MULTIPLE WELL TREATMENT FLUID DISTRIBUTION AND CONTROL SYSTEM AND METHOD

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

CROSS-REFERENCE TO RELATED APPLICATIONS

Priority is claimed from U.S. Provisional Application No. 61/231,252 filed on Aug. 4, 2009.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND OF THE INVENTION

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.

SUMMARY OF THE INVENTION

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.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows schematically an example treatment fluid distribution system.

FIG. 2 shows a more detailed view of a wellhead shown in FIG. 1.

DETAILED DESCRIPTION

An example well treatment fluid distribution and control system is shown schematically in FIG. 1. The system 11 may be hydraulically connected to a plurality of wells drilled through subsurface rock formations from a common “pad” or platform 10. The pad 10 is arranged such that the surface locations of the wellbores are proximate each other. The pad 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 the wellhead 12 will be shown in more detail and explained further below with reference to FIG. 2. The example shown in FIG. 1 includes wellheads 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 the pad 10 from a main control valve 22 disposed at one end of the first manifold line 24 substantially to the longitudinal position of a furthest wellhead 12 on the pad 10. Similarly, a second fluid manifold line 26 may extend from a main control valve 22 at one end to the longitudinal position of the furthest wellhead 12. During fluid treatment operations, a pumping unit 28 may be disposed at one end of the pad 10 as shown. Typically, the pumping unit 28 will be removed from the pad 10 at times when fluid treatment operations are not underway. During such times, the main control valves 22 will be closed, and the ends of the first 24 and second 26 manifold lines may be hydraulically closed by closing the main control valves 22. Although not shown in FIG. 1, the manifold lines 24, 26 may be assembled from segments (“joints”) of conduit or tubing. The interconnection between joints may be any type known in the art including, without limitation, flanges, threads, hammer unions and welding. The manifold lines 24, 26 preferably extend from proximate one end of the pad 10 (to enable coupling to the pumping unit 28) to a position proximate the most distant one of the wellheads 12. The pumping 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 each manifold line 24, 26 to provide at least one fluid outlet to each wellhead 12 from each manifold line 24, 26. Thus, each of the two manifold lines 24, 26 will have an individual hydraulic connection to each wellhead 12. Connection from the fluid coupling 20 in the first manifold line 24 to the wellhead 12 may be obtained using a first remotely operable control valve 18, and for safety and backup purposes a first manually operated control valve 16 coupled to the wellhead through a first treatment fluid flow line 14. The first remotely operable 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, the manual control valves 16 may also be remotely operable. It is only necessary for purposes of the invention to have one remotely operable valve between the manifold line 24 and the wellhead 12. The first 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 the first 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 each wellhead 12 through a fluid coupling 20 and corresponding second remotely operable valve 19, second manual valve 17 and second flow line 15. Each of the foregoing components may be similar in configuration to the respective first remotely operable valves 18, manual valves 16 and flow lines 14. The second remotely operable valves 19 and the first remotely operable valves 18 may be operated remotely from a control 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 remotely operable valves 18, 19 to be opened and closed remotely. As will be further explained below, the control unit 30 may also be configured to interrogate sensors in signal communication with the control 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 in FIG. 1 may enable selective pumping of fluid from the pumping unit 28 to any or all of the wellbores through the respective wellheads 12 by suitable operation of the remotely operable valves 18, 19. If a particular wellbore, for example, requires large fluid flow volume for the type of fluid treatment, then for such wellbore, both the first remotely operable valve 18 and the second remotely operable valve 19 may be opened. In the event of failure of a particular remotely operable valve, for example the first remotely operable valve 18, it is possible to pump fluid into the wellhead 12 through the second remotely operable valve 19. It is also possible to repair or replace individual remotely operable valves 18, 19 by closing the respective manual valve 16, 17, closing all the other remotely operable valves 18, 19 connected to the respective manifold line 24, 26 and the main control valve 22 associated with the respective manifold line so that pressure may be relieved therefrom.

FIG. 1 also shows a well intervention device 50, such as a coiled tubing unit, including a reel 52 and guide rollers 52 that enable coiled tubing 53 to be inserted into one of the wellbores through suitable pressure control equipment (not shown) coupled to the top of the wellhead 12. Other well intervention devices may include, without limitation, wireline units, snubbing units and workover rigs. The functions performed by the well intervention device 50 as they relate to the system 11 will be further explained below.

FIG. 2 shows one of the wellheads 12 in more detail, as well as several additional components of the fluid distribution and control system. The wellhead 12 may include master valves 34, 36 coupled to the top of the well casing 32. The casing 32 is shown extending into the subsurface from the wellhead 12 starting substantially vertically and then extending substantially horizontally in a reservoir formation 35. The casing 32 may have perforations 33 disposed at a selected position within the reservoir formation 35. The configuration of casing shown in FIG. 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 the wellhead 12 above the master valves 34, 36 using a spool 41. The spool 41 may be configured similarly to fluid coupling devices used for hydraulic fracturing operations known as “frac heads.” Hydraulic connections to the wellhead 12 from the manifold lines 24, 26 may be substantially as explained above with reference to FIG. 1. A valve 40 may be disposed above the spool 41 to enable the wellhead 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). The wellhead 12 may also include one or more wing valves 38 to enable coupling of the wellhead 12 to a production line (not shown) for delivery of produced fluid from the wellbore.

In the present example, the flow lines 14, 15 and the manifold lines 24, 26 may each include an erosion sensor 44 downstream of the bend in the flow lines 14, 15 or the coupling 20, respectively, or other places in the flow path as required. In other examples, wherein the manifold lines 24, 26 are assembled from joints as explained above, an erosion sensor 44 may be disposed proximate each connection downstream in the flow direction. The erosion 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 the respective flow line 14, 15 or manifold line 26, 28. The 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 in FIG. 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 the flow lines 14, 15 or the 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 the flow lines 14, 15 and/or at selected positions along each of the manifold lines 24, 26. The pressure and/or temperature sensors 45 may be in signal communication with the control unit (30 in FIG. 1) using cable or wireless connection, as is the case for the erosion 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 to particular 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 the flow lines 14, 15, or at selected positions along each manifold line 24, 26. The flow rate sensors may also be in signal communication with the control unit (30 in FIG. 1) by wireless or cable connection.

Returning to FIG. 1, it is possible using the system 11 to perform fluid pumping into one or more wellbores while the well 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 remotely operable valves 18, 19 associated with the wellbore having the intervention device 50 working thereon may be closed. Another one or more of the wellbores may have the remotely operable valves 18, 19 opened by a control signal from the control unit 30. Fluid may be pumped into the wellbore(s) having the opened remotely operable valves 18, 19 by the 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 the pumping unit 28 is relieved. It is possible to move the intervention device 50 from wellbore to wellbore without the need to move the pumping unit 28 or the need to move or physically disconnect any part of the system 11 from the wellheads 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

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.