SYSTEMS AND METHODS FOR REDUCING PVT EFFECTS DURING PRESSURE TESTING OF A WELLBORE FLUID CONTAINMENT SYSTEM

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

1. Field of the Disclosure

The disclosure relates generally to systems and methods for conducting a pressure test of wellbore system equipment. More particularly, the disclosure relates to systems and methods for mitigating pressure-volume-temperature (PVT) effects that take place while pressure testing wellbore fluid containment system equipment such as blowout preventers (BOPs), choke and kill lines, wellhead hangers, casing, liner and liner hangers, tubing hangers, completions and other equipment.

2. Background of the Technology

In drilling for oil and gas from a hydrocarbon producing well, a well or well system is provided that includes a drilling rig with a riser section and a drill string used to convey drilling fluid down the drill string and through a wellhead to a drill bit disposed within a wellbore of a formation. The fluid recirculates from the drill bit back to the drilling rig via an annulus formed between the drill string and walls of the wellbore, and via the annulus formed between the drill string and the riser section that encircles it. A wellbore or formation fluid influx, also called a “kick”, can cause an unstable and unsafe condition at the drilling rig. When a kick is detected, a fluid containment system of the well system may be actuated and steps may be taken to “kill” the well and regain control. The fluid containment system includes all critical sealing points, including the BOP and its associated rams, the choke and kill lines and their associated valves, the choke and kill manifolds, an internal BOP (IBOP).

Due to the criticality of the functional operation of the fluid containment system with regard to containing and managing fluid pressurizations within the well system, periodic testing of each component (e.g., BOP, choke and kill lines, etc.) and each sealing element of the fluid containment system is important. Per current U.S. federal regulations, pressure testing of the fluid containment system must be conducted upon installation and before 14 days have elapsed since the last BOP pressure test. For instance, each ram of the BOP and each valve of the choke and kill lines must be individually pressure tested to properly comply with current regulations. Low and high pressure tests must be conducted for each individual component, and each component and sealing element must demonstrate that it holds a reasonably stable pressure. For instance, in practice a pressure decay rate of 4 pounds per square inch (psi) per minute or less is seen as reasonably stable.

Even though a fluid containment system component need only demonstrate pressure holding capability for five minutes to pass a presently-required pressure test, conducting the individual tests often take much longer due to PVT effects that take place due to the pressurizing of the test fluid. Specifically, for fluids (e.g., drilling fluid, completion fluid, etc.), an increase in pressure of the fluid will result in an increase of temperature of the fluid, while a decrease in temperature of the fluid will correspondingly result in a decrease in pressure of the fluid. The temperature of the testing fluid increases during pressurization due to heat generated by friction during the pumping of the fluid by a cementing unit, mud pump, or either types of high pressure pumps. For instance, heat generated by pistons of a triplex pump as they reciprocate may be transferred to the pressurized testing fluid. For this reason, testing fluid pumped into the fluid containment system may feature a larger temperature increase than fluid already disposed in the system, which is pressurized by the injection into the system of the pumped-in testing fluid. Referring to FIG. 1, graph 200 illustrates fluid pressures in relation to time at different positions along a vertically-oriented subsea drill string during a pressure test. Pressure curve 110 illustrates the fluid pressure at a point within the drill string near the sea floor, with curves 130, 120 and 110 illustrating fluid pressure at progressively shallower points along the drill string, with curve 110 illustrating fluid pressure at the shallowest point, near the surface of the water. Due to being located at different vertical depths along the drill string, curve 110 is at the highest pressure, while curve 140 is at the lowest pressure of the curves. As shown in FIG. 1, the pressure test can be divided into three phases: a pumping phase (112, 122, 132 and 142), a shut-in phase (114, 124, 134 and 144) and a depressurization phase (116, 126, 136 and 146). The pumping phase takes places when testing fluid is pumped into the well system in order to pressurize the fluid containment system. Testing fluid may be pumped into the drill string by a cementing unit or mud pump disposed at the drilling rig. Once the well system has been pressurized to the testing pressure, pumping ceases and the well system is shut-in, such that a portion of the well system containing the system components to be tested is isolated from the outside environment. Shut-in phases 114, 124, 134 and 144 have a beginning (114a, 124a, 134a and 144a) and an ending (114b, 124b, 134b and 144b). As shown by FIG. 1, the pressure at the beginning 114a, 124a, 134a and 144a exceeds the pressure at the end 114b, 124b, 134b and 144 of the shut-in phase. Further, the difference in pressure between beginning 144a and ending 144b is greater than the difference in pressures between 114a and 114b, due to curve 140 being at a shallower point along the drill string. Also, in this pressure test, shut-in phases include a pressurization point (114c, 124c, 134c and 144c) where additional testing fluid is pumped into the well system to slightly increase the pressure within the system. Additional fluid may be pumped in during the shut-in phase to raise the pressure within the well system to a level similar to that existing near the beginning of the tests, at points 114a, 124a, 134a and 144a.

Referring to FIG. 2, graph 200 illustrates fluid temperatures in relation to time at different positions along the vertically oriented subsea drill string during a pressure test. Temperature curve 210 is generated by temperature sensors positioned at the same vertical position along the drill string as the pressure sensors generating pressure curve 110, curve 220 is generated by temperature sensors positioned at the same position as curve 120, etc. Temperature curve 240, at the shallowest position along the drill string, displays the greatest downward slope of the curves 210, 220, 230 and 240. The greater slope of temperature curve 240 is due to being in closer proximity to the testing fluid that has been pumped into the well system for the purpose of pressurization. For instance, heat from the testing fluid pumped into the well system during the pumping phase may transfer to proximal fluid at the position of temperature curve 240, resulting in a greater difference in temperature between testing fluid within the drill string at the position of sensors generating curve 240 and ambient water surrounding the drill string at that point, which cools the testing fluid within the drill string following pressurization. Referring to FIGS. 1 and 2, the greater decrease in temperature along curve 240 provides for the greater decrease in pressure during shut-in phase 144 of pressure curve 140. Specifically, the greater drop in temperature of fluid of curve 240 results in more PVT effect driven pressure decay during shut-in phase 144.

During the performance of the pressure test, an analog and low resolution circular chart reader may be used by drilling personnel on the drilling rig to observe a continuous pressure recording of the fluid containment system. Even in cases where the fluid containment system component being tested is not leaking, the pressure test often lasts over half an hour before the pressure within the fluid containment system begins to stabilize enough such that a five minute period of successful pressure stabilization may be recorded. Further, due to pressure decay caused by PVT effects and the low resolution of the chart recorder, pressure tests are sometimes judged as successful before full stabilization (e.g., decay of 4 psi/min or less, as is a typical current standard in certain jurisdictions), thus allowing for the risk that the remaining pressure decay may be due to a leak, in addition to PVT effects. In practice, this phenomenon is especially impactful at higher testing pressures as are required in deeper wells and where synthetic oil based mud (SOBM) is used as the testing fluid.

Accordingly, there remains a need in the art for systems and methods that allow for quick and effective pressure testing of well system equipment, such as a fluid containment system. Further, it would be advantageous if such systems and methods would mitigate the PVT effects that take place during a pressure test of well system equipment. Still further, it would be advantageous to provide a system that includes a means providing a continuous pressure signal with a relatively high resolution.

BRIEF SUMMARY OF THE DISCLOSURE

Disclosed herein is a system for pressure testing a component of a well system that includes a tubular member that extends into a wellbore penetrating a subterranean formation. The tubular member has a first fluid passageway and one or more nodes that are configured to measure fluid pressure and are coupled to the tubular member. The system also includes a heat exchanger having a second fluid passageway and is configured to cool a fluid passing through the second passageway. Further, the system includes a fluid flowpath that includes at least a portion of the first fluid passageway and at least a portion of the second fluid passageway. In an embodiment, the tubular member comprises a drill string. In another embodiment, the tubular member comprises a production riser. In an embodiment, the system further includes a pump in fluid communication with the fluid flowpath. In this embodiment, the pump is configured to pressurize the cooled fluid to produce a pressurized fluid. The pressurized fluid has a temperature that is substantially equal to the temperature of the first volume of fluid. In an embodiment, the system further includes a test plug disposed within the tubular member.

Also disclosed herein is a method for pressure testing a component of a well system that includes producing a cooled fluid by cooling a first volume of fluid having a first pressure. The cooled fluid is flowed into a closeable chamber of the well system and shut in to the chamber. Pressure in the chamber is measured using nodes distributed within the chamber. In an embodiment, flowing the cooled fluid into the chamber comprises pressurizing the cooled fluid to produce a pressurized fluid having a second pressure that is greater than the first pressure of the first volume of fluid. In an embodiment, pressurizing the cooled fluid to produce a pressurized fluid includes pressurizing the cooled fluid to a temperature that is substantially equal to the temperature of the first volume of fluid. In an embodiment, pressurizing the cooled fluid to produce a pressurized fluid includes pressurizing the cooled fluid to a temperature that is less than the temperature of the first volume of fluid. In an embodiment, the method further includes determining the presence of a leak within the closeable chamber by monitoring the pressure measurement. In an embodiment, cooling the fluid to produce the cooled fluid comprises flowing the first volume of fluid through a heat exchanger.

Embodiments described herein comprise a combination of features and characteristics intended to address various shortcomings associated with certain prior devices, systems, and methods. The various features and characteristics described above, as well as others, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the exemplary embodiments of the invention disclosed herein, reference will now be made to the accompanying drawings in which:

FIG. 1 is a graph illustrating pressure curves generated during a pressure test of a drilling system;

FIG. 2 is a graph illustrating temperature curves generated during a pressure test of a drilling system;

FIG. 3 is a schematic view of an embodiment of a drilling system in accordance with principles described herein;

FIGS. 4A-4D are perspective views, some in cross-section, showing components of the downhole electromagnetic network shown in FIG. 3;

FIG. 5 is a schematic view of a heat exchanger employed in the drilling system shown in FIG. 3;

FIG. 6 is a schematic of the testing fluid system shown in FIG. 3;

FIG. 7 is a schematic showing the drilling system shown in FIG. 3 configured to conduct a fluid containment system pressure test;

FIG. 8A is a graph illustrating pressure curves generated during a pressure test of the BOP pressure testing application shown in FIG. 7;

FIG. 8B is a graph illustrating temperature curves generated a pressure test of the BOP pressure testing application shown in FIG. 7;

FIG. 9 is a schematic showing the drilling system shown in FIG. 3 configured for conducting a pressure test of a completion system; and

FIG. 10 is a schematic of a production system configured for pressure testing in accordance with principles described herein.

DETAILED DESCRIPTION

The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.

In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a given axis (e.g., given axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the given axis. For instance, an axial distance refers to a distance measured along or parallel to the given axis, and a radial distance means a distance measured perpendicular to the given axis. Still further, as used herein, the phrase “communication coupler” refers to a device or structure that communicates a signal across the respective ends of two adjacent tubular members, such as the threaded box/pin ends of adjacent pipe joints; and the phrase “wired drill pipe” or “WDP” refers to one or more tubular members, including drill pipe, drill collars, casing, tubing, subs, and other conduits, that are configured for use in a drill string and include a wired link. As used herein, the phrase “wired link” refers to a pathway that is at least partially wired along or through a WDP joint for conducting signals, and “communication link” refers to a plurality of communicatively-connected tubular members, such as interconnected WDP joints for conducting signals over a distance.

A system and method for pressure testing a well system is disclosed herein. Embodiments described herein may be employed in various well system applications; however, it has particular application as a system and method for mitigating PVT effects during the pressure testing of various elements of the fluid containment system, such as the BOPs, casing, Christmas tree, tubing hangers, etc. Further, it has particular application with regard to offshore well systems.

Referring now to FIG. 3, a well or drilling system 10 generally includes an offshore semi-submersible well system rig 20 at the water line 12 having a testing fluid system 21 disposed thereon. In other embodiments, rig 20 may comprise other varying types of offshore platforms, such as drilling ships, submerged platforms, etc. System 10 further includes a marine riser 30 that extends between the rig 20 and a wellhead 60 disposed at the sea floor 14, a fluid containment system 40, a drill string 50 disposed within riser 30 and having a central axis 55 and an internal fluid passageway 50a, and a casing 70 supported by cement 72.

An annulus 35 is formed between drill string 50 and riser 30 and allows for the recirculation of drilling fluid to rig 20 from a wellbore 62 formed in the subterranean formation 16. A fluid containment system comprises several components configured to retain and manage pressure within drill string 50 and annulus 35. In the embodiment of drilling string 10, fluid containment system 40 includes BOP 41, choke line 44, kill line 46 and an internal BOP (IBOP) 48. Rams 42 of BOP 41 are configured to provide an annular seal 43 upon actuation, dividing annulus 35 into an upper section 35a extending between rig 20 and seal 43 and a lower section 35b extending from seal 43 downward into the wellbore 62. During drilling, a high pressure volume of fluid from the formation 16 may flow into wellbore 62 and travel upward through annulus 35. This formation “kick” may be isolated within lower section 35a of annulus 35 via actuating one or more rams 42, providing the annular seal 43. Choke line 44 and kill line 46 provide for alternate routes of fluid communication between rig 20 and the portion of annulus 35 disposed below BOP 41.

During a formation kick, high pressure fluid from the formation may be circulated upward through choke line 44 to the rig 20, in order to reduce the pressure of the formation fluid within the annulus 35. Choke line 44 comprises a lower valve 44a, a manifold 44b and an upper valve 44c. Also, each valve (lower 44a and upper 44b) may include an inner and outer valve, with each valve being individually pressure tested. Fluid flow through choke line 44 may be restricted by closing lower valve 44a or upper valve 44c. Further, choke manifold 44b comprises one or more valves and chokes and is configured to manage and regulate flow through choke line 44. Because successful control of a formation kick may depend on the effective operation of choke line 44 and its components, valves 44a, 44c and manifold 44b are pressure tested during the pressure testing of fluid containment system 40. Kill line 46 is also used to manage a formation kick by allowing for circulation between annulus 35 and rig 20. Kill line 46 is used to pump high density drilling mud or other fluid downward from rig 20 to the annulus 35 to circulate the formation influx out of the wellbore 62. Thus, a kill line such as kill line 46 may be used to “kill” the well by stopping or at least substantially restricting the flow of fluid from the formation into the wellbore 62 by pumping heavy fluid into annulus 35 from the rig 20. Kill line 46 comprises a lower valve 46a, a kill manifold 46b and an upper valve 46c. As with choke line 44, flow through kill line 46 may be substantially restricted or controlled via valves 46a, 46c and manifold 46b. Thus, during pressure testing of fluid containment system 40, valves 46a, 46c and manifold 46b are pressure tested as well.

IBOP 48 is disposed at an upper end 50b of drill string 50 at the rig 20 and is configured to manage fluid pressure within drill string 50. For instance, during a formation kick, high pressure formation fluid may begin flowing upward through string 50 via an opening or port of the string 50 disposed within wellbore 62. IBOP 48 may restrict the flow of fluid out of drill string 50 at upper end 50b. Thus, because IBOP 48 may be used in effectively controlling a formation kick, IBOP 48 is pressure tested during the pressure testing of fluid containment system 40.

Referring now to FIGS. 3, 4A-4D, drill string 50 comprises a plurality of nodes 51 having sensors 57 coupled between a plurality of pipe joints 52. Wired or networked drill pipe incorporating distributed sensors can transmit data from anywhere along the drill string 50 to the rig 20 for analysis. Nodes 51 are provided at desired intervals along the drill string 50. Network nodes 51 essentially function as signal repeaters to regenerate and/or boost data signals and mitigate signal attenuation as data is transmitted up and down the drill string. The nodes 51 may also include measurement assemblies. The nodes 51 may be integrated into an existing section of drill string or a downhole tool along the drill string 50. For purposes of this disclosure, the term “sensors” is understood to comprise sources (to emit/transmit energy/signals), receivers (to receive/detect energy/signals), and transducers (to operate as either source/receiver). Pipe joints 52 include a first pipe end 53 having, for example, a first induction coil 53a and a second pipe end 54 having, for example, a second induction coil 54a.

Nodes 51 comprise a portion of a downhole electromagnetic network 56 that provides an electromagnetic signal path that is used to transmit information along the drill string 50. The downhole network 56, or broadband network telemetry, may thus include multiple nodes 51 based along the drill string 50. Communication links 52a may be used to connect the nodes 51 to one another, and may comprise cables or other transmission media integrated directly into sections of the drill string 50. The cable may be routed through the central borehole of the drill string 50, or routed externally to the drill string 50, or mounted within a groove, slot or passageway in the drill string 50. Preferably signals from the plurality of sensors along the drill string 50 are transmitted to a remote location (e.g., rig 20) through a wire conductor 52a along the drill string 50. Communication links 52a between the nodes 51 may also use wireless connections. A plurality of packets may be used to transmit information along the nodes 51. Further detail with respect to suitable nodes, a network, and data packets are disclosed in U.S. Pat. No. 7,207,396 (Hall et al., 2007), hereby incorporated in its entirety by reference.

Various types of sensors 57 may be employed along the drill string 50 in various embodiments, including without limitation, axially spaced pressure sensors, temperature sensors, and others. The sensors 57 may be disposed on the nodes 51 positioned along the drill string, disposed on tools incorporated into the string of drill string, or a combination thereof. The downhole network 56 transmits information from each of a plurality of sensors 57 to a surface computer 58. In some embodiments, the sensors 57 are annular pressure sensors.

Rig 20 includes a well site computer 58 that may display information for the drilling operator. Information may also be transmitted from computer 58 to another computer 59, located at a site remote from the well, with this computer 59 allowing an individual in the office remote from the well to review the data output by the sensors 57. Although only a few sensors 57 are shown in the figures, those skilled in the art will understand that a larger number of sensors may be disposed along a drill string when drilling, and that all sensors associated with any particular node may be housed within or annexed to the node 51, so that a variety of sensors rather than a single sensor will be associated with that particular node.

Due to safety concerns and to minimize the impact of a wellbore influx, it is important to detect and contain the influx as soon as possible. In some circumstances, the BOPs are actuated and isolate the well at the onset of a formation influx. In some cases, for example in deepwater wells, the wellbore influx may migrate above the BOP 41 at the time the BOP's rams are closed. In the embodiments herein, downhole distributed measurements and the high speed broadband telemetry system allow wellsite personnel to identify potential remedial actions for the migrated wellbore influx. In some embodiments, the measurements used are independent from surface measurements.

Referring again to FIG. 3, booster assemblies and network nodes 51 are disposed along the drill string 50. In some embodiments, the booster assemblies are spaced at 1,500 ft. (500 m) intervals to boost the data signal as it travels the length of the drill string 50 to prevent signal degradation. Network nodes 51 are also located at these intervals to allow measurements to be taken along the length of the drill string 50. The distributed network nodes 51 provide measurements that give the driller additional insight into what is happening along the potentially miles-long stretch of the drill string 50.

Well system rig 20 comprises a rig floor 22, a derrick 24 extending from the floor 22. Testing system 21 is disposed at rig floor 22 and comprises a mud pit 25, one or more heat exchangers 26a, 26b, a cementing unit 27 and a fluid conduit 28. Conduit 28 provides a fluid flowpath for a testing fluid 29 from mud pit 25, through heat exchangers 26a, 26b and cementing unit 27 to the passageway 50a of drill string 50. Testing fluid 29 comprises a high density and high weight fluid (e.g., drilling fluid, SOBM, completion fluid, etc.) relative to ambient water 13 disposed below water line 12. For instance, fluid 29 has a relatively higher density than fluid from formation 16.

Referring to FIG. 5, a schematic of heat exchanger 26a is shown. In the example shown in FIGS. 3, heat exchangers 26a, 26b are shell and tube heat exchangers having a tube side fluid passageway 26c and a shell side fluid passageway 26d with two tube sheets 26e that create a seal between tube side 26c and shell side 26d. Testing fluid 29 enters shell side passageway 26c via port 26f, flows through a plurality of tubes 26g, and exits via port 26i. Also, heat exchanger 26b is substantially identical to heat exchanger 26a in structure.

Chilled water 26i enters tube side 26d via port 26j, follows a deviated flowpath around internal baffles 26k, and exits via port 26l. While water 26i flows through shell side 26d, water 26i contacts the outer surfaces of the plurality of tubes 26g, allowing for heat to transfer out of the testing fluid 29 disposed within tubes 26g and into the chilled water 26i. Thus, due to this heat transfer between testing fluid 29 and water 26i, the testing fluid 29 entering port 26f is at a higher temperature than the testing fluid 29 exiting port 26fh, and the chilled water 26i entering port 26j is at a lower temperature than the water 26i exiting port 26l. The amount of temperature drop between testing fluid 29 entering port 26f and testing fluid 29 exiting port 26h is a function of the temperature of the chilled water 26i as it enters port 26j, the mass flow rate of water 26i, and the mass flow rate of the testing fluid 29. For instance, increasing the mass flow rate of chilled water 26i entering heat exchanger 26a will increase the temperature drop of the testing fluid 29 as it flows through the heat exchanger. Also, increasing the mass flow rate of the testing fluid 29 will decrease the temperature drop in the fluid 29 as it passes through heat exchanger 26a.

In the embodiment illustrated in FIG. 5, chilled water 26i enters port 26j at approximately 35° F. and exits port 26l at approximately 39° F. Testing fluid 29 enters port 26f at approximately 90° F. and exits port 26h at approximately 68° F., forming a cool fluid. In other embodiments, chilled water 26i may enter port 26j at other temperatures, and testing fluid 29 may enter port 26f at other temperatures. Further, in other embodiments, water 26i may comprise other fluids suitable for transferring heat out of testing fluid 29 as the two fluids flow through heat exchanger 26a. In other embodiments, heat exchangers 26a. 26b may be another style of heat exchanger, such as a plate, a plate and fin, a phase change, an air coil and other types of heat exchangers.

Referring now to FIG. 6, a schematic of testing fluid system 21 is shown. In this embodiment of testing fluid system 21, a first volume of testing fluid flows from mud pit 21 through heat exchanger 26a to cementing unit 27. Testing fluid 29 may be circulated to mud pit 25 from wellbore 62 via riser 30 (FIG. 3). Testing fluid 29 has a temperature T₁as it flows from mud pit 25 to heat exchanger 26a. Fluid 29 at this point has yet to be pressurized and thus temperature T₁is at an ambient level with respect to the surrounding environment. A cooled fluid is formed via passing testing fluid 29 through heat exchanger 26a, cooling fluid 29 to a temperature T₂, which is cooler than the temperature T₁. In this example, T₁is approximately 90° F. while T₂is approximately 68° F. After passing through heat exchanger 26a, testing fluid 29 enters cementing unit 27. Cementing unit 27 comprises a high pressure pump suitable for forming a pressurized fluid via pressurizing test fluid 29 from ambient pressure to pressures ranging from 5,000-12,000 pounds per square inch (psi). In this embodiment, cementing unit 27 comprises a triplex reciprocating pump that pressurizes fluid 29 between approximately 8,000-12,000 psi. Due to PVT effects, the pressurization of fluid 29 by unit 27 increases the temperature of fluid 29 from temperature T₂to a higher temperature T₃. In this embodiment, the pumping action of cementing unit 27 increases the temperature of the testing fluid 29 by approximately 22° F., and thus temperature T₃is approximately 90° F. or ambient with respect to the surrounding air temperature. Also, the pressurized testing fluid at temperature T₃is approximately equal in temperature as the first volume of fluid at temperature T₁. Thus, the configuration of heat exchanger 26a and cementing unit 27 results in a pressurized testing fluid 29 at approximately 10,000 psi at an ambient temperature T₃of 90° F.

Referring still to FIG. 6, in an embodiment, second heat exchanger 26b is provided downstream of cementing unit 27. As test fluid 29 passes through heat exchanger 26b, it decreases in temperature from temperature T₃to a temperature T₄of approximately 75° F. Heat exchanger 26b is configured to lower the temperature of the test fluid 29 to a temperature that is substantially equal to the ambient water 13 surrounding riser 30 (FIG. 3) at shallow depths. For instance, as testing fluid 29 is pumped into drill string 50, a portion of testing fluid 29 will be disposed within a segment of the drill string 50 that is below the water line 12. Because the temperature of the ambient water may 13 be cooler than the ambient air temperature, testing fluid 29 disposed below the water line 12 may be cooled to below ambient air temperature (e.g., cooled to 80° F.) in order to eliminate any substantial difference in the temperatures of the testing fluid 29 and the surrounding ambient water 13 below water line 12. Each temperature T₆-T_n, is measured at a corresponding depth from the water line 12. T₆is measured at depth 13a, T₇is measured at depth 13b and T_nis measured at depth 13n, where the depth of 13n is greater than the depth of 13a, 13b and 13c. Because the temperature of water 13 disposed at depth 13b is greater than the temperature of the water at 13a, the temperature of fluid 29 disposed at depth 13a is cooled to a greater extent than the fluid 29 disposed at depth 13b, etc. The amount of heat transferred out of fluid 29, as fluid 29 flows through heat exchangers 26a and 26b, is controlled via the pump rate of cementing unit 27, the temperature of water 26i as it enters heat exchangers 26a and 26b, and the flow rate of water 26i (FIG. 5) as it enters heat exchangers 26a and 26b.

While the testing fluid system 21 is shown in FIG. 6 as having two heat exchangers (26a and 26b), in other embodiments the testing fluid system of a well system may only have one heat exchanger disposed between a mud pit (e.g., mud pit 25) and a cementing unit (e.g., cementing unit 27). In that arrangement, the temperature of the testing fluid after pressurization by the cementing unit is substantially equal to the temperature of the fluid before it enters the heat exchanger. Thus, the temperature of testing fluid 29 entering drillstring 50 is substantially equal to the ambient air temperature. In other embodiments, two or more heat exchangers may be included in the testing fluid, depending on the amount of cooling required to have substantially equal temperatures between the first volume of testing fluid entering the first heat exchanger and the pressurized testing fluid entering the drill string.

Referring now to FIG. 7, drilling system 10 previously described with reference to FIG. 3, is shown configured for pressure testing fluid containment system 40. As shown, drill string 50 comprises a BOP test plug 49 that is coupled to an end of two adjacent pipe joints 52 and is disposed axially below BOP 41, proximal to wellhead 60. As shown in FIG. 7, test plug 49 is configured to prevent fluid within drill string 50 from flowing across plug 49. Test plug 49 also forms an annular seal 49a, preventing fluid flow within annulus 35 across test plug 49. A radial port or opening 45 is provided in the drillstring 50 to act as a route of fluid communication between drillstring 50 and the annulus 35 axially above testing plug 49. A ram 42 of BOP 41 may be actuated to form an annular seal, preventing fluid passing through port 45 from flowing upward through annulus 35 to the rig 20. Thus, annular seals 49a and 43 form a closable annular chamber 35c within riser 30. Pressure and temperature is continuously measured at different locations of annulus 35 is detected via nodes 51. For instance, pressure and temperature of fluid within chamber 35c is continuously measured via node 51a. The measurements taken by sensors 57 of nodes 51 are continuously transmitted to rig 20 via electromagnetic downhole network 56.

In the example of FIG. 7, fluid containment system 40 is filled with high density testing fluid 29 (e.g., mud, water based drilling fluid, SOBM, completion brine, etc.) at a relatively low pressure. Pressure within drillstring 50 and annular chamber 35c of annulus 35 is increased to the required BOP testing pressure by injecting a volume of testing fluid 29 into drillstring 50. Testing fluid 29 is pumped via cementing unit 27 into drill string 50 via fluid flowpath 29a that comprises mud pit 25, passageway 26c of heat exchanger 26a, cementing unit 27, passageway 26c of heat exchanger 26b and passageway 50a of string 50. Before entering cementing unit 27, testing fluid 29 passes through the tube side of heat exchanger 26a (FIG. 5), chilling the testing fluid 29 to a temperature below the ambient air temperature at the rig 20. Testing fluid 29 is pressurized to approximately between 5,000-12,000 psi, increasing the temperature of testing fluid 29 to a temperature substantially equal to the ambient air temperature at rig 20. Following pressurization by cementing unit 27, testing fluid 29 flows through heat exchanger 26b, lowering the temperature of testing fluid 29 to a temperature substantially equal to the ambient water 13 temperature surrounding riser 30. A volume of testing fluid 29 is then displaced into drill string 50, pressurizing fluid within drill string 50 and the annular chamber 35c. In subsequent pressure tests of other elements of the fluid containment system 40, testing fluid 29 is also disposed within choke line 44 and kill line 46.

Referring now to FIGS. 8A and 8B, graphs of pressure and temperature of testing fluid 29 measured during the BOP pressure test of FIG. 7 are shown. Pressure graph 500 illustrates pressure curve 510 as measured by and transmitted from node 51a during the BOP pressure test illustrated in FIG. 7. As shown in FIG. 8A, pressure curve 510 comprises a pumping phase 512, a shut-in phase 514 having a beginning 514a and an end 514, and a depressurization phase 516. During pumping phase 512, testing fluid 29 is pumped into drillstring 50 via cementing unit 27, which in turn displaces a volume of fluid into chamber 35c, pressurizing the chamber 35c to the BOP testing pressure. Once pressure within chamber 35c has reached the BOP testing pressure, the beginning 514a of shut-in phase 514 takes place with the cessation of pumping from cementing unit 27, thus stopping the flow of testing fluid 29 into drillstring 50 at rig 20. As part of a BOP pressure test shown in FIG. 7, ram 42 must successfully hold the BOP test pressure for a specified period of time. In one example, ram 42 must hold 15,000 psi for a period of five minutes. Because the testing fluid 29 that is now disposed within drillstring 50 has been chilled via heat exchangers 26a and 26b, shut-in phase 514 of pressure curve 510 is stable with respect to time, varying to a lesser degree over time than the pressure curves shown in FIG. 1 where the testing fluid is not compensated for the temperature increase caused by heat being transferred into the fluid via the pressurization performed by a cementing unit or other pump type. Thus, shut-in phase 514 may have a relatively shorter duration than the shut-in phases shown in FIG. 1, as the requirement of holding the BOP test pressure (e.g., 10,000 psi) within chamber 35c for a specified amount of time (e.g., five minutes) will be satisfied more quickly due to the stability and continuity of the shut-in phase 514 of pressure curve 510 provided by mitigating and/or eliminating heat transfer out of the fluid following the pumping phase, allowing for a faster BOP pressure test.

Pressure within drillstring 50 and chamber 35c exhibits a stable shut-in phase 514 due to the testing fluid 29 having a stable temperature following pumping phase 512. For instance, referring to FIG. 8B, a temperature curve 610 of the temperature of fluid proximal to node 51a (FIG. 7) within chamber 35c is shown during the shut-in phase of the BOP pressure test. Temperature curve 610 exhibits a stable and near constant slope, thus eliminating or at least substantially reducing PVT related effects on the testing fluid 29 for the duration of the shut-in phase 514. Thus, any substantial fluctuation of pressure during shut-in phase 514 may be properly attributed to a leak within the fluid containment system 40, such as a leak within annular seal 43 provided by ram 42, rather than being caused by a decrease in temperature of testing fluid 29.

Referring back to FIG. 7, in addition to 7 ram 42 of BOP 41 being pressure tested, other components of fluid containment system 40 may be pressure tested in a similar manner. For instance, other individual rams of BOP 41 may be actuated to create an annular seal within annulus 35, forming a cavity defined by the ram's annular seal and the seal 49a produced by BOP test plug 49. Likewise, (inner and outer) lower valves 44a, 46a, manifolds 44b, 46b, and upper (inner and outer) valves 44c, 46c, of choke line 44 and kill line 46, respectively, may be pressure tested by placing nodes (e.g., nodes similar to nodes 51) within choke line 44 or kill line 46 in order to continuously measure and transmit pressure and temperature readings from lines 44, 46. In order to test the components of choke line 44 and kill line 46, high density testing fluid 29 is pumped through heat exchangers 26a and 26b, and into drillstring 50 via cementing unit 27. Ram 42 of BOP 41 may be actuated to create annular seal 43. However, instead of allowing fluid communication between choke line 44 and kill line 46 with chamber 35c, a component of lines 44, 46, may be sealed (e.g., lower valve 44a). In this embodiment, the sealed component (e.g., valve 44a) may be pressure tested to see if it holds the BOP test pressure for a requisite period of time (e.g., five minutes).

Referring now to FIG. 9, drilling system 10 previously described with reference to FIG. 3 is shown configured for pressure testing well completion system 80. Well completion system 80 generally includes wellhead 60, tubing hanger 82, tubing 84, casing 70 and cement 72. In this example, drillstring 50 has a lower terminal end 50c that couples to tubing hanger 82. Tubing hanger 82, disposed within wellhead 60, seals annulus 35 of riser 30 via annular seal 84a. Tubing 84 couples to tubing hanger 82 at terminal end 84a, and extends downward into wellbore 62. Tubing 84 is configured to act as a route of fluid communication between formation 16 and a production riser (not shown) that is installed following completion. Tubing hanger 82 physically supports tubing 80 and allows for a route of fluid communication between tubing 80 and drillstring 50. Further, annular seal 84a of hanger 82 prevents fluid within wellbore 62 from flowing upward and out of wellbore 62 via annulus 35. Casing 70 allows for selective fluid communication between wellbore 62 and formation 16. For instance, following the completion pressure tests, casing 70 is perforated at predetermined locations in wellbore 62 to provide routes of fluid communication with the formation 16 via the perforations.

Prior to installing the production system, well completion system 80 is pressure tested in order to ensure that completion 80 will not leak once fluid from formation 16 begins to flow into wellbore 62 and tubing 84 once production of hydrocarbons from formation 16 has commenced. As part of the pressure test, a radial port or opening 86 is provided within tubing 84 to allow for a route of fluid communication between tubing 84 and wellbore 62. Prior to the initiation of the completion pressure test, drillstring 50, tubing 80 and wellbore 62 are filled with high density testing fluid 29 (e.g., mud, SOBM, completion brine, etc.) at a relatively low pressure. Once filled, an additional volume of testing fluid 29 is pumped into drillstring 50 via conduit 28 and cementing unit 27. Testing fluid 29 is pumped from mud pit 25 where it is stored at ambient pressure and temperature (e.g., 90° F. and atmospheric pressure).

Testing fluid 29 passes through heat exchanger 26a prior to pressurization by cementing unit 27, and flows through a second heat exchanger 26b prior to entering string 650. Thus, testing fluid 29 is chilled to below the ambient air temperature to a temperature of approximately 68° F. prior to pressurization via cementing unit 27, which increases the pressure of fluid 29 from 5,000-12,000 psi, in this example. Due to PVT effects (e.g., friction from pumping), pressurization of fluid 29 results in a temperature increase of the pressurized fluid such that fluid 29 returns to ambient temperature (e.g., the temperature of the testing fluid 29 as it exits mud pit 25). Before entering drillstring 50, fluid 29 passes through heat exchanger 26b, reducing the temperature of fluid 29 to below the ambient air temperature to a temperature of approximately 80° F., in this example. Thus, the temperature of fluid 29 as it enters string 650 is substantially equal to the temperature of the water 13.

Although the temperature of the water 13 proximal to rig 20 may vary by depth, because only a relatively small volume of fluid 29 is pumped into drillstring 50, the pressurized fluid 29 may be reduced to a temperature heat exchanger 26b to a temperature substantially equal to the temperature of the water 13 at shallower depths (e.g., 0-500 feet below water line 12). Further, the pump rate of cementing unit 27 and the flow rate of chilled water 26g (FIG. 5) may be varied to vary the temperature of fluid 29 as it enters drillstring 50. The temperature of fluid 29 may be varied to match the temperature of the water 13 at the depth below water line 12 where that portion of fluid 29 will be disposed following the completion of pumping. For instance, a first portion of fluid 29 pumped into drillstring 50 may be cooled to a greater extent than a later portion of fluid 29, because the first portion will occupy a lower depth in drillstring 50, which is surrounded by relatively cooler water 13, while the later portion will occupy a shallower depth within drillstring 50, which is surrounded by relatively warmer water 13. Thus, by ensuring a relatively small temperature difference between the pumped in fluid 29, and the ambient water 13 disposed proximal to that fluid 29, heat transfer from between the ambient water 13 and the pumped in fluid 29 may be minimized.

Referring still to FIG. 9, as testing fluid 29 is pumped into drillstring 50, fluid within drillstring 50 is displaced out of opening 86 and into wellbore 62, pressurizing wellbore 62. Once wellbore 62 has reached a completion test pressure (e.g., 12,000 psi), pumping via cementing unit 27 is stopped and the completion pressure test enters a shut-in phase. During the shut-in phase of the pressure test, continuous pressure measurements may be taken and transmitted to rig 20 via nodes 51 and electromagnetic network 56. Sensors 57 of Nodes 51 continuously measure pressure within annulus 35 of riser 30 and within drillstring 50.

Referring now to FIG. 10, a well or production system 600 is shown. Production system 600 generally comprises rig 20, a production riser 630 having a central axis 635 and ends 630a and 630b, a Christmas tree 410 having an upper end 410a and a lower end 410b, and well completion system 80. Production riser 630 extends from upper end 630a at rig 20 to lower end 630b that is coupled to the first end 410a of Christmas tree 410. The second end 610b of Christmas tree 410 couples to wellhead 60. Fluid communication between fluid within formation 16 and production riser 630 is provided by tubing 84 disposed within wellbore 602. Production riser includes one or more nodes 51, which partly form electromagnetic network 56. Christmas tree 410 generally includes an assembly of valves, spools and other fittings.

During and/or at the onset of the production phase, the various sealing elements and components of Christmas tree 410 are pressure tested in order to ensure that production system 600 may contain a high pressure influx of fluid from formation 16. In this example, testing fluid 29 may be pressurized and injected into production riser 630 via testing fluid circuit 21 disposed at the rig 20. Christmas tree 410 may be isolated from the formation 16 via displacing a testing plug downward through production riser 630 such that the plug is disposed within wellhead 60, sealing tubing 84 from tree 410 and riser 630. Testing fluid 29 is then pumped into production riser 630, and a pressure test of Christmas tree 410 is conducted. This pressure test may be iterated for every individual sealing element and component of Christmas tree 410 (e.g., repeated for every valve, spool, etc.). Due to the cooling provided by heat exchangers 26a and 26b, the temperature of the testing fluid 29 entering production riser 630 is substantially equal to or below the temperature of the testing fluid 29 exiting mud pit 25 (e.g., ambient air temperature at 90° F.). Thus, the time required for pressure testing of Christmas tree 410 is reduced, as the transfer of heat out of pressurized testing fluid 29 into the surrounding ambient water 13 is eliminated or at least substantially minimized.

While embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.

SYSTEMS AND METHODS FOR REDUCING PVT EFFECTS DURING PRESSURE TESTING OF A WELLBORE FLUID CONTAINMENT SYSTEM

Information

Publication Number

Date Filed

Date Published

Inventors

Original Assignees

CPC

US Classifications

International Classifications

Abstract

Description

Claims