval of the wellbore adjacent to the sand control device is automatically performed without user intervention.
As an example,
However, when sand is produced, a sand bridge 306 forms to block the fluid flow path 302 into the compartment 300, as shown in
The distance 305 is calculated based on the geometry, fluid properties and sand properties of the well using common models for fluid flow in porous media. In particular, the distance 305 is calculated to achieve a target pressure drop at a given flow rate and provide sufficient resistance to fluid flow once the compartment is at least partially filled with sand. The calculation may be based on commonly used models/equations for fluid flow in porous media. Some of the specific parameters that may be utilized in determining the distance 305 may include the cross sectional flow area of the chamber, the permeability of the plugging material (i.e. the sand filling the chamber) and fluid properties (i.e. viscosity). These properties may be known values or may be theoretical properties derived from experience, experimentation, data from related well sites, and other sources.
A further advantageous aspect of the present techniques is shown in
Furthermore, sand control device may provide enhancements to a multi-zone reservoir or formation, such as subsurface formation 107. For example, a subsurface formation 107 may include multiple production zones or intervals 108a-108n that produce sand free for some period of time. These intervals may be isolated or commingled with other production intervals within the well. Typically, after a certain amount of depletion/drawdown or with the onset of water production from different production intervals, premature water breakthrough and/or sand failure may threaten the other production intervals of the well. However, with the present sand control devices, sand failure in a specific interval may plug off as the linear flow channels through and adjacent to the sand control device fill with sand and plug. As a result, any producing production intervals may continue to provide hydrocarbons, while the sand control devices 138a-138n may block the flow of sand and water from depleted production intervals 108a-108n. Accordingly, the use of the exemplary sand control devices with multiple production intervals within a well is shown in greater
In
Similar to the discussion above, the openings in the sand control devices 502a-502b may be located a sufficient distance 505a-505b across the respective production interval 504a-504b. However, in this configuration, the annulus between the production casing string 126 and the basepipes 512a-512b is utilized as the longer linear flow paths to plug the compartment of the annulus to prevent flow. For instance, fluid flow paths, such as fluid flow path 514, may be formed to allow fluids to flow from the production intervals 504a-504b into the production tubing string 128. As the fluid flows from the production intervals 504a-504b through the cement 516 and respective perforations 518a-518b into the production tubing string 128 for each of the compartments, a longitudinal distance 505a-505b separates the perforations 518a-518b from the sand screens 510a-510b to cause the fluid pressure to drop along the flow path 514. Accordingly, a sand bridge may form adjacent to the one of the sand control devices 502a-502b because of the pressure drop of fluid flowing through the perforations 518a-518b and the annulus between the sand control device 502a-502b and the production casing string 126. This sand bridge may effectively restrict the flow of fluids from the sand producing production interval. In particular, the formation of a sand bridge 517 adjacent to the sand control device 502a blocks fluid flow from the production interval 504a into the production tubing string 128. However, the flow of fluids from the production interval 504b may continue to produce fluids through the sand control device 502b.
Similar to the discussion above, the openings in the sand control devices 502a and 502b may be located a sufficient distance 605a-605b above the respective production interval 604a-604b. Open-hole packers 602a-602b may be disposed between production intervals 604a-604b to isolate different zones. However, in this configuration, the annulus formed between the walls of the wellbore 600 and the basepipes 512a-512b is utilized as the linear flow paths to plug the compartment of the annulus to prevent flow. For instance, fluid flow paths, such as fluid flow path 608, may be formed to allow fluids to flow from the production intervals 604a-604b into the production tubing string 128. As the fluid flows from the production intervals 604a-604b through the annulus into the production tubing string 128 for each of the compartments, a longitudinal distance 605a-605b separates the production intervals 604a-604b from the sand screens 510a-510b to cause the fluid pressure to drop along the flow path 608. Accordingly, a sand bridge may form adjacent to the one of the sand control devices 502a and/or 502b because of the pressure drop of fluid flowing from the production intervals 604a and 604b in the annulus between the sand control device 502a-502b and walls of the wellbore 600. This sand bridge may effectively restrict the flow of fluids from the sand producing production interval. In particular, the formation of a sand bridge 610 adjacent to the sand control device 502a blocks fluid flow from the production interval 604a into the production tubing string 128. However, the flow of fluids from the production interval 604b may continue to produce fluids through the sand control device 502b.
Beneficially, the various combinations of these sand control devices 138a-138n and 502a-502b in
The present techniques also encompass the placement of a tubular member over a previously disposed basepipe. For example, some wells may already have a perforated basepipe disposed in them to allow production fluid coming into the well, but lack a concentric pipe or tubular member to plug off unwanted fluid coming into the wellbore. These wells may not have produced sand and water at the time the basepipe was originally placed, but have begun to produce sand and water or are likely to begin producing such byproducts. In a case such as this, an operator may position a perforated tubular member inside the original basepipe at certain intervals determined to inhibit the production of sand and water through the basepipe. The size and placement of the openings along the pipe's length could be calculated based on measured properties of the wellbore environment.
It should be noted that any number of compartments may be formed within production intervals. For instance, as shown in
Further, as another variation on the embodiments described above, it should be appreciated that the sand screens 510a-510b in
While the present techniques of the invention may be susceptible to various modifications and alternative forms, the exemplary embodiments discussed above have been shown by way of example. However, it should again be understood that the invention is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present techniques of the invention are to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the following appended claims.
This application claims the benefit of U.S. Provisional Application No. 60/751,676, filed 19 Dec. 2005.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/US2006/039878 | 10/12/2006 | WO | 00 | 5/19/2008 |
| Number | Date | Country | |
|---|---|---|---|
| 60751676 | Dec 2005 | US |
