Patent Application
20070039741
This invention relates generally to oil well completion and, in particular, to a sand control screen assembly enhanced with disappearing sleeve and burst disc.
It is well known in the field of subterranean well drilling and completion that relatively fine particulate materials may be produced during the production of hydrocarbons from a well that traverses an unconsolidated or loosely consolidated formation. Numerous problems may occur as a result of the production of such particulate. For example, the particulate causes abrasive wear to components within the well, such as tubing, pumps and valves. In addition, the particulate may partially or fully clog the well creating the need for an expensive workover. Also, if the particulate matter is produced to the surface, it must be removed from the hydrocarbon fluids using surface processing equipment.
One method for preventing the production of such particulate material is to gravel pack the well adjacent to the unconsolidated or loosely consolidated production interval. In a typical gravel pack completion, a sand control screen is lowered into the wellbore on a work string to a position proximate the desired production interval. A fluid slurry including a liquid carrier and a relatively coarse particulate material, such as sand, gravel or proppants which are typically sized and graded, is then pumped down the work string and into the well annulus formed between the sand control screen and the perforated well casing or open hole production zone.
The liquid carrier either flows into the formation, returns to the surface by flowing through a wash pipe, or both. In either case, the gravel is deposited around the sand control screen to form the gravel pack, which is highly permeable to the flow of hydrocarbon fluids but blocks the flow of the fine particulate materials carried in the hydrocarbon fluids. As such, gravel packs can successfully prevent the problems associated with the production of these particulate materials from the formation.
In other cases, it may be desirable to stimulate the formation by, for example, performing a formation fracturing and propping operation prior to or simultaneously with the gravel packing operation. Hydraulic fracturing of a hydrocarbon formation is sometimes necessary to increase the permeability of the formation adjacent the wellbore. According to conventional practice, a fracture fluid such as water, oil, oil/water emulsion, gelled water or gelled oil is pumped down the work string with sufficient volume and pressure to open multiple fractures in the production interval. The fracture fluid may carry a suitable propping agent, such as sand, gravel or proppants, into the fractures for the purpose of holding the fractures open following the fracturing operation.
It has been found, however, that following formation treatment operations, the fluid inside the sand control screen tends to leak off into the adjacent formation. This leak off not only results in the loss of the relatively expensive fluid into the formation, but may also result in damage to the gravel pack around the sand control screen and damage to the formation. This fluid leak off is particularly problematic in cases where multiple production intervals within a single wellbore require treatment as the fluid remains in communication with the various formations for an extended period of time.
Existing sand control devices may be expensive and complex tools that must be fit into the relatively restrictive geometry inside a wellbore. The complexity of the tools may make them unreliable. Furthermore, the sizes of the tools (smaller inner diameter for given outer diameter, or larger outer diameter for given inner diameter) may make them undesirable for various applications, such as having an inner diameter that is too small to allow service tools or concentric production equipment to be run inside the screen, or an outer diameter to large to allow effective placement of gravel or frac packs around the device.
In accordance with the teachings of the present invention, disadvantages and problems associated with managing fluid leak off during completion operations in a production interval of a wellbore have been substantially reduced or eliminated. In particular, the system and method described herein prevent undesirable fluid leak off during wellbore completion while improving the hydrocarbon production rate from the production interval during production.
In accordance with one embodiment of the present invention, a sand control screen assembly for use in a wellbore includes a tubular base pipe having a first perforated section. The first perforated section has at least a first opening that allows fluid flow therethrough. The assembly also includes an internal seal element disposed within an internal diameter of the tubular base pipe and positioned at least partially overlapping the first perforated section. The internal seal element is able to control fluid flow through the first opening. The internal seal element includes a first material that is dissolvable by a first solvent, and may be dissolved by exposing the internal seal element to the first solvent until the internal seal element no longer controls fluid flow through the first opening.
In particular embodiments, the tubular base pipe may have a second perforated section with at least a second opening. The assembly may also include a degradable plug disposed so as to prevent fluid flow through the second opening. The degradable plug may include a second material that is dissolvable by a second solvent, and the degradable plug may be dissolved by exposing the degradable plug to the second solvent until the degradable plug no longer prevents fluid flow through the second opening. In another embodiment, the internal seal element may include at least one longitudinal slit. The longitudinal slit allows fluid flow through the first opening from the exterior to the interior of the tubular base pipe when an exterior fluid pressure outside of the base pipe is sufficiently higher than an interior fluid pressure inside of the base pipe to deform the internal seal element radially inwards and allow fluid flow through the longitudinal slit.
In accordance with another embodiment of the present invention, a sand control screen assembly for use in a wellbore includes a tubular base pipe having a first perforated section with at least a first opening that allows fluid flow therethrough. The assembly also includes a degradable plug disposed so as to prevent fluid flow through the first opening. The degradable plug includes a first material that is dissolvable by a first solvent and the degradable plug may be dissolved by exposing the degradable plug to the first solvent until the degradable plug no longer prevents fluid flow through the first opening.
Technical advantages of certain embodiments of the present invention include a sand control screen assembly and a treatment method that prevent fluid loss into the formation(s) during the completion process and allow for the production of fluids from the formation(s) following the completion process. An internal seal element may prevent treatment fluids from leaking into the formation while other production intervals are being completed or until production is begun. During production, the internal seal element may be radially deformed, thereby allowing production fluids to flow from the exterior of the assembly to the interior.
Another technical advantage of particular embodiments of the present invention may include the ability to increase the rate of production from the production interval by selectively degrading the internal seal element and one or more of a plurality of degradable plugs. The internal seal element and degradable plugs may degrade as a consequence of production, or they may be degraded by solvents which are pumped down the wellbore for the purpose of degrading the internal seal element and degradable plugs. The materials used to fabricate the internal seal element and the degradable plugs will determine the solvent used to degrade them. The internal seal element and degradable plugs may be made from materials that dissolve in the presence of hydrocarbons or water.
An additional technical advantage of particular embodiments of the present invention may include the ability to degrade the internal seal element or degradable plugs at a desired time and rate. One or more burst discs or rupture discs may be incorporated into the assembly. If the rate of production is lower than desired, the pressure in the wellbore may be increased to rupture the discs. The new openings may be used to increase production, or may be used to circulate a solvent over the internal seal element and/or degradable plugs to dissolve them and thereby increase the production rate.
Other technical advantages of the present invention will be readily apparent to one skilled in the art from the following figures, descriptions, and claims. Moreover, while specific advantages have been enumerated above, various embodiments may include all, some, or none of the enumerated advantages.
To provide a more complete understanding of the present invention and the features and advantages thereof, reference is made to the following description, taken in conjunction with the accompanying drawings, in which:
While the making and using of various embodiments of the present invention are discussed in detail below, it should be appreciated that the present invention provides many applicable inventive concepts which can be embodied in a wide variety of specific contexts. The specific embodiments discussed herein are merely illustrative of specific ways to make and use the invention, and do not delimit the scope of the present invention.
Referring initially to
A wellbore 34 extends through the various earth strata including formations 14, 16. A casing 36 is cemented within wellbore 34 by cement 38. Work string 32 includes sand control screen assemblies 40, 42. Sand control screen 40 is positioned within production interval 44 between packers 46, 48 adjacent to formation 14. Sand control screen assembly 42 is positioned within production interval 50 between packers 52, 54 adjacent to formation 16. Once sand control screen assemblies 40, 42 have been installed as illustrated, a treatment fluid containing sand, gravel, proppants or the like may be pumped down work string 32 to treat production intervals 44, 50 and formations 14, 16, as described in greater detail below with reference to
Although
Spaced around base pipe 62 are a plurality of ribs 72. Ribs 72 are generally symmetrically distributed about the axis of base pipe 62. Ribs 72 are depicted as cylindrical rods, however, ribs 72 may have a rectangular or triangular cross section or have any other suitable geometry. Additionally, the exact number and arrangement of ribs 72 is not limited to the number and arrangement illustrated and will vary depending upon the diameter of base pipe 62 as well as other design characteristics that are well known in the art.
Wrapped around ribs 72 is a screen wire 74. Screen wire 74 forms a plurality of turns, such as turn 76 and turn 78. Between each of the turns is a gap through which formation fluids may flow. The number of turns and the gap between the turns are determined based upon the characteristics of the formation from which fluid is being produced and the size of the gravel to be used during the gravel packing operation. Together, ribs 72 and screen wire 74 may form a sand control screen jacket that is attached to base pipe 62 by welding or other suitable technique.
Although
Positioned within perforated section 66 of base pipe 62 is an internal seal element 80 that prevents fluid flow from the interior to the exterior of sand control screen assembly 60. In particular embodiments, internal seal element 80 may be formed from an elastomer such as a natural or synthetic rubber or other suitable polymer such as a high polymer having the ability to partially or completely recover to its original shape after deforming forces are removed. In other embodiments, internal seal element 80 may be formed from a degradable or dissolvable (collectively “dissolvable”) material such as polylactic acid (PLA); a pliable water, oil, or gas soluble resin; or any other suitable dissolvable material. In alternative embodiments, internal seal element 80 may be constructed from any material or have any configuration that allows internal seal element 80 to prevent fluid flow from the interior to the exterior of sand control screen assembly 60 when the pressure inside of sand control screen assembly 60 is greater than the pressure outside of sand control screen assembly 60 and to allow fluid flow from the exterior to the interior of sand control screen assembly 60 when the differential pressure across internal seal element 80 from the exterior to the interior of sand control screen assembly 60 exceeds a predetermined level.
With internal seal element 80 positioned within base pipe 62 during a treatment process, such as a gravel pack, a frac pack or a fracture operation, treatment fluid returns may flow into the interior of sand control screen assembly 60 by deforming internal seal element 80 radially inward away from sealing engagement with the interior of base pipe 62 and openings 68. Also, with internal seal element 80 positioned within base pipe 62 following a treatment process, fluids in the wellbore are prevented from flowing out of sand control screen assembly 60 by deforming internal seal element 80 radially outward into sealing engagement with the interior of base pipe 62 and openings 68.
During production with internal seal element 80 positioned within base pipe 62, production fluids may flow into sand control screen assembly 60 by deforming internal seal element 80 radially inward away from sealing engagement with the interior of base pipe 62 and openings 68. In particular embodiments, the flow of production fluids around internal seal element 80 will dissolve internal seal element 80 until internal seal element 80 can no longer engage the interior of base pipe 62 to seal openings 68. A dissolvable internal seal element 80 may prevent treatment fluids from leaking from the interior of sand control screen assembly 60 during completion or treatment of the wellbore and may dissolve prior to or during production so as not to hamper or decrease the flow rate of the production fluids through openings 68.
Positioned within base pipe 92 is an internal seal element 104 that prevents fluid flow from the interior to the exterior of sand control screen assembly 90 during completion and treatment of a production interval (not illustrated) adjacent sand control screen assembly 90. In the illustrated embodiment, a flared portion 106 of internal seal element 104 is securably mounted within a receiving profile 108 on the interior of blank pipe section 94 of base pipe 92. An adhesive or other suitable bonding agent or method may be used to secure flared portion 106 of internal seal element 104 within receiving profile 108.
A sealing portion 110 of internal seal element 104 is not adhered to base pipe 92 and is radially inwardly deformable away from sealing engagement with the interior of base pipe 92 and openings 98 to allow fluid flow from the exterior to the interior of sand control screen assembly 90. Accordingly, internal seal element 104 allows for treatment fluid returns during a treatment process and for fluid production once the well is online. In addition, internal seal element 104 prevents fluid loss into the formation after the treatment process but before the well is brought online as the fluids within sand control screen assembly 90 deform sealing portion 110 of internal seal element 104 radially outward into sealing engagement with the interior of perforated section 96 of base pipe 92, thereby sealing openings 98.
In the embodiment illustrated in
The material which internal seal element 104 is formed from will at least partially determine when internal seal element 104 will begin dissolving. Therefore, the material used to form internal seal element 104 may be selected based on a desired life of internal seal element 104. In certain embodiments, the desired life of internal seal element 104 may be approximately one week and internal seal element 104 may comprise polylactic acid that is dissolvable by free water molecules in the surrounding fluid. In another embodiment, internal seal element 104 may comprise an oil-soluble or gas-soluble resin and internal seal element 104 may maintain its check valve functionality until the onset of hydrocarbon production. The presence of internal seal element 104 may result in a decreased flow rate of production fluids through openings 98 because the production fluids need to deform and flow around internal seal element 104. Dissolving internal seal element 104 after completion of the well will result a higher flow rate of the production fluids during production.
In certain embodiments, the material of internal seal element 104 may be dissolved by production fluids such as oil, gas, water, or other fluid present in the formation. Once production has commenced, the fluids being produced will flow around internal seal element 104 thereby dissolving internal seal element 104.
Alternatively, internal seal element 104 may be selectively dissolvable by a fluid or treatment agent other than a production fluid. In this embodiment, a dissolving agent, or solvent, may be pumped downhole from the surface to circulate around and dissolve internal seal element 104. This step may be performed after well completion and before production starts, or it may be completed after production has commenced to increase the flow rate of the production fluids. In particular embodiments, water is not produced from a formation and may be used to selectively dissolve internal seal element 104.
Positioned within base pipe 122 is an internal seal element 138 that prevents fluid flow from the interior to the exterior of the sand control screen assembly 120. In the illustrated embodiment, a first flared portion 134 of internal seal element 138 is securably mounted within a first receiving profile 135 on the interior of base pipe 122. A second flared portion 136 of internal seal element 138 is securably mounted within a second receiving profile 137 on the interior of base pipe 122. An adhesive or other suitable bonding agent or method may be used to secure first and second flared portions 134, 136 of internal seal element 138 within first and second receiving profiles 135, 137. Internal seal element 138 is also illustrated with a plurality of longitudinal slits 140.
In operation, a middle section of internal seal element 138 between first flared portion 134 and second flared portion 136 is deformable radially inward away from sealing engagement with the interior of perforated section 126 of base pipe 122. When internal seal element 138 is inwardly deformed, slits 140 open and widen to allow fluid flow through openings 128 from the exterior to the interior of sand control screen assembly 120. Internal seal element 138 thereby allows for treatment fluid returns during a treatment process and for fluid production once the well is online. Internal seal element 138 also prevents fluid loss into the formation after the treatment process but before the well is brought online as the fluids within sand control screen assembly 120 deform internal seal element 138 radially outward, thereby closing slits 140 and sealing openings 128.
In particular embodiments, internal seal element 138 may be formed from a dissolvable material such as PLA; pliable water, oil, or gas soluble resin; or any other suitable dissolvable material. In this embodiment, internal seal element 138 may be dissolved in any of the manners discussed above regarding internal seal element 104. Alternatively, internal seal element 138 may be formed from a robust material such as a natural or synthetic rubber or other suitable polymer such as a high polymer having the ability to partially or completely recover to its original shape after deforming forces are removed. In a particular embodiment, internal seal element 138 may be formed from nitrile rubber.
Positioned within base pipe 152 is an internal seal element 168 that prevents fluid flow from the interior to the exterior of the sand control screen assembly 150. Internal seal element 168 may be similar to any of internal seal elements 80, 104, or 138 discussed above. Therefore, internal seal element 168 may be made of a robust or dissolvable material, may or may not include slits (slits not illustrated), and may be anchored to base pipe 152 on one or both sides of internal seal element 168 (only one side is anchored in the illustration).
In operation, internal seal element 168 may operate as described above. Additionally, degradable plugs 157 may be degraded or dissolved (collectively “dissolved”) after well completion or during production to allow fluid flow through openings 155. Degradable plugs 157 may be formed from a dissolvable material such as PLA; pliable water, oil, or gas soluble resin; or any other suitable dissolvable material. Degradable plugs 157 may be dissolved by exposing degradable plugs 157 to a solvent capable of dissolving the material of degradable plugs 157. Exposing degradable plugs 157 to a solvent may include, but is not limited to, circulating the solvent around degradable plugs 157, allowing the solvent to remain in contact with degradable plugs 157 for a length of time, or, when the solvent is a production fluid, by beginning or continuing production.
The material which degradable plugs 157 are formed from will at least partially determine when degradable plugs 157 will begin dissolving, and the material may be selected based on a desired life of degradable plugs 157. In certain embodiments the desired life of degradable plugs 157 may be approximately three weeks. In particular embodiments, the material of degradable plugs 157 may be dissolved by production fluids such as oil, gas, water, or other fluids present in the formation. Once production has commenced, the fluids being produced will flow around degradable plugs 157 thereby dissolving degradable plugs 157. Dissolving degradable plugs 157 after completion of the well will result a higher flow rate of the production fluids during production as the area for fluid flow is increased.
Alternatively, degradable plugs 157 may be selectively dissolvable by a fluid or treatment agent other than a production fluid. In this embodiment, a dissolving agent may be pumped downhole from the surface to circulate around and dissolve degradable plugs 157. This step may be performed after well completion and before production starts, or it may be completed after production has commenced to increase the flow rate of the production fluids. In particular embodiments, water is not produced from a formation and may be used to selectively dissolve degradable plugs 157.
When degradable plugs 157 are used in conjunction with internal seal element 168 formed from a dissolvable material, the degradable plugs 157 and the material used to form internal seal element 168 may be the same material or a different material. Choosing the same or different material for degradable plugs 157 and internal seal element 168 may result in degradable plugs 157 and internal seal element 168 being dissolvable by the same or different solvents. If degradable plugs 157 and internal seal element 168 are dissolvable by different solvents, one or the other of degradable plugs 157 and internal seal element 168 may be selectively dissolved before the other. The ability to dissolve one of degradable plugs 157 or internal seal element 168 before dissolving the other may allow for greater adjustability of the flow rate of production fluids during production. Even when degradable plugs 157 and internal seal element 168 are formed from the same material, the design of degradable plugs 157 and internal seal element 168 may be such that one dissolves more rapidly than the other, thereby providing a gradual increase in the area available for flow of production fluids.
While a particular number and arrangement of openings 155 and degradable plugs 157 has been illustrated in
Positioned within base pipe 171 is an internal seal element 183 that prevents fluid flow from the interior to the exterior of the sand control screen assembly 170. Internal seal element 183 may be similar to any of internal seal elements 80, 104, 138, or 168 discussed above. Therefore, internal seal element 183 may be made of a robust or dissolvable material, may or may not include slits (slits not illustrated), and may be anchored to base pipe 171 on one or both sides of internal seal element 183 (only one side is anchored in the illustration). Likewise, degradable plugs 176 and openings 175 may be similar to degradable plugs 157 and openings 155 described above.
In operation, internal seal element 183 and degradable plugs 176 may operate in a similar manner to those described above. Additionally, rupture disc 179 may be ruptured by increasing a pressure within base pipe 171 above a threshold rupture pressure of rupture disc 179. The threshold rupture pressure of rupture disc 179 may be chosen such that rupture disc 179 will rupture at a desired and predetermined pressure. When rupture disc 179 ruptures, fluid flow is established through opening 178. Initially, following rupture, the pressure within sand control screen assembly 170 will be greater than the pressure outside of sand control screen assembly 170. This may result in fluid flow through opening 178 from the interior to the exterior of sand control screen assembly 170. The differential pressure between the interior and exterior of sand control screen assembly 170 may be significant and may result in a high rate of fluid flow under great force through opening 178. Blank pipe section 182 may optionally be arranged, as illustrated, adjacent opening 178 to redirect the fluid flow out of opening 178 and thereby reduce the likelihood of damage to sand control screenjacket 180.
Rupture disc 179 may be ruptured for a variety of reasons. Opening 178 will increase the area for fluid flow and therefore rupture disc 179 may be ruptured to increase the flow rate of production fluids. Rupturing disc 179 may also allow a solvent (or solvents) to be circulated around degradable plugs 176 and internal seal element 183. This may be desirable when degradable plugs 176 or internal seal element 183 are not dissolving as quickly as desired or when degradable plugs 176 or internal seal element 183 are not dissolvable by production fluids and an increased flow rate is desired. In the example illustrated, rupture disc 179 is located at the opposite end of base pipe 171 from openings 177 such that a solvent flowing through opening 178 will be circulated past degradable plugs 176 and internal seal element 183. Furthermore, rupture disc 179 may be ruptured to further fracture the formation or provide greater treatment of the formation.
While one opening 178 and rupture disc 179 has been illustrated in
Referring now to
To begin the completion process, production interval 44 adjacent to formation 14 is isolated. Packer 46 seals the near or uphole end of production interval 44 and packer 48 seals the far or downhole end of production interval 44. Likewise, production interval 50 adjacent to formation 16 is isolated. Packer 52 seals the near end of production interval 50 and packer 54 seals the far end of production interval 50. Work string 32 includes cross-over ports 186, 188 that provide a fluid communication path from the interior of work string 32 to production intervals 44, 50, respectively. Preferably, fluid flow through cross-over ports 186, 188 is controlled by suitable valves that are opened and closed by conventional means. Service tool 184 includes a cross-over assembly 190 and a wash pipe 192.
Next, the desired treatment process may be performed. As an example, when the treatment process is a fracture operation, the objective is to enhance the permeability of the treated formation by delivering a fluid slurry containing proppants at a high flow rate and in a large volume above the fracture gradient of the formation such that fractures may be formed within the formation and held open by proppants. In addition, if the treatment process is a frac pack, after fracturing, the objective is to prevent the production of fines by packing the production interval with proppants. Similarly, if the treatment process is a gravel pack, the objective is to prevent the production of fines by packing the production interval with gravel, without fracturing the adjacent formation.
The following example will describe the operation of the present invention during a gravel pack operation. Sand control screen assemblies 40, 42 each have a filter medium associated therewith that is designed to allow fluid to flow therethrough but prevent particulate matter of a sufficient size from flowing therethrough. During the gravel pack, a treatment fluid, in this case a fluid slurry containing gravel 194, is pumped downhole in service tool 184, as indicated by arrows 196, and into production interval 44 via cross-over assembly 190, as indicated by arrows 198. As the fluid slurry containing gravel 194 travels to the far end of production interval 44, gravel 194 drops out of the slurry and builds up, filling the perforations and production interval 44 around sand control screen assembly 40 and forming gravel pack 194A. While some of the carrier fluid in the slurry may leak off into formation 14, the remainder of the carrier fluid enters sand control screen assembly 40, as indicated by arrows 200 and radially inwardly deforms internal seal element 185 to enter the interior of sand control screen assembly 40, as indicated by arrows 202. The fluid flowing back through sand control screen assembly 40, as indicated by arrows 204, enters wash pipe 192, as indicated by arrows 206, passes through cross-over assembly 190 and flows back to the surface, as indicated by arrows 208.
After the gravel packing operation of production interval 44 is complete, service tool 184 including cross-over assembly 190 and wash pipe 192 may be moved uphole such that other production intervals may be gravel packed, such as production interval 50, as best seen in
Referring now to
As should be apparent to those skilled in the art, even though
Some or all of the embodiments of the present invention may enable injection for formation treatment (planned or unplanned), reservoir pressure maintenance, or other purpose after the completion has been installed, while still preventing fluid loss during the completion. This control of fluid loss during completion operations may simplify designs for other production tools (e.g., may eliminate the need for isolation ball valves and their associated shifting tools) or service tools (e.g., service tool string used for multiple zone completions). Certain embodiments of the present invention may be used in wells with concentric, or “smart” concentric strings for managing production/injection flow that are to be installed inside the sand screens across the production interval(s). Certain embodiments of the present invention may also be used in multiple zone wells without concentric strings and allow simplification of the completion process at lower cost. Embodiments of the present invention could also have potential applicability to any sand-controlled well and may provide cost savings over alternative sand control devices.
Although the present invention has been described with several embodiments, a myriad of changes, variations, alterations, transformations, and modifications may be suggested to one skilled in the art, and it is intended that the present invention encompass such changes, variations, alterations, transformations, and modifications as fall within the scope of the appended claims.
