FIG. 2 is a side, cross-sectional view of the wellbore shown in FIG. 1, now with a lateral leg having been drilled.
FIG. 3 is a side, cross-sectional view of the wellbore shown in FIGS. 1, 1A and 2 now with a lateral leg completion arrangement run into the lateral leg.
FIG. 4 is a side, cross-sectional view of the wellbore shown in FIGS. 1, 1A, 2-3 now with a feed-through assembly run into the wellbore and a first isolation string run into the lateral leg completion arrangement.
FIG. 4A is an enlarged, cross-sectional view of portions of FIG. 4.
FIG. 5 is a side, cross-sectional view of the wellbore shown in the previous figures, now with a pass-through device having been landed within the wellbore.
FIG. 5A is an enlarged, cross-sectional view of portions of FIG. 5.
FIG. 6 is a side, cross-sectional view of the wellbore shown in the previous figures, how with a second isolation string having been run into the main bore portion of the wellbore.
FIG. 7 is a side, cross-sectional view of an exemplary feed-through device used within the wellbore, apart from the other components.
FIG. 8 is an axial cross-section taken along lines 8-8 in FIG. 7.
FIG. 9 is a schematic diagram which illustrates such communication for a completed wellbore assembly.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
The term “multilateral,” as used herein, will refer to wellbores having a main bore, or leg, and at least one lateral leg which branches off from the main bore and extends radially away from the main bore. The term “communication line,” as used herein, refers broadly to conduits used in a wellbore for transmission of power, fluids and/or data. Communication lines can include electrical power cables, electrical data cables, optic fibers, and/or hydraulic lines.
FIGS. 1 and 1A illustrate a portion of an exemplary wellbore 10 which has been drilled through the earth 12. The wellbore 10 has an upper portion which has been lined with casing 14 and a lower main bore portion 16 which is unlined. A main bore completion arrangement, generally indicated at 18, has been run into the lower unlined portion 16, which shall also be referred to as the main bore portion of the wellbore 10. The exemplary main bore completion arrangement 18 is a tubular conduit which includes packers 20 and 22 which can be set to secure the main bore completion arrangement 18 within the main bore portion 16 of the wellbore 10. The main bore completion arrangement 18 also includes a lateral valve 24 and screen 26. A flowbore 28 is defined along the length of the main bore completion assembly 18. Fluid communication with the flowbore 28 is permitted through the use of flow controllers in the form of lateral valve 24 and screen 26. The lateral valve 24 is preferably a frac sleeve of a type known in the art which can be selectively moved between open and closed positions. In the open position, the lateral valve 24 permits fluid communication between the flowbore 28 and the radial exterior of the main bore completion arrangement 18.
A combination whipstock and seal bore diverter 30 is located within the wellbore 10 above the main bore completion arrangement 18. Preferably, the whipstock and seal bore diverter 30 is secured within the casing 14 of the wellbore 10 by anchor 32.
The whipstock and seal bore diverter 30 may be used to sidetrack a mill and subsequently a drill to create a lateral leg, as is known in the art. FIG. 2 illustrates the wellbore 10 after a lateral leg 34 has been created.
FIG. 3 illustrates the wellbore 10 at a subsequent time when a lateral leg completion arrangement 36 has been emplaced within the lateral leg 34. The lateral leg completion arrangement 36 can be run in by wireline or coiled tubing based running string or by other conventional methods and released within the lateral leg 34. The running string is then removed. The exemplary lateral leg completion arrangement 36 is a tubular string which includes packers 38, 40 as well as a lateral valve 42 and sleeve 44. A flowbore 46 is defined along the length of the lateral leg completion arrangement 36. The lateral valve 42 can be selectively moved between open and closed positions in order to control fluid communication between the flowbore 46 and the area radially surrounding the lateral leg completion arrangement 36. The completion 36 presents a closed distal end 48 and an open proximal end 50. The sleeve 44 is preferably a sliding sleeve device that can be opened and closed to allow fluid communication with the flowbore 46 of the lateral leg completion arrangement 36.
FIGS. 4 and 4A depict the wellbore 10 now with a first isolation string 52 having been run in and landed within the lateral leg completion arrangement 36. The first isolation string 52 is inserted into the open end 50 and preferably extends along the entire length of the lateral leg completion arrangement 36 and bottoms out at the closed distal end 48. The first isolation string 52 is preferably run in using a wireline or coiled tubing based running string and is then released within the lateral leg completion arrangement 36. The first isolation string 52 contains one or more communication lines and one or more devices that either utilize power from surface or that communicate with the surface. In the depicted embodiment, the first isolation string 52 includes a monitoring gauge 54. The monitoring gauge 54 typically includes one or more sensors that are capable of detecting at least one operational parameter, such as temperature, pressure or flow rate. In preferred embodiments, the monitoring gauge 54 detects operational parameters of fracturing fluid that is pumped through the lateral leg completion assembly 36 during fracturing operations. The operational parameters detected by the monitoring gauge 54 are transmitted to surface via communication line. When the first isolation string 52 is seated within the lateral leg completion 36, the monitoring gauge 54 is preferably located slightly upstream of the sleeve 44, as best seen in FIG. 4A, in order to measure temperature, pressure or other parameters relating to fracturing fluid proximate the sleeve 44 where the fluid would exit the flowbore 46.
The first isolation string 52 also includes a valve actuator 56. The valve actuator 56 is operable to actuate the lateral valve 42 of the lateral leg completion arrangement 36 between open and closed positions. A suitable valve actuator for use as the valve actuator 56 is an IWS (Intelligent Wellbore System) valve actuator which is available commercially from Baker Hughes Incorporated of Houston, Tex. It is noted that both the monitoring gauge 54 and the valve actuator 56 of the first isolation string 52 require, or preferably utilize, communication from surface to operate in their intended manner. The monitoring gauge 54, for example, preferably transmits data relating to detected operational parameters uphole to surface via one or more communication lines (electrical/fiber optic). The valve actuator 56 preferably utilizes power from surface (electrical/hydraulic) to operate.
The first isolation string 52 also features a mating connector 58 at its uphole end which will permit connection of communication lines within the first isolation string in end-to-end fashion with other communication lines. Preferably, the mating connector 58 is a wet mate connector which allows connection of electrical and other communication lines even in the presence of fluids. An example of a suitable wet mate connector is the annular electrical wet connect CA2669750 A1 which is available commercially from Baker Hughes Incorporated of Houston, Tex. Wet connect devices are also described in U.S. Pat. No. 6,439,932 (“Multiple Protected Live Circuit Wet Connect System”) issued to Ripolone.
FIGS. 5 and 5A illustrate the wellbore 10 now with a feed through device having been landed within the wellbore and a mating connection made with the mating connector 58 of the first isolation string 52. Feed through device 60 is shown seated upon the seal bore assembly 30, the whipstock having been removed previously. A packer 62 is preferably used to secure the feed through device 60 within the cased portion 14 of the wellbore 10.
A suitable device for use as the feed-through device 60 would be a Hydrasplit™ multilateral junction which is available commercially from Baker Hughes Incorporated of Houston, Tex. FIGS. 7 and 8 illustrate an exemplary feed-through device 60 which features a central mandrel 64 which defines an interior bore 66. The mandrel 64 splits into two legs 68, 70 at its lower end. First leg 68 has an outer surface portion 72 which is shaped and sized to be seated within the upper end of the seal bore diverter 30. When the first leg 68 is so seated, the second leg 70 will have entered the lateral leg 34 of the wellbore 10. The first leg 68 also defines an interior bore 74 through which tools, objects and fluids can be passed through the feed through device 60 into or out of the main bore completion assembly 18 below. The second leg 70 features one or more bores 76 through which objects and fluids can be passed through the feed through device 60 into or out of the lateral leg completion assembly 36. In the depicted embodiment, the bores 76 are used to contain communication lines, although some bores 76 may be used purely for production and be isolated from the interior bore 66. In the embodiment depicted in FIGS. 7-8, there are three bores 76. However, there may be more or fewer than three, as desired to create the desired number and types of communication lines to surface.
The feed-through device 60 is provided with suitable communication lines 78 (best shown in FIG. 5A) which extend through the feed-through device 60 and will permit communication of power and/or data between the surface and the first isolation string 52. As best seen in FIG. 5A, communication lines 78 include a mating connector 80 which is complementary to the uphole mating connector 58 of the first isolation string 52. The communication lines 78 terminate at an uphole mating connector 82. When the feed through device 60 is set down and landed upon the seal bore diverter 30 and set down weight applied, the connector 80 is interconnected with the uphole mating connector 58.
FIG. 6 illustrates the wellbore 10 at a time after the feed-through device 60 has been landed and communication line interconnection is made with the first isolation string 52. A communication work string 84 has now been lowered into the wellbore 10. The communication work string 84 includes tubing 86 for production to surface. The production tubing 86 also includes communication lines which extend to surface. A communications mating assembly 88 is located at the lower end of the production tubing 86. The communications mating assembly 88 will interconnect with the uphole mating connector 82 and will thereby provide a communication path between the first isolation string 52 and the surface of the wellbore 10.
A second isolation string 90 forms a part of the communication work string 84 and extends downwardly from the communications mating assembly 88. As the communications mating assembly 88 is interconnected with the uphole mating connector 82, the second isolation string 90 will be fed through the bore 74 of the feed through device 60 and landed within the flowbore 28 of the main bore completion assembly 18. The exemplary second isolation string 90 of FIG. 6 includes a monitoring gauge 92. The monitoring gauge 92 will preferably be positioned slightly uphole from the screen 26 in order to measure temperature, pressure or other parameters relating to fracturing fluid proximate the screen 26 where the fluid would exit the flowbore 28. The exemplary second isolation string 90 also includes a valve actuator 94. The frac sleeve 24 is used for fracturing the surrounding formation prior to installation of the second isolation string 90. Production fluid will later enter via the screen 26. The valve actuator 94 allows an operator to flow from the particular zone in which the screen 26 is located. The valve actuator 94 is located proximate the lateral valve 24 so that it can move the lateral valve 24 between open and closed positions. The valve actuator 94 preferably utilizes power from surface (electrical/hydraulic) to operate.
Once the communication work string 84 has been landed within the wellbore 10, complete communication lines are now provided between devices at the surface and components in the first and second isolation strings 52, 90. FIG. 9 is a schematic diagram illustrating communication lines between the surface 96 and certain components within the first and isolation strings 52, 90 in the wellbore 10. At surface 96 are several exemplary transmission/reception devices which can be used to transmit power or commands downhole or which receive data or information from the wellbore 10. Some or all of these transmission/reception devices might be used in any particular instance. These devices include an electrical power generator 98 and hydraulic fluid pump 100. An optical time-domain reflectometer (“OTDR”) 102 is also located at surface 96 and is used to transmit and receive data along an optical fiber. Additionally, a processor 104 is located at surface 96 which is programmed to receive, store and/or display data detected by a downhole sensor. The processor 104 may be in the form of a computer with suitable software and programming.
Communication lines extend from the surface 96 to components within the wellbore 10. FIG. 9 is a schematic diagram which illustrates such communication for a completed wellbore assembly. Communication lines include an electrical power conduit 106 which extends from the power generator 98 into the wellbore 10. The electrical power conduit 106 can supply electrical power to valve actuators 56, 94 (if electrically operated) and/or to monitoring gauges 54, 92. A hydraulic conduit 108 leads from the fluid pump 100 and can be used to supply hydraulic power to operate valve actuators 56, 94 (if hydraulically actuated). An optical fiber 110 and an electrical data cable 112 extend into the wellbore 10 from the OTDR 102 and processor 104, respectively. Each of these communication lines (110, 112) is useful to transmit data, information, or commands between the surface 96 and components within the wellbore 10, such as the monitoring gauges 54, 92 or possibly the valve actuators 56, 94.
The invention provides a communication junction arrangement for a multilateral wellbore having a main bore portion 16 and at least one lateral leg 34. In other aspects, the invention provides a method for constructing a hydrocarbon production assembly within a multilateral wellbore which provides communication lines for completion arrangements 18, 36 in both the main bore portion 16 and the lateral leg 34. In accordance with these methods, a main bore completion arrangement 18 is disposed within a main bore portion 16 of a wellbore 10. A whipstock and seal bore diverter 30 is then landed upon the main bore completion arrangement 18. A lateral leg 34 is then formed which extends radially away from the main bore portion 16. Next, a lateral leg completion arrangement 36 is then disposed within the lateral leg 34. A first isolation string 52 is inserted into the lateral leg completion arrangement 36. A second isolation string 90 is then inserted into the main bore completion arrangement below the seal bore diverter 30. Communication is then established between each of the first and second isolation strings 52, 90 and at least one transmission/reception device at surface 96. The transmission/reception devices include electrical power generator 98, hydraulic fluid pump 100, OTDR 102 and processor 104. Communication is established by lines 106, 108, 110 and/or 112.
In operation, fluid flow parameters are measured as fluid (i.e., fracturing fluid) is flowed out of the flowbores 28, 46 of the main bore and lateral leg completion arrangements 18, 36 through valves 56, 94 and screen 26. Fluid that is flowed can include fracturing fluid or other formation treatment fluid which′ is flowed out of the flowbores 28, 46 and into the surrounding formation. Fluid that is flowed can also include hydrocarbon production fluid that is drawn into the flowbores 28, 46 of the main bore and lateral leg completion arrangements 18, 36. Thus, the valves 56, 94, screen 26, and valve 42 can be thought of as flow controllers which can be opened and closed by the first and second isolation strings 52, 90 to permit fluid communication either outwardly into the surrounding formation (i.e., for fracturing fluids) or inwardly from the formation (i.e., production fluid).
Those of skill in the art will recognize that numerous modifications and changes may be made to the exemplary designs and embodiments described herein and that the invention is limited only by the claims that follow and any equivalents thereof.
Patent Application
20170241241
