Patent Application
20120168175
To form a borehole in a formation, a drilling assembly (also referred to as the “bottom hole assembly” or the “BHA”) carrying a drill bit at its bottom end is conveyed downhole. The borehole may be used to store fluids, such as CO2 sequestration, in the formation or obtain fluids, such as hydrocarbons or water, from one or more production zones in the formation. Several techniques may be employed to stimulate hydrocarbon production. For example, a plurality of boreholes (also “wellbores” or “wells”), such as a first and second borehole, may be formed in a formation. The first borehole is an injection borehole and the second borehole is a production borehole. A flow of pressurized fluids from the first borehole cause flow of formation fluids to the production borehole. Specifically, the fluid is flowed downhole within a tubular disposed in the first or injection borehole. One or more flow control apparatus, such as a valve, is located in the tubular to control the pressurized fluid flow into the formation. The pressurized fluid then causes an increased pressure within the formation resulting in flow of formation fluid into a producing string located in the second borehole. A surface fluid source, such as a pump, provides the pressurized injection fluid to each flow control apparatus downhole.
If the fluid source shuts down or malfunctions, a pressure differential occurs between the formation zone receiving the injected fluid and the fluid inside the tubular. Specifically, a pressure caused by injecting fluid into a zone of the formation is significantly higher than the hydrostatic pressure within the tubular. Communication of fluid across the pressure differential can cause crossflow from the high pressure zone to other lower pressure zones in the formation. The flow from the high pressure zone can cause flow of sand and debris into the tubular and lower pressure zones, inhibiting flow paths and causing damage to the tubular string. In addition flow of fluid from high pressure zone can cause a high pressure wave or water hammer of fluid to propagate uphole in the tubular. The high pressure wave can damage equipment within the tubular string and at the surface.
Devices for flow control of injection fluid from the tubular to the formation zone are controlled from the surface. A control signal to close the device may take several minutes to communicate from the surface. Due to the delayed control signal, the device remains open after a pump shut down, leading to communication of the pressure differential (between the formation and tubular) and resulting cross flow and pressure wave.
In one aspect, a flow control apparatus for use in a borehole is provided. The apparatus includes a tubular body, a check valve sleeve and a check valve, wherein a change of a pressure inside the check valve sleeve causes the check valve to control fluid communication between the check valve sleeve and the borehole outside the tubular body.
In another aspect, a method for controlling fluid flow between a borehole and a tubular is provided, wherein the method includes directing a fluid downhole via a string to a tubular body. The method further includes increasing a first pressure of the fluid within the string, wherein increasing the first pressure to a selected level causes a check valve to move to an open position, wherein the selected level is greater than a second pressure of a borehole annulus outside the tubular. The method also includes directing the fluid from the string to the borehole annulus via the open check valve.
The disclosure herein is best understood with reference to the accompanying figures in which like numerals have generally been assigned to like elements and in which:
Referring initially to
The string 120 is shown to include a generally horizontal portion 132 that extends along the deviated leg or section 110b of the borehole 110. Injection assemblies 134 are positioned at selected locations along the string 120. Optionally, each injection assembly 134 may be isolated within the borehole 110 by a pair of packer devices 136. Although only two injection assemblies 134 are shown along the horizontal portion 132, a large number of such injection assemblies 134 may be arranged along the horizontal portion 132. Another injection assembly 134 is disposed in vertical section 110a to affect production from production zone 114. In addition, a packer 142 may be positioned near a heel 144 of the borehole 110, wherein element 146 refers to a toe of the borehole. Packer 142 isolates the horizontal portion 132, thereby enabling pressure manipulation to control fluid flow in borehole 110.
As depicted, each injection assembly 134 includes equipment configured to control fluid communication between a formation and a tubular, such as string 120. The exemplary injection assemblies 134 include one or more flow control apparatus or valves 138 to control flow of one or more injection fluids between the string 120 and production zones 114, 116. A fluid source 140 is located at the surface 126, wherein the fluid source 140 provides pressurized fluid via string 120 to the injection assemblies 134. Accordingly, each injection assembly 134 may provide fluid to one or more formation zone (114, 116) to induce formation fluid to flow to a second production string (not shown).
Injection fluids may include any suitable fluid used to cause a flow of formation fluid from formation zones (114, 116) to a production borehole and string. Further, injection fluids may include a fluid used to reduce or eliminate an impediment to fluid production, such as an acid. As used herein, the term “fluid” or “fluids” includes liquids, gases, hydrocarbons, multi-phase fluids, mixtures of two of more fluids, water and fluids injected from the surface, such as water and/or acid. Additionally, references to water should be construed to also include water-based fluids; e.g., brine, sea water or salt water.
In an embodiment, injection fluid, shown by arrow 142, flows from the surface 126 within string 120 (also referred to as “tubular” or “injection tubular”) to injection assemblies 134. Flow control apparatus 138 (also referred to as “injection devices” or “valves”) are positioned throughout the string 120 to distribute the fluid based on formation conditions and desired production. In one exemplary embodiment, the flow control apparatus 138 is configured to open to allow fluid to flow from tubular string 122 to borehole 110 when a fluid pressure inside the tubular string 122 reaches a first level or value. In addition, the flow control apparatus 138 is configured to close to shut off or restrict flow of the fluid from the tubular string 122 when the fluid pressure is lowered to a second level that is less than a pressure inside the borehole 110. Accordingly, the flow control apparatus 138 moves to a closed position shortly after a stoppage of pumping by the fluid source 140. The closed position prevents or restricts a pressure differential from being communicated between the tubular string 122 and borehole 110. Thus, flow of fluid from the production zone into the string 120 is restricted to reduce cross flow into other zones. As discussed in detail below, exemplary flow control apparatus 138 are controlled by a pressure level inside the tubular string 122, thereby improving performance of an injection process while reducing damage to equipment in the tubular string 122.
The depicted flow control apparatus 200 in a closed position, wherein the insert sleeve 204 and check valve are both in a closed position to restrict fluid communication between the flowbore 214 and a borehole annulus 232. Specifically, the insert sleeve 204 is positioned to block a passage 220 in the tubular body 202, wherein seals 223 restrict fluid flow inside the insert sleeve 204. In the closed position, a passage 222 in the insert sleeve 204 is not aligned with the passage 220. In addition, the check valve 206 blocks a passage 224 in the check valve sleeve 210. A seal 228 is located between the check valve 206 and check valve sleeve 208. The seal 228 restricts fluid flow between the flowbore 214 and outside the check valve sleeve 210. The flow control apparatus 200 may be in the closed position during run in or prior to production using an injection process. In the closed position, fluid communication is prevented or restricted between the flowbore 214 and the borehole annulus 232. The position of insert sleeve 204 is coupled to and controlled by a controller 230 via control lines. The controller 230 may be located in any suitable location, such as the surface 126 (
As discussed below, a fluid flow 304 provided by fluid source 140 (
In an exemplary embodiment, the locked open position enables fluid flow from the borehole annulus 232 to the flowbore 214 after an acid fluid has flowed into the borehole annulus 232 to break up debris impeding fluid flow into the formation. After acid injection, it is desirable to flow the acid and broken up debris to the surface to clean the borehole annulus 232, thereby enabling production to resume. Accordingly, the depicted locked open position allows fluid flow from the borehole annulus 232 into the flowbore 214 and uphole 502 to clean an area for future injection operations. In another embodiment, the locked position allows formation fluid to flow into the flowbore 214 and tubular string 122 (
As shown in
In an exemplary embodiment, the flow control apparatus 200 is run in at the closed position (
While the foregoing disclosure is directed to certain embodiments, various changes and modifications to such embodiments will be apparent to those skilled in the art. It is intended that all changes and modifications that are within the scope and spirit of the appended claims be embraced by the disclosure herein.
