Patent Application
20170058646
The present disclosure relates generally to deepwater extended reach hardrock completions. More specifically, in certain embodiments, the present disclosure relates to high angled deepwater extended reach hardrock completions and associated methods and systems.
Extended reach drilling is the directional drilling of very long high angle to horizontal wellbores. The aims of extended reach drilling are: (1) to reach a larger area from one surface drilling location, and (2) to keep a well in a reservoir for a longer distance in order to maximize its productivity and drainage capability. Examples of extended reach drilling systems and methods are disclosed in U.S. Pat. Nos. 8,657,015, 6,942,044, 6,142,245, 5,343,950, and 4,431,068, the entireties of which are hereby incorporated by reference.
Existing deepwater wells are typically drilled less than 30 degrees from vertical due to requirements imposed by sand control technology. These low angles can limit the contact and/or exposure provided by long lateral distances within the reservoir. Many deepwater, deep reservoir extended reach wells cannot be drilled by the majority of rigs in existing fleets. In addition, high angle deepwater wells cannot be completed using the traditional sand control technology. Furthermore, each of the reservoirs penetrated by the wells may need to undergo up to five separate massive fracs thereby limiting the stimulation of reservoirs with more than five horizons. Current deepwater completion methods do not allow for multi fracs in high angle and extended reach wells.
It is desirable to develop methods that allows for drilling high angle contact and the use of multi fracs in an open hole wellbore to enhance both recovery and inflow performance relationship.
The present disclosure relates generally to deepwater extended reach hardrock completions. More specifically, in certain embodiments, the present disclosure relates to high angled deepwater extended reach hardrock completions and associated methods and systems.
In one embodiment, the present disclosure provides a deepwater extended hardrock completion system comprising a wellbore penetrating a subsea subterranean formation, wherein the wellbore comprises a near vertical first portion, a deviated second portion, and a deviated third portion.
In another embodiment, the present disclosure provides a modular lower completion string comprising one or more first modules and one or more second modules, wherein each of the one or more first modules comprises one or more open hole packers, one or more frac sleeves, one or more sand control/inflow modules, one or more seal bores, and one or more spacer pipes and wherein each of the one or more second modules comprises one or more external casing packers and one or more spacer pipes.
In another embodiment, the present disclosure provides a method comprising: providing a subsea subterranean formation; drilling a first portion of a wellbore and drilling a second portion of the wellbore penetrating the subsea subterranean formation, wherein the second portion is a deviated portion.
A more complete and thorough understanding of the present embodiments and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings.
The features and advantages of the present disclosure will be readily apparent to those skilled in the art. While numerous changes may be made by those skilled in the art, such changes are within the spirit of the disclosure.
The description that follows includes exemplary apparatuses, methods, techniques, and/or instruction sequences that embody techniques of the inventive subject matter. However, it is understood that the described embodiments may be practiced without these specific details.
The present disclosure relates generally to deepwater extended reach hardrock completions. More specifically, in certain embodiments, the present disclosure relates to high angled deepwater extended reach hardrock completions and associated methods and systems.
In certain embodiments, the present disclosure relates to a novel application of drilling high angle contact (with the reservoir) and the use of multi-fracs (aka multi-zonal fracing) in an open hole wellbore to enhance both recovery and IPR respectively.
There may be several advantages of the methods and systems described herein. In certain embodiments, the methods and systems described herein allow for an increase in the IPR of a well to a point where production can be accelerated. In certain embodiments, the methods and systems described herein allow for an increase in the overall recovery per well to the point where fewer wells can be drilled for the same economic performance. In certain embodiments, use of the methods and systems described herein may allow for the use of water flooding as the methods described herein may improve the injectivity of a formation. In certain embodiments, the present disclosure uses open hole fracture stimulation of subsea high angle wells using processes normally found onshore.
In certain embodiments, the systems and methods described herein allow for two fold increase in recovery from a well. In certain embodiments, the hard rock formation may permit the use of screen only sand control technology or do not require sand control thus allowing for high angle wells. The combination of the high angle wells with the use of multi-fracs may result in a doubling of the recovery per well.
In certain embodiments, the systems and methods described herein allow for the simultaneous fracture of multiple legs of a single wellbore.
In certain embodiments, the present disclosure discloses a deepwater extended hardrock completion system. Referring now to
In certain embodiments, wellbore 1100 may comprise subsea wellbore. In certain embodiments, wellbore 1100 may comprise an open-hole wellbore. In certain embodiments, a portion of wellbore 1100 may comprise an open-hole wellbore. In certain embodiments, wellbore 1100 may comprise a first portion 1101, a second portion 1102, and a third portion 1103.
In certain embodiments, first portion 1101 may be a vertical portion or a near vertical portion. In certain embodiments, first portion 1101 may be deviated from vertical at an angle in the range of from 0° to 20°. In certain embodiments, first portion 1101 may be deviated from vertical at an angle in the range of from 5° to 10°. In certain embodiments, first portion 1101 may be deviated from vertical at an angle in the range of from 0° to 5°.
In certain embodiments, second portion 1102 may be a deviated portion. In certain embodiments, second portion 1102 may be deviated from vertical at an angle in the range of from 30° to 90°. In certain embodiments, second portion 1102 may be deviated from vertical at an angle in the range of from 45° to 60°.
In certain embodiments, third portion 1103 may be a deviated portion. In certain embodiments, third portion 1103 may be deviated from vertical at an angle in the range of from 0° to 60°. In certain embodiments, third portion 1103 may be deviated from vertical at an angle in the range of from 30° to 45°.
In certain embodiments, deepwater extended hardrock completion system 1000 may further comprise casing 1300. In certain embodiments casing 1300 may be disposed only in first portion 1101 of wellbore 1100. In certain embodiments, casing 1300 may comprise any conventional casing. In certain embodiments, casing 1300 may be designed to be rotated. In certain embodiments, casing 1300 may be cemented in place.
In certain embodiments, deepwater extended hardrock completion system 1000 may further comprise lower completion string 1400. In certain embodiments, lower completion string 1400 may comprise liner packer 1401, open hole packers 1402, frac sleeves 1403, production sleeves 1404, sand control/inflow module 1405, seal bores 1406, isolation seals 1407, external casing packers 1408, spacer pipes 1409, and float shoe 1410.
In certain embodiments, liner packer 1401 may comprise any type of conventional liner packer. In certain embodiments, liner packer 1401 may be mechanically coupled to lower completion string 1400 by way of a threaded connection. In certain embodiments, liner packer 1401 may be used to attach or hang lower completion string 1400 from the internal wall of the casing (not illustrated in
In certain embodiments, open hole packer 1402 may comprise any type of conventional open hole packer. In certain embodiments, open hole packer 1402 may be mechanically coupled to lower completion string 1400 by way of threaded connections. In certain embodiments, and in conjunction with frac sleeve 1403, open hole packer 1402 allows for independent stimulation of individual zones/segments within the well and reservoir. In certain embodiments, for example when used in conjunction with stand-alone inner string and sand control/inflow module 1405, open hole packer also 1402 may allow for inflow from individual zones/segments within the reservoir.
In certain embodiments, frac sleeve 1403 may comprise any type of conventional frac sleeve. In certain embodiments, frac sleeve 1403 may be mechanically coupled to lower completion string 1400 by way of threaded connections. In certain embodiments, when used in conjunction with open hole packer 1402, frac sleeve 1403 may be used to stimulate the reservoir in independent segments by providing a flow path from the inner lower completion to the open hole. In certain embodiments, frac sleeve 1403 may comprise one or more multi-directional hydra jetting nozzles and/or one or more multi-directional direct formation connecting ports. In certain embodiments, frac sleeve 1403 may comprise any type of sand control/inflow module.
In certain embodiments, frac sleeve 1403 sleeves may comprise large bores. In certain embodiments, the bores may have an inner diameter in the range of from 3 inches to 6 inches. In certain embodiments, the bores may have an inner diameter in the range of from 4 inches to 6 inches. In certain embodiments, the large bores may enable the use of a stand-alone inner string comprising production sleeve 1404 and isolation seal 1407. In such embodiments, the large bores may allow passage of the stand-alone inner string and its components in order that the stand-alone inner string size will not inhibit production from the reservoir.
In certain embodiments, the fracture sleeve 1403 may be operated using a pump down tool without using a tool on the work string. In certain embodiments, facture sleeve 1403 may have a ball and seat design. In certain embodiments, the ball and seat design may include use of disintegrating materials. In certain embodiments, the fracture sleeve 1403 may be operated using a pipe conveyed shifting tool.
In certain embodiments, production sleeve 1404 may comprise any type of conventional production sleeve. In certain embodiments, production sleeve 1404 may be a component of a stand-alone inner string and may be mechanically coupled to the stand-alone inner string by way of threaded connections. In certain embodiments, the stand-alone inner string may be conveyed into the well on a subsequent pipe trip after all fracturing is completed. In certain embodiments, production sleeve 1404 may allow inflow from the reservoir to the stand-alone inner string. In certain embodiments, the production sleeve 1404 may be operated using a pipe conveyed shifting tool.
In certain embodiments, sand control/inflow module 1405 may comprise any type of conventional sand control/inflow module. In certain embodiments, sand control/inflow module 1405 may mechanically coupled to the lower completion string 1400 by way of threaded connections. In certain embodiments, sand control/inflow module may be used to provide hydrocarbon inflow from the reservoir while also providing a means of solids exclusion.
In certain embodiments, seal bore 1406 may comprise any type of conventional seal bore. In certain embodiments, seal bore 1406 may be mechanically coupled to lower completion string 1400 by way of threaded connections. In certain embodiments, seal bore 1406 may be used to provide a sealing surface for isolation seal 1407.
In certain embodiments, isolation seal 1407 may comprise any type of conventional isolation seal. In certain embodiments, isolation seal 1407 may be mechanically coupled to the stand-alone inner string by way of threaded connections. In certain embodiments, isolation seal 1407 may be used in conjunction with seal bore 1406 to provide a seal in order that the individual zones/segments can be isolated.
In certain embodiments, external casing packer 1408 may comprise any type of conventional external casing packer. In certain embodiments, external casing packer 1408 may be mechanically coupled to lower completion string 1400 by way of threaded connections. In certain embodiments, external casing packer 1408 may comprise a swelling elastomer.
In certain embodiments, spacer pipe 1409 may comprise any type of conventional spacer pipe or blank pipe. In certain embodiments, spacer pipe 1409 may be mechanically coupled to lower completion string 1400 by way of threaded connections. In certain embodiments, spacer pipe 1409 may be used to provide a spacer so that each frac sleeve 1403 and other necessary components can be appropriately placed in the wellbore.
In certain embodiments, float shoe 1410 may comprise any type of conventional float shoe. In certain embodiments, float shoe 1410 may be mechanically coupled to lower completion string 1400 by way of threaded connections. In certain embodiments, float shoe 1410 may be used to prevent inflow of wellbore fluid into lower completion string 1400 while conveying the system in the well. In certain embodiments, float shoe 1410 may also guide the assembly into the well and reduce the hook weight of the assembly by making the assembly buoyant.
In certain embodiments, lower completion string 1400 may have a modular design. In such embodiments, lower completion string 1400 may comprise any number of first modules 1501 and second modules 1502. As shown in
In certain embodiments, first modules 1501 may comprise one or more open hole packers 1402, frac sleeves 1403, sand control/inflow modules 1405, seal bores 1406, and spacer pipes 1409. In certain embodiments, second modules 1502 may comprise one or more external casing packers 1408 and one or more spacer pipes 1409. In certain embodiments, first modules 1501 may comprise two open hole packers 1402 with one or more frac sleeves 1403, sand control/inflow modules 1405, seal bores 1406, and spacer pipes 1409 disposed in between the two open hole packers 1402.
In certain embodiments, lower completion string 1400 may be a stand-alone completion without an inner string. In certain embodiments, lower completion string 1400 may divvy up the completion into hydraulic units via packers and may have pressure and temperature gauges and an option to use distributed temperature array and/or Fiber Optics (DTS/DAS). In certain embodiments, lower completion string 1400 may also accommodate zonal flow control for either injectors or producers.
In certain embodiments, the present disclosure provides a method comprising: providing a subsea subterranean formation; drilling a first portion of a wellbore; drilling a second portion of the wellbore penetrating the subsea subterranean formation, wherein the second portion is a deviated portion. In certain embodiments, the method may further comprise drilling a third portion of the wellbore penetrating the subsea subterranean formation, wherein the third portion is a deviated portion. In certain embodiments, the method may further comprise drilling a fourth portion of the wellbore penetrating the subsea subterranean formation, wherein the fourth portion is a deviated portion. In certain embodiments, the method may further comprise fracturing a portion of the subsea subterranean formation adjacent to the well bore.
In certain embodiments, the subsea subterranean formation may be a deepwater subterranean formation. In certain embodiments, the subterranean formation may comprise any subterranean formation discussed above with respect to subsea subterranean formation 1200. In certain embodiments, the wellbore may comprise any wellbore discussed above with respect to wellbore 1100.
In certain embodiments, the first portion of the wellbore may be a vertical portion or a near vertical portion. In other embodiments, the first portion of the wellbore may be deviated from vertical at an angle in the range of from 0° to 20°. In certain embodiments, the first portion of the wellbore may be deviated from vertical at an angle in the range of from 5° to 10°.
In certain embodiments, the second portion of the wellbore may be a deviated portion. In certain embodiments, the second portion of the wellbore may be deviated from vertical at an angle in the range of from 30° to 90°. In certain embodiments, the second portion of the wellbore may be deviated from vertical at an angle in the range of from 45° to 60°.
In certain embodiments, the third portion may be a first leg of the wellbore or a lateral. In certain embodiments, the third portion of the wellbore may be deviated from vertical at an angle in the range of from 0° to 60°. In certain embodiments, the third portion of the wellbore may be deviated from vertical at an angle in the range of from 30° to 45°.
In certain embodiments, the fourth portion may be a second leg of the wellbore or a lateral. In certain embodiments, the fourth portion of the wellbore may be deviated from vertical at an angle in the range of from 0° to 60°. In certain embodiments, the fourth portion of the wellbore may be deviated from vertical at an angle in the range of from 30° to 45°.
In certain embodiments, the first portion of the wellbore, the second portion of the wellbore, the third portion of the wellbore, and/or the fourth portion of the wellbore may be drilled with a drilling string utilizing a combination of swell and mechanical external casing packers instead of cement. In certain embodiments, the use of the combination of swell and mechanical external casing packers may be beneficial as their use provides the instant isolation of the mechanical external casing packers with the longevity of the swell external casing packers. In certain embodiments, the swell and mechanical external casing packers may make up the drilling string.
In certain embodiments, logging while drilling (LWD) data may be collected as the first portion, the second portion, the third portion, and/or the fourth portion of the wellbore. In certain embodiments, the LWD data may be used to determine the location of sweet spots for the placement of fracs in the wellbore. In certain embodiments, the sweet spots may have high resistivity and/or comprise natural fractures. In certain embodiments, the sweet spots may be adjacent to the second portion of the wellbore, the third portion of the wellbore, and/or the fourth portion of the wellbore.
In certain embodiments, fracturing a portion of the subterranean formation adjacent to the wellbore may comprise fracturing the subterranean formation at a sweet spot. In certain embodiments, fracturing a portion of the subterranean formation may comprise utilizing a work string to fracture the subterranean formation. In certain embodiments, the work string may comprise any combination of features discussed above with respect to lower completion string 1400.
In certain embodiments, fracturing a portion of the subterranean formation comprise placing a fracture sleeve of the work string within 3 feet of the sweet spot and fracturing the subterranean formation utilizing the fracture sleeve. In certain embodiments, the fracture sleeve may comprise any combination of features discussed above with respect to frac sleeve 1403. In certain embodiments, operation and isolation of the fracture sleeve may be controlled utilizing a ball and seat method.
In certain embodiments, fracturing a portion of the subterranean formation comprises fracturing the formation with multi-directional hydra jetting nozzles and/or multi-directional direct formation connecting ports. In certain embodiments, the multi-directional hydra jetting nozzles and/or multi-direction direct formation connecting ports may be incorporated into the fracture sleeve design. In certain embodiments, the use of such a fracture sleeve may reduce the probability of early screen out due to the ability to orientate fracture initiation perpendicular with minimum horizontal stress. It is believed that by allowing the fracture to initiate perpendicular to the least principle minimum horizontal formation stress, the chance for near wellbore fracture tortuosity can be reduced.
In certain embodiments, by targeting the fracture placement to sweet spots, the overall fracture size can be reduced, thus eliminating the need for weighted fracture fluids (due to lower pump rates) and improving offshore stimulation vessel logistics. Furthermore, in certain embodiments, the methods and systems described herein may eliminate the need for repeated teardown and rig up of the surface treating lines after each frac as the methods and systems described herein may be operated in a continuous process, thereby saving multiple days of rig time during the completion of the well.
While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible.
Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.
This application claims the benefit of U.S. Provisional Application No. 62/209,462, filed Aug. 25, 2015, which is incorporated herein by reference.
| Number | Date | Country | |
|---|---|---|---|
| 62209462 | Aug 2015 | US |
