US20110030963A1 - Multiple well treatment fluid distribution and control system and method - Google Patents
Multiple well treatment fluid distribution and control system and method Download PDFInfo
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- US20110030963A1 US20110030963A1 US12/631,834 US63183409A US2011030963A1 US 20110030963 A1 US20110030963 A1 US 20110030963A1 US 63183409 A US63183409 A US 63183409A US 2011030963 A1 US2011030963 A1 US 2011030963A1
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
- E21B43/2607—Surface equipment specially adapted for fracturing operations
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/30—Specific pattern of wells, e.g. optimizing the spacing of wells
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- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Earth Drilling (AREA)
Abstract
A system for distributing fluid to a plurality of wellbores drilled from a common pad includes at least two fluid conduits extending between the wellbores. The fluid conduits are configured to couple at one end to a fluid pump. At least one remotely operable valve is hydraulically connected to each fluid conduit proximate each wellbore. At least one flow line hydraulically connects each remotely operable valve to each wellbore such that fluid moved through the flow line enters the wellbore. A control unit is disposed proximate the pad and is configured to operate the remotely operable valves.
Description
- Priority is claimed from U.S. Provisional Application No. 61/231,252 filed on Aug. 4, 2009.
- Not applicable.
- 1. Field of the Invention
- The invention relates generally to the field of fluid treatment of wellbores drilled through subsurface rock formations. More particularly, the invention relates to systems for controlling distribution of treatment fluid to multiple wells drilled from a common surface pad or platform.
- 2. Background Art
- Wellbores drilled through subsurface rock formations to extract oil and gas may be treated by pumping various types of fluids into the formations. Fluid pumping treatments include, for example, hydraulic fracturing, wherein fluid is pumped into the formation at pressure that exceed the fracture pressure of the formations. The fractures thus opened may be held open by pumping of material (proppant) that supports the fracture structurally after the fluid pressure on the formation is relieved. Other fluid treatments may include, for example, pumping acid into the wellbore to dissolve certain minerals present in the pore spaces of the formations that reduce the formation permeability.
- Certain types of rock formations that hold oil and/or gas reservoirs may have a plurality of wellbores drilled through the rock formations along selected trajectories deviated from vertical, or even substantially horizontally. Such wellbores may be drilled, for example, so that the surface locations of the wellbores are closely spaced on a relatively small land area called a “pad”, or on a structure in the water called a “platform” in marine environments, while the lowermost portions of the wellbore extend laterally from the respective surface locations in a selected drainage pattern. Such arrangement reduces or minimizes the amount of land surface affected by the construction of the wellbores.
- In conducting fluid pumping treatments on multiple wells drilled from a common surface pad or platform, it is generally necessary to connect the pumping equipment hydraulically to one well, pump the fluid, then disconnect the pumping equipment from the well before another well can be fluid treated. Such operations can create, among other exposures, safety risks to personnel working on or near the pad or platform, and interference with the operation of wellbores that are producing oil and/or gas while the fluid treatment equipment is connected and disconnected from various wellbores on the pad or platform. Such connection and disconnection operations may also take considerable amounts of time to perform.
- Limitations of the current state of the art design may include the following. Current piping configurations for fracture treatment can have many limitations in wells requiring multiple completed intervals and on pads with multiple wellheads. The common land fracturing configuration involves laying pipe from each “frac pumper” to a central collection manifold and then in single or multiple lines to the well being treated. The result is that a costly separate rig-up and rig down is required for every fracture treatment.
- In many applications, a single stimulation is not sufficient, and multiple stimulations of different intervals are required. On pads with multiple wells, if a problem is encountered on a well while there are still intervals to stimulated, a significant cost can be incurred. Also, the problem must be solved before the stimulation can continue, resulting in the stimulation equipment waiting until the problem is resolved. In the case of a problem with a barrier between the intervals to stimulate, this can cause a very expensive delay of multiple days, or a complete demobilization of the pumping equipment.
- What is needed is a system that enables selective connection of fluid treatment equipment to multiple wells having surface locations on a pad, platform or similar surface arrangement without the need for human intervention near the well surface control equipment (“wellhead”), and that can provide increased fluid pumping capacity, can save time, enable more treatments to be accomplished in shorter time and reduces potential for spills. It is desirable that such system has sensing devices to determine whether any system components have eroded as a result of fluid flow, so that the system operator can determine when it is necessary to replace affected system components or reroute flow through alternate conduits when and if needed.
- A system according to one aspect of the invention for distributing fluid to a plurality of wellbores drilled from a common pad includes at least two fluid conduits extending between the wellbores. The fluid conduits are configured to couple at one end to a fluid pumping system of one or more pumps. At least one remotely operable valve is hydraulically connected to each fluid conduit proximate each wellbore. A flow line hydraulically connects each remotely operable valve to each wellbore such that fluid moved through the flow line enters the wellbore. A control unit is disposed proximate the pad and is configured to operate the remotely operable valves.
- A method according to another aspect of the invention for operating a plurality of wellbores drilled from a common pad, wherein the wellbores include at least two fluid conduits extending between the wellbores, the fluid conduits configured to couple at one end to a fluid pump; at least one remotely operable valve hydraulically connected to each fluid conduit proximate each wellbore, a flow line hydraulically connecting each remotely operable valve to each wellbore such that fluid moved through the flow line enters the wellbore, and a control unit disposed proximate the pad and configured to operate the remotely operable valves includes the following. A wellbore intervention device is moved to a selected one of the wellbores. A signal is communicated from the control unit to close the remotely operable valves associated with the selected wellbore. At least one wellbore instrument is inserted into the selected one of the wellbores using the intervention device. A signal from the control unit is communicated to open at least one of the remotely operable valves at least one other wellbore. Fluid is pumped into ones of the at least two conduits associated with the opened remotely operable valves such that fluid enters the at least one other wellbore.
- Other aspects and advantages of the invention will be apparent from the following description and the appended claims.
-
FIG. 1 shows schematically an example treatment fluid distribution system. -
FIG. 2 shows a more detailed view of a wellhead shown inFIG. 1 . - An example well treatment fluid distribution and control system is shown schematically in
FIG. 1 . Thesystem 11 may be hydraulically connected to a plurality of wells drilled through subsurface rock formations from a common “pad” orplatform 10. Thepad 10 is arranged such that the surface locations of the wellbores are proximate each other. Thepad 10 may be, for example, an area of the land surface clear, leveled and configured for equipment access to the various wellbores, or as another example may be a bottom supported or floating marine (water based) platform. An example spacing between surface locations of the wellbores is about 3 meters, although the exact spacing is not intended to limit the scope of the present invention. Well surface positions spacings are known to vary between three to fifteen or more meters in such pad drilling arrangements. As is known in the art, wellbores drilled through subsurface locations typically include a pipe or “casing” emplaced in the wellbore along part or all of the wellbore. A set of control valves and pressure isolating devices, called a “wellhead” 12 is coupled to the surface end of such pipe or casing on each such wellbore. An example of thewellhead 12 will be shown in more detail and explained further below with reference toFIG. 2 . The example shown inFIG. 1 includeswellheads 12 disposed in two lines or rows, however, the number of wellheads on any pad or platform and their particular geometric arrangement are not limits on the scope of the present invention. - In some examples, the wellbores (shown in
FIG. 2 ) may be initially drilled from the surface substantially vertically and may at a selected depth be have the wellbore trajectory change so that the well is ultimately drilled at high inclination or substantially horizontally to enable the wellbores to provide a selected reservoir drainage pattern. The trajectory of any of the individual wellbores, however is not a limit on the scope of the present invention. - A first
fluid manifold line 24 may extend along thepad 10 from amain control valve 22 disposed at one end of thefirst manifold line 24 substantially to the longitudinal position of afurthest wellhead 12 on thepad 10. Similarly, a secondfluid manifold line 26 may extend from amain control valve 22 at one end to the longitudinal position of thefurthest wellhead 12. During fluid treatment operations, apumping unit 28 may be disposed at one end of thepad 10 as shown. Typically, thepumping unit 28 will be removed from thepad 10 at times when fluid treatment operations are not underway. During such times, themain control valves 22 will be closed, and the ends of the first 24 and second 26 manifold lines may be hydraulically closed by closing themain control valves 22. Although not shown inFIG. 1 , themanifold lines manifold lines wellheads 12. Thepumping unit 28 may be, for example, an hydraulic fracture pumping unit, an acid pumping unit, or any other wellbore fluid pumping unit known in the art for introducing fluid under pressure into a wellbore drilled through subsurface rock formations. - Proximate the position of each wellhead, a “T” or “Y”
fluid coupling 20 may be disposed in eachmanifold line wellhead 12 from eachmanifold line manifold lines wellhead 12. Connection from thefluid coupling 20 in the firstmanifold line 24 to thewellhead 12 may be obtained using a first remotelyoperable control valve 18, and for safety and backup purposes a first manually operatedcontrol valve 16 coupled to the wellhead through a first treatmentfluid flow line 14. The first remotelyoperable control valves 18 may be, for example, hydraulically controlled, electrically controlled (using cable or using wireless control) or operated by any other device that enables control of the valve from a location remote from the location of the valve. In other examples, themanual control valves 16 may also be remotely operable. It is only necessary for purposes of the invention to have one remotely operable valve between themanifold line 24 and thewellhead 12. Thefirst flow line 14 may be, for example, flexible hose, flexible metal line, formed rigid metal line or other type of line used in hydraulic fracturing operations known as a “chicksan.” It is preferable for thefirst flow line 14 to have smooth bends to avoid as far as practical abrupt changes in flow direction. - In the present example, the
second manifold line 26 may be hydraulically connected to eachwellhead 12 through afluid coupling 20 and corresponding second remotelyoperable valve 19, secondmanual valve 17 andsecond flow line 15. Each of the foregoing components may be similar in configuration to the respective first remotelyoperable valves 18,manual valves 16 andflow lines 14. The second remotelyoperable valves 19 and the first remotelyoperable valves 18 may be operated remotely from acontrol unit 30 having suitable devices (not shown separately), for example, a suitably programmed computer with associated device drivers to actuate the device (not shown separately) that enables the remotelyoperable valves control unit 30 may also be configured to interrogate sensors in signal communication with thecontrol unit 30 so that the system operator may determine various system operating and condition parameters. - In other examples of a system, more than two manifold lines and associated wellhead connecting equipment as described above may be used. For example, if the required fluid flow rates may exceed the flow capacity of two manifold lines, one or more additional manifold lines may be used substantially as explained above, preferably with a main control valve at one longitudinal end, a T or Y coupling proximate each wellhead location, a remotely operable valve and a flow line.
- The
system 11 shown inFIG. 1 may enable selective pumping of fluid from thepumping unit 28 to any or all of the wellbores through therespective wellheads 12 by suitable operation of the remotelyoperable valves operable valve 18 and the second remotelyoperable valve 19 may be opened. In the event of failure of a particular remotely operable valve, for example the first remotelyoperable valve 18, it is possible to pump fluid into thewellhead 12 through the second remotelyoperable valve 19. It is also possible to repair or replace individual remotelyoperable valves manual valve operable valves respective manifold line main control valve 22 associated with the respective manifold line so that pressure may be relieved therefrom. -
FIG. 1 also shows awell intervention device 50, such as a coiled tubing unit, including areel 52 and guiderollers 52 that enable coiledtubing 53 to be inserted into one of the wellbores through suitable pressure control equipment (not shown) coupled to the top of thewellhead 12. Other well intervention devices may include, without limitation, wireline units, snubbing units and workover rigs. The functions performed by thewell intervention device 50 as they relate to thesystem 11 will be further explained below. -
FIG. 2 shows one of thewellheads 12 in more detail, as well as several additional components of the fluid distribution and control system. Thewellhead 12 may includemaster valves well casing 32. Thecasing 32 is shown extending into the subsurface from thewellhead 12 starting substantially vertically and then extending substantially horizontally in areservoir formation 35. Thecasing 32 may haveperforations 33 disposed at a selected position within thereservoir formation 35. The configuration of casing shown inFIG. 2 is only provided as an example, and is not intended to limit the scope of the present invention. The first 14 and second 15 flow lines may be coupled to thewellhead 12 above themaster valves spool 41. Thespool 41 may be configured similarly to fluid coupling devices used for hydraulic fracturing operations known as “frac heads.” Hydraulic connections to thewellhead 12 from themanifold lines FIG. 1 . Avalve 40 may be disposed above thespool 41 to enable thewellhead 12 to be hydraulically closed in the event wellbore intervention operations are required (e.g., insertion of tools, coiled tubing and any other devices known in the art). Thewellhead 12 may also include one ormore wing valves 38 to enable coupling of thewellhead 12 to a production line (not shown) for delivery of produced fluid from the wellbore. - In the present example, the
flow lines manifold lines erosion sensor 44 downstream of the bend in theflow lines coupling 20, respectively, or other places in the flow path as required. In other examples, wherein themanifold lines erosion sensor 44 may be disposed proximate each connection downstream in the flow direction. Theerosion sensors 44 may be, for example, target plates, acoustic sensors or electromagnetic induction sensors configured to make measurements and assist in predicting wear or metal loss corresponding to the wall thickness or stability of therespective flow line manifold line erosion sensors 44 may be wirelessly in signal communication with, or may be cable (e.g., electrical and/or optical cable) connected to the control unit (30 inFIG. 1 ) so that thickness of the respective component may be continuously monitored. In the event any of the sensor measurements indicates that the component thickness is less than a predetermined safe amount, such component (e.g., segment of theflow lines manifold lines 24, 26) may be removed from service and replaced. - In the present example, pressure and/or
temperature sensors 45 may be disposed in theflow lines manifold lines temperature sensors 45 may be in signal communication with the control unit (30 inFIG. 1 ) using cable or wireless connection, as is the case for theerosion sensors 44. Measurement of pressure and/or temperature at selected positions within the system may enable the system operator to determine optimum routing of pumped fluid toparticular wellheads 12 and/or to isolate portions of the system that may be defective or at risk of failure. - In the present example, flow
rate sensors 47 may be disposed in theflow lines manifold line FIG. 1 ) by wireless or cable connection. - Returning to
FIG. 1 , it is possible using thesystem 11 to perform fluid pumping into one or more wellbores while thewell intervention device 50 performs one or more tasks on a selected wellbore, including inserting at least one wellbore instrument into the selected wellbore. For example, coiled tubing may be used to convey pressure actuated perforating guns or well tools into the wellbore, or remove proppant from a wellbore. Wireline units may be used to convey perforating guns, fracture treatment isolation packers and other devices for installation in the wellbore. During such operations, the remotelyoperable valves intervention device 50 working thereon may be closed. Another one or more of the wellbores may have the remotelyoperable valves control unit 30. Fluid may be pumped into the wellbore(s) having the opened remotelyoperable valves pumping unit 28. The fluid may be hydraulic fracturing fluid, for example, water or breakable gel having sand or ceramic particles as proppant. The fluid may be pumped in stages according to well known fracturing procedures to open fractures in the formation and insert the proppant therein to hold the fractures open after fluid pressure from thepumping unit 28 is relieved. It is possible to move theintervention device 50 from wellbore to wellbore without the need to move thepumping unit 28 or the need to move or physically disconnect any part of thesystem 11 from thewellheads 12. Such operation is believed capable of saving substantial operating time and cost, as well as increasing safety by reducing personnel operations related to moving components of or modifying components of the flow system. - Possible benefits of a system made as described herein include the following. Personnel need not be present in the wellhead area during operations because the system may be assembled prior to commencing any pumping operations. Such feature can significantly reduce risk by using the remotely valves (18, 19 in
FIG. 1 ) to route the fluid flow along the manifold and between wellheads. - Offsite building of many of the unitized components of a fit-for-purpose manifold can be used for all the wells on a pad, with minimum time required on-site for final assembly. Once assembled, the fluid distribution system can provide fluid access to each well on the pad without significant changes in location or the flow equipment, and thus minimizes many fracturing rig-up construction activities. Activities involving equipment transport, use of cranes and forklifts are reduced, and vehicular traffic, human presence and construction noise are minimized.
- Using a pre-built system uses less of the pad area and uses only one site and mobilization/demobilization route on and off the pad for the fluid pumping unit. This allows a smaller footprint for the fluid pumping unit.
- A permanently installed system as described above can eliminate spills of treating fluid that can occur during disassembly of ordinary treatment fluid equipment that is disconnected from the wellhead at the end of pumping operations when wells are treated one at a time.
- A permanently installed system using the manifold-to-wellhead connection in the present example makes use of formed flow conduits to allow close spacing of wellheads without the congestion of multiple layers of temporary piping present in ordinary treatment fluid equipment that is disconnected from the wellhead at the end of pumping operations. A consistent, well known manifold arrangement will also eliminate mistakes in fluid routing since the location of valves, lines, and sensors does not change from job to job.
- Multiple flow distribution piping along the manifold allows routing of fluids through the least restricted or lowest pressure paths and enables switching and isolating paths if a malfunction occurs in distribution control devices, or higher rates are needed for particular applications. By having multiple paths available to the operator, pressure losses and wear in equipment can be reduced. This can be a benefit to both operating safety and environmental risk exposure.
- Permanently instrumenting the manifold lines (24, 26 in
FIG. 2 ) to monitor, pressure, temperature, erosion, fatigue and corrosion can further reduce the risk of spills and surface escape of fluids or pressure. Permanent sensors allow more secure transmission of data during pumping operations allowing for fewer instances of data feed interruption and more precise control of the fluid pumping operation. These features greatly increase safety and environmental protection of the site. - The manifold can be hooked up to elevated wellheads, wellheads disposed in protective “houses”, low profile wellheads disposed in a “cellar”, or standard height wellheads. The connection may be made using flexible hoses, formed connectors, chicksans or conventional piping without the need to move the manifold lines (24, 26 in
FIG. 1 ). - The state of the art of plumbing wells for fracturing prior to the present invention has certain limitations. When multiple wells are available, there are certain significant advantages in customizing a well layout and piping system to reduce the cost of hydraulic fracturing on multiple wells. The present invention incorporates many novel features to possibly avoid problems in using prior art designs and promote trouble free hydraulic fracturing operations. The present invention can reduce or eliminates the non productive time in the completion operation by making other wells on the pad immediately available for stimulation in case of one well encountering a problem.
- On wells with multiple stimulations with proppant there can be serious erosion problems in the piping along the fluid movement route from the stimulation pumpers to the wellhead. Some of the contributing factors to erosion such as velocity and change in velocity are directly impacted by the design of the piping geometry. The fracture treatment distribution system of the present invention can minimizes fluid velocity and therefore reduces erosion by increasing the pipe diameter throughout the manifold design. It also minimizes changes to the fluid velocity in two ways: First, the entire manifold is designed with a minimum of pipe diameter changes (i.e., the change in direction of the fluid flow is minimized by the design of the manifold). Second, where the velocity changes cannot be avoided, the area downstream of the velocity change is designed for higher erosion resistance.
- While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.
Claims (9)
1. A system for distributing fluid to a plurality of wellbores drilled from a common pad, comprising:
at least two fluid conduits extending between the wellbores, the fluid conduits configured to couple at one end to at least one fluid pump;
at least one remotely operable valve hydraulically connected to each fluid conduit proximate each wellbore;
at least one flow line hydraulically connecting each remotely operable valve to each wellbore such that fluid moved through the flow line enters the wellbore; and
a control unit disposed proximate the pad and configured to operate the remotely operable valves.
2. The system of claim 1 further comprising a valve at one end of each fluid conduit.
3. The system of claim 1 further comprising at least one erosion sensor disposed at a selected position along each fluid conduit, the at least one erosion sensor in signal communication with the control unit.
4. The system of claim 1 further comprising at least one erosion sensor disposed at a selected position along each flow line, the at least one erosion sensor in signal communication with the control unit.
5. The system of claim 1 further comprising a flow rate sensor disposed in each flow line, the flow rate sensors in signal communication with the control unit.
6. The system of claim 1 further comprising at least one additional valve in each flow line disposed between the at least one remotely operable valve and the wellbore.
7. The system of claim 1 wherein the at least one additional valve is remotely operable.
8. A method for operating a plurality of wellbores drilled from a common pad, wherein the wellbores include at least two fluid conduits extending between the wellbores, the fluid conduits configured to couple at one end to a fluid pump; at least one remotely operable valve hydraulically connected to each fluid conduit proximate each wellbore, a flow line hydraulically connecting each remotely operable valve to each wellbore such that fluid moved through the flow line enters the wellbore, and a control unit disposed proximate the pad and configured to operate the remotely operable valves, the method comprising:
moving a wellbore intervention device to a selected one of the wellbores;
communicating a signal from the control unit to close the remotely operable valves associated with the selected wellbore;
inserting at least one wellbore instrument into the selected one of the wellbores using the intervention device;
communicating a signal from the control unit to open at least one of the remotely operable valves at least one other wellbore; and
pumping fluid into ones of the at least two conduits associated with the opened remotely operable valves such that fluid enters the at least one other wellbore.
9. The method of claim 8 wherein the fluid is hydraulic fracturing fluid.
Priority Applications (6)
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US12/631,834 US20110030963A1 (en) | 2009-08-04 | 2009-12-06 | Multiple well treatment fluid distribution and control system and method |
EP10805926A EP2462314A1 (en) | 2009-08-04 | 2010-09-24 | Multiple well treatment fluid distribution and control system and method |
AU2010281281A AU2010281281B2 (en) | 2009-08-04 | 2010-09-24 | Multiple well treatment fluid distribution and control system and method |
PCT/CA2010/001526 WO2011014967A1 (en) | 2009-08-04 | 2010-09-24 | Multiple well treatment fluid distribution and control system and method |
CA2769774A CA2769774C (en) | 2009-08-04 | 2010-09-24 | Multiple well treatment fluid distribution and control system and method |
US13/006,283 US8656990B2 (en) | 2009-08-04 | 2011-01-13 | Collection block with multi-directional flow inlets in oilfield applications |
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US23125209P | 2009-08-04 | 2009-08-04 | |
US12/631,834 US20110030963A1 (en) | 2009-08-04 | 2009-12-06 | Multiple well treatment fluid distribution and control system and method |
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US13/006,283 Continuation-In-Part US8656990B2 (en) | 2009-08-04 | 2011-01-13 | Collection block with multi-directional flow inlets in oilfield applications |
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US12/631,834 Abandoned US20110030963A1 (en) | 2009-08-04 | 2009-12-06 | Multiple well treatment fluid distribution and control system and method |
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EP (1) | EP2462314A1 (en) |
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US20130233560A1 (en) * | 2012-03-09 | 2013-09-12 | Andy Lee Davidson | Remotely operated system for use in hydraulic fracturing of ground formations, and method of using same |
WO2014160601A1 (en) * | 2013-03-27 | 2014-10-02 | Fts International Services, Llc | Frac pump isolation safety system |
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US9453380B2 (en) | 2013-02-26 | 2016-09-27 | Halliburton Energy Services, Inc. | Remote hydraulic control of downhole tools |
WO2016167764A1 (en) * | 2015-04-15 | 2016-10-20 | Halliburton Energy Services, Inc. | Remote hydraulic control of downhole tools |
WO2016182708A1 (en) * | 2015-05-08 | 2016-11-17 | Schlumberger Technology Corporation | Multiple wellbore perforation and stimulation |
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Also Published As
Publication number | Publication date |
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EP2462314A1 (en) | 2012-06-13 |
CA2769774C (en) | 2013-11-19 |
AU2010281281B2 (en) | 2013-12-12 |
WO2011014967A1 (en) | 2011-02-10 |
CA2769774A1 (en) | 2011-02-10 |
AU2010281281A1 (en) | 2012-02-09 |
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