US20140027113A1 - Systems and methods for reducing pvt effects during pressure testing of a wellbore fluid containment system - Google Patents
Systems and methods for reducing pvt effects during pressure testing of a wellbore fluid containment system Download PDFInfo
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- US20140027113A1 US20140027113A1 US13/559,133 US201213559133A US2014027113A1 US 20140027113 A1 US20140027113 A1 US 20140027113A1 US 201213559133 A US201213559133 A US 201213559133A US 2014027113 A1 US2014027113 A1 US 2014027113A1
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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
- E21B47/00—Survey of boreholes or wells
- E21B47/06—Measuring temperature or pressure
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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
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/06—Blow-out preventers, i.e. apparatus closing around a drill pipe, e.g. annular blow-out preventers
-
- 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
- E21B36/00—Heating, cooling, insulating arrangements for boreholes or wells, e.g. for use in permafrost zones
- E21B36/001—Cooling arrangements
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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
- E21B47/00—Survey of boreholes or wells
- E21B47/10—Locating fluid leaks, intrusions or movements
- E21B47/117—Detecting leaks, e.g. from tubing, by pressure testing
Definitions
- 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.
- PVT pressure-volume-temperature
- a well or well system 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.
- 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).
- each component e.g., BOP, choke and kill lines, etc.
- 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.
- 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.
- 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.
- 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.
- shut-in phases 114 , 124 , 134 and 144 have a beginning ( 114 a , 124 a , 134 a and 144 a ) and an ending ( 114 b , 124 b , 134 b and 144 b ).
- the pressure at the beginning 114 a , 124 a , 134 a and 144 a exceeds the pressure at the end 114 b , 124 b , 134 b and 144 of the shut-in phase.
- shut-in phases include a pressurization point ( 114 c , 124 c , 134 c and 144 c ) 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 114 a , 124 a , 134 a and 144 a.
- 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.
- 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.
- the greater decrease in temperature along curve 240 provides for the greater decrease in pressure during shut-in phase 144 of pressure curve 140 .
- the greater drop in temperature of fluid of curve 240 results in more PVT effect driven pressure decay during shut-in phase 144 .
- 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.
- SOBM synthetic oil based mud
- 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.
- 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.
- the tubular member comprises a drill string.
- the tubular member comprises a production riser.
- the system further includes a pump in fluid communication with the fluid flowpath.
- 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.
- 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.
- 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.
- 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.
- 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.
- the method further includes determining the presence of a leak within the closeable chamber by monitoring the pressure measurement.
- 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.
- 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.
- FIG. 10 is a schematic of a production system configured for pressure testing in accordance with principles described herein.
- the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .”
- 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.
- 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.
- an axial distance refers to a distance measured along or parallel to the given axis
- a radial distance means a distance measured perpendicular to the given axis.
- 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.
- wireless link refers to a pathway that is at least partially wired along or through a WDP joint for conducting signals
- 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.
- 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.
- 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 50 a , 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 .
- 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 35 a extending between rig 20 and seal 43 and a lower section 35 b extending from seal 43 downward into the wellbore 62 .
- 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 35 a 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 .
- Choke line 44 comprises a lower valve 44 a , a manifold 44 b and an upper valve 44 c .
- each valve (lower 44 a and upper 44 b ) 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 44 a or upper valve 44 c .
- choke manifold 44 b comprises one or more valves and chokes and is configured to manage and regulate flow through choke line 44 .
- 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 .
- 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 46 a , a kill manifold 46 b and an upper valve 46 c .
- flow through kill line 46 may be substantially restricted or controlled via valves 46 a , 46 c and manifold 46 b .
- valves 46 a , 46 c and manifold 46 b are pressure tested as well.
- IBOP 48 is disposed at an upper end 50 b 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 50 b . 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 .
- 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 .
- Pipe joints 52 include a first pipe end 53 having, for example, a first induction coil 53 a and a second pipe end 54 having, for example, a second induction coil 54 a.
- 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 52 a 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 .
- 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 52 a along the drill string 50 .
- Communication links 52 a 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.
- 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 .
- 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.
- the BOPs are actuated and isolate the well at the onset of a formation influx.
- the wellbore influx may migrate above the BOP 41 at the time the BOP's rams are closed.
- downhole distributed measurements and the high speed broadband telemetry system allow wellsite personnel to identify potential remedial actions for the migrated wellbore influx.
- the measurements used are independent from surface measurements.
- booster assemblies and network nodes 51 are disposed along the drill string 50 .
- 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 26 a , 26 b , 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 26 a , 26 b and cementing unit 27 to the passageway 50 a 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 .
- heat exchanger 26 a a schematic of heat exchanger 26 a is shown.
- heat exchangers 26 a , 26 b are shell and tube heat exchangers having a tube side fluid passageway 26 c and a shell side fluid passageway 26 d with two tube sheets 26 e that create a seal between tube side 26 c and shell side 26 d .
- Testing fluid 29 enters shell side passageway 26 c via port 26 f , flows through a plurality of tubes 26 g , and exits via port 26 i .
- heat exchanger 26 b is substantially identical to heat exchanger 26 a in structure.
- Chilled water 26 i enters tube side 26 d via port 26 j , follows a deviated flowpath around internal baffles 26 k , and exits via port 26 l . While water 26 i flows through shell side 26 d , water 26 i contacts the outer surfaces of the plurality of tubes 26 g , allowing for heat to transfer out of the testing fluid 29 disposed within tubes 26 g and into the chilled water 26 i . Thus, due to this heat transfer between testing fluid 29 and water 26 i , the testing fluid 29 entering port 26 f is at a higher temperature than the testing fluid 29 exiting port 26 fh , and the chilled water 26 i entering port 26 j is at a lower temperature than the water 26 i exiting port 26 l .
- the amount of temperature drop between testing fluid 29 entering port 26 f and testing fluid 29 exiting port 26 h is a function of the temperature of the chilled water 26 i as it enters port 26 j , the mass flow rate of water 26 i , and the mass flow rate of the testing fluid 29 . For instance, increasing the mass flow rate of chilled water 26 i entering heat exchanger 26 a 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 26 a.
- chilled water 26 i enters port 26 j at approximately 35° F. and exits port 26 l at approximately 39° F.
- Testing fluid 29 enters port 26 f at approximately 90° F. and exits port 26 h at approximately 68° F., forming a cool fluid.
- chilled water 26 i may enter port 26 j at other temperatures, and testing fluid 29 may enter port 26 f at other temperatures.
- water 26 i may comprise other fluids suitable for transferring heat out of testing fluid 29 as the two fluids flow through heat exchanger 26 a .
- heat exchangers 26 a . 26 b 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.
- testing fluid 29 may be circulated to mud pit 25 from wellbore 62 via riser 30 ( FIG. 3 ). Testing fluid 29 has a temperature T 1 as it flows from mud pit 25 to heat exchanger 26 a . Fluid 29 at this point has yet to be pressurized and thus temperature T 1 is at an ambient level with respect to the surrounding environment. A cooled fluid is formed via passing testing fluid 29 through heat exchanger 26 a , cooling fluid 29 to a temperature T 2 , which is cooler than the temperature T 1 .
- 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).
- 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 T 2 to a higher temperature T 3 .
- the pumping action of cementing unit 27 increases the temperature of the testing fluid 29 by approximately 22° F., and thus temperature T 3 is approximately 90° F. or ambient with respect to the surrounding air temperature. Also, the pressurized testing fluid at temperature T 3 is approximately equal in temperature as the first volume of fluid at temperature T 1 .
- the configuration of heat exchanger 26 a and cementing unit 27 results in a pressurized testing fluid 29 at approximately 10,000 psi at an ambient temperature T 3 of 90° F.
- second heat exchanger 26 b is provided downstream of cementing unit 27 .
- test fluid 29 passes through heat exchanger 26 b , it decreases in temperature from temperature T 3 to a temperature T 4 of approximately 75° F.
- Heat exchanger 26 b 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 .
- 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 T 6 -T n is measured at a corresponding depth from the water line 12 .
- T 6 is measured at depth 13 a
- T 7 is measured at depth 13 b
- T n is measured at depth 13 n , where the depth of 13 n is greater than the depth of 13 a , 13 b and 13 c .
- the temperature of fluid 29 disposed at depth 13 a is cooled to a greater extent than the fluid 29 disposed at depth 13 b , etc.
- the amount of heat transferred out of fluid 29 , as fluid 29 flows through heat exchangers 26 a and 26 b is controlled via the pump rate of cementing unit 27 , the temperature of water 26 i as it enters heat exchangers 26 a and 26 b , and the flow rate of water 26 i ( FIG. 5 ) as it enters heat exchangers 26 a and 26 b.
- testing fluid system 21 is shown in FIG. 6 as having two heat exchangers ( 26 a and 26 b ), 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.
- 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 .
- 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 49 a , 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 .
- annular seals 49 a and 43 form a closable annular chamber 35 c within riser 30 .
- Pressure and temperature is continuously measured at different locations of annulus 35 is detected via nodes 51 .
- pressure and temperature of fluid within chamber 35 c is continuously measured via node 51 a .
- the measurements taken by sensors 57 of nodes 51 are continuously transmitted to rig 20 via electromagnetic downhole network 56 .
- 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.
- high density testing fluid 29 e.g., mud, water based drilling fluid, SOBM, completion brine, etc.
- Pressure within drillstring 50 and annular chamber 35 c 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 29 a that comprises mud pit 25 , passageway 26 c of heat exchanger 26 a , cementing unit 27 , passageway 26 c of heat exchanger 26 b and passageway 50 a of string 50 .
- testing fluid 29 Before entering cementing unit 27 , testing fluid 29 passes through the tube side of heat exchanger 26 a ( 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 .
- testing fluid 29 flows through heat exchanger 26 b , 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 35 c .
- testing fluid 29 is also disposed within choke line 44 and kill line 46 .
- Pressure graph 500 illustrates pressure curve 510 as measured by and transmitted from node 51 a during the BOP pressure test illustrated in FIG. 7 .
- pressure curve 510 comprises a pumping phase 512 , a shut-in phase 514 having a beginning 514 a and an end 514 , and a depressurization phase 516 .
- testing fluid 29 is pumped into drillstring 50 via cementing unit 27 , which in turn displaces a volume of fluid into chamber 35 c , pressurizing the chamber 35 c to the BOP testing pressure.
- 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 .
- 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 26 a and 26 b , 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.
- 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 35 c 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.
- BOP test pressure e.g. 10,000 psi
- a specified amount of time e.g., five minutes
- Pressure within drillstring 50 and chamber 35 c exhibits a stable shut-in phase 514 due to the testing fluid 29 having a stable temperature following pumping phase 512 .
- a temperature curve 610 of the temperature of fluid proximal to node 51 a ( FIG. 7 ) within chamber 35 c 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 .
- 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 .
- (inner and outer) lower valves 44 a , 46 a , manifolds 44 b , 46 b , and upper (inner and outer) valves 44 c , 46 c , of choke line 44 and kill line 46 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 .
- nodes e.g., nodes similar to nodes 51
- high density testing fluid 29 is pumped through heat exchangers 26 a and 26 b , and into drillstring 50 via cementing unit 27 .
- Ram 42 of BOP 41 may be actuated to create annular seal 43 .
- a component of lines 44 , 46 may be sealed (e.g., lower valve 44 a ).
- the sealed component e.g., valve 44 a
- the sealed component may be pressure tested to see if it holds the BOP test pressure for a requisite period of time (e.g., five minutes).
- Well completion system 80 generally includes wellhead 60 , tubing hanger 82 , tubing 84 , casing 70 and cement 72 .
- drillstring 50 has a lower terminal end 50 c that couples to tubing hanger 82 .
- Tubing hanger 82 disposed within wellhead 60 , seals annulus 35 of riser 30 via annular seal 84 a .
- Tubing 84 couples to tubing hanger 82 at terminal end 84 a , 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 .
- annular seal 84 a 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.
- well completion system 80 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.
- 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 .
- high density testing fluid 29 e.g., mud, SOBM, completion brine, etc.
- 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 26 a prior to pressurization by cementing unit 27 , and flows through a second heat exchanger 26 b prior to entering string 650 .
- 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 ).
- fluid 29 Before entering drillstring 50 , fluid 29 passes through heat exchanger 26 b , 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 .
- the pressurized fluid 29 may be reduced to a temperature heat exchanger 26 b to a temperature substantially equal to the temperature of the water 13 at shallower depths (e.g., 0-500 feet below water line 12 ).
- the pump rate of cementing unit 27 and the flow rate of chilled water 26 g 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.
- 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 .
- heat transfer from between the ambient water 13 and the pumped in fluid 29 may be minimized.
- drilling fluid 29 is pumped into drillstring 50
- fluid within drillstring 50 is displaced out of opening 86 and into wellbore 62 , pressurizing wellbore 62 .
- 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.
- 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 .
- Production system 600 generally comprises rig 20 , a production riser 630 having a central axis 635 and ends 630 a and 630 b , a Christmas tree 410 having an upper end 410 a and a lower end 410 b , and well completion system 80 .
- Production riser 630 extends from upper end 630 a at rig 20 to lower end 630 b that is coupled to the first end 410 a of Christmas tree 410 .
- the second end 610 b 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.
- 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 26 a and 26 b , 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.
Abstract
A system for pressure testing a component of a well system includes a tubular member extending into a wellbore. The tubular member has a fluid passageway and one or more nodes that are configured to measure fluid pressure. The system also includes a heat exchanger configured to cool a fluid passing therethrough.
Description
- Not applicable.
- Not applicable.
- 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, withcurves 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, whilecurve 140 is at the lowest pressure of the curves. As shown inFIG. 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-inphases FIG. 1 , the pressure at thebeginning end curve 140 being at a shallower point along the drill string. Also, in this pressure test, shut-in phases include a pressurization point (114 c, 124 c, 134 c and 144 c) 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, atpoints - 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 generatingpressure curve 110,curve 220 is generated by temperature sensors positioned at the same position ascurve 120, etc.Temperature curve 240, at the shallowest position along the drill string, displays the greatest downward slope of thecurves 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 oftemperature curve 240, resulting in a greater difference in temperature between testing fluid within the drill string at the position ofsensors 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 toFIGS. 1 and 2 , the greater decrease in temperature alongcurve 240 provides for the greater decrease in pressure during shut-inphase 144 ofpressure curve 140. Specifically, the greater drop in temperature of fluid ofcurve 240 results in more PVT effect driven pressure decay during shut-inphase 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.
- 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.
- 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 inFIG. 3 ; -
FIG. 5 is a schematic view of a heat exchanger employed in the drilling system shown inFIG. 3 ; -
FIG. 6 is a schematic of the testing fluid system shown inFIG. 3 ; -
FIG. 7 is a schematic showing the drilling system shown inFIG. 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 inFIG. 7 ; -
FIG. 8B is a graph illustrating temperature curves generated a pressure test of the BOP pressure testing application shown inFIG. 7 ; -
FIG. 9 is a schematic showing the drilling system shown inFIG. 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. - 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 ordrilling system 10 generally includes an offshore semi-submersiblewell system rig 20 at thewater line 12 having atesting 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 amarine riser 30 that extends between therig 20 and awellhead 60 disposed at thesea floor 14, afluid containment system 40, adrill string 50 disposed withinriser 30 and having acentral axis 55 and an internal fluid passageway 50 a, and acasing 70 supported bycement 72. - An
annulus 35 is formed betweendrill string 50 andriser 30 and allows for the recirculation of drilling fluid to rig 20 from awellbore 62 formed in thesubterranean formation 16. A fluid containment system comprises several components configured to retain and manage pressure withindrill string 50 andannulus 35. In the embodiment ofdrilling string 10,fluid containment system 40 includesBOP 41,choke line 44, killline 46 and an internal BOP (IBOP) 48.Rams 42 ofBOP 41 are configured to provide anannular seal 43 upon actuation, dividingannulus 35 into anupper section 35 a extending betweenrig 20 andseal 43 and alower section 35 b extending fromseal 43 downward into thewellbore 62. During drilling, a high pressure volume of fluid from theformation 16 may flow intowellbore 62 and travel upward throughannulus 35. This formation “kick” may be isolated withinlower section 35 a ofannulus 35 via actuating one ormore rams 42, providing theannular seal 43. Chokeline 44 and killline 46 provide for alternate routes of fluid communication betweenrig 20 and the portion ofannulus 35 disposed belowBOP 41. - During a formation kick, high pressure fluid from the formation may be circulated upward through
choke line 44 to therig 20, in order to reduce the pressure of the formation fluid within theannulus 35. Chokeline 44 comprises alower valve 44 a, a manifold 44 b and anupper valve 44 c. Also, each valve (lower 44 a and upper 44 b) may include an inner and outer valve, with each valve being individually pressure tested. Fluid flow throughchoke line 44 may be restricted by closinglower valve 44 a orupper valve 44 c. Further, chokemanifold 44 b comprises one or more valves and chokes and is configured to manage and regulate flow throughchoke line 44. Because successful control of a formation kick may depend on the effective operation ofchoke line 44 and its components,valves fluid containment system 40. Killline 46 is also used to manage a formation kick by allowing for circulation betweenannulus 35 andrig 20. Killline 46 is used to pump high density drilling mud or other fluid downward fromrig 20 to theannulus 35 to circulate the formation influx out of thewellbore 62. Thus, a kill line such askill line 46 may be used to “kill” the well by stopping or at least substantially restricting the flow of fluid from the formation into thewellbore 62 by pumping heavy fluid intoannulus 35 from therig 20. Killline 46 comprises alower valve 46 a, akill manifold 46 b and anupper valve 46 c. As withchoke line 44, flow throughkill line 46 may be substantially restricted or controlled viavalves fluid containment system 40,valves -
IBOP 48 is disposed at anupper end 50 b ofdrill string 50 at therig 20 and is configured to manage fluid pressure withindrill string 50. For instance, during a formation kick, high pressure formation fluid may begin flowing upward throughstring 50 via an opening or port of thestring 50 disposed withinwellbore 62.IBOP 48 may restrict the flow of fluid out ofdrill string 50 atupper end 50 b. Thus, becauseIBOP 48 may be used in effectively controlling a formation kick,IBOP 48 is pressure tested during the pressure testing offluid 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 thedrill string 50 to therig 20 for analysis. Nodes 51 are provided at desired intervals along thedrill 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 thedrill 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 afirst pipe end 53 having, for example, afirst induction coil 53 a and asecond pipe end 54 having, for example, asecond induction coil 54 a. - Nodes 51 comprise a portion of a downhole
electromagnetic network 56 that provides an electromagnetic signal path that is used to transmit information along thedrill string 50. Thedownhole network 56, or broadband network telemetry, may thus include multiple nodes 51 based along thedrill string 50. Communication links 52 a may be used to connect the nodes 51 to one another, and may comprise cables or other transmission media integrated directly into sections of thedrill string 50. The cable may be routed through the central borehole of thedrill string 50, or routed externally to thedrill string 50, or mounted within a groove, slot or passageway in thedrill string 50. Preferably signals from the plurality of sensors along thedrill string 50 are transmitted to a remote location (e.g., rig 20) through awire conductor 52 a along thedrill string 50. Communication links 52 a 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. Thedownhole 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 thedrill 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 thedrill 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 thedrill 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 thedrill string 50. - Well
system rig 20 comprises arig floor 22, aderrick 24 extending from thefloor 22.Testing system 21 is disposed atrig floor 22 and comprises amud pit 25, one ormore heat exchangers unit 27 and afluid conduit 28.Conduit 28 provides a fluid flowpath for atesting fluid 29 frommud pit 25, throughheat exchangers unit 27 to the passageway 50 a ofdrill string 50. Testingfluid 29 comprises a high density and high weight fluid (e.g., drilling fluid, SOBM, completion fluid, etc.) relative toambient water 13 disposed belowwater line 12. For instance,fluid 29 has a relatively higher density than fluid fromformation 16. - Referring to
FIG. 5 , a schematic ofheat exchanger 26 a is shown. In the example shown inFIGS. 3 ,heat exchangers side fluid passageway 26 c and a shellside fluid passageway 26 d with twotube sheets 26 e that create a seal betweentube side 26 c andshell side 26 d. Testingfluid 29 entersshell side passageway 26 c viaport 26 f, flows through a plurality oftubes 26 g, and exits via port 26 i. Also,heat exchanger 26 b is substantially identical toheat exchanger 26 a in structure. - Chilled water 26 i enters
tube side 26 d via port 26 j, follows a deviated flowpath aroundinternal baffles 26 k, and exits via port 26 l. While water 26 i flows throughshell side 26 d, water 26 i contacts the outer surfaces of the plurality oftubes 26 g, allowing for heat to transfer out of thetesting fluid 29 disposed withintubes 26 g and into the chilled water 26 i. Thus, due to this heat transfer betweentesting fluid 29 and water 26 i, thetesting fluid 29 enteringport 26 f is at a higher temperature than the testingfluid 29 exiting port 26 fh, and the chilled water 26 i entering port 26 j is at a lower temperature than the water 26 i exiting port 26 l. The amount of temperature drop betweentesting fluid 29 enteringport 26 f and testingfluid 29 exitingport 26 h is a function of the temperature of the chilled water 26 i as it enters port 26 j, the mass flow rate of water 26 i, and the mass flow rate of thetesting fluid 29. For instance, increasing the mass flow rate of chilled water 26 i enteringheat exchanger 26 a will increase the temperature drop of thetesting fluid 29 as it flows through the heat exchanger. Also, increasing the mass flow rate of thetesting fluid 29 will decrease the temperature drop in the fluid 29 as it passes throughheat exchanger 26 a. - In the embodiment illustrated in
FIG. 5 , chilled water 26 i enters port 26 j at approximately 35° F. and exits port 26 l at approximately 39°F. Testing fluid 29 entersport 26 f at approximately 90° F. and exitsport 26 h at approximately 68° F., forming a cool fluid. In other embodiments, chilled water 26 i may enter port 26 j at other temperatures, andtesting fluid 29 may enterport 26 f at other temperatures. Further, in other embodiments, water 26 i may comprise other fluids suitable for transferring heat out of testingfluid 29 as the two fluids flow throughheat exchanger 26 a. In other embodiments,heat exchangers 26 a. 26 b 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 oftesting fluid system 21 is shown. In this embodiment oftesting fluid system 21, a first volume of testing fluid flows frommud pit 21 throughheat exchanger 26 a to cementingunit 27. Testingfluid 29 may be circulated tomud pit 25 fromwellbore 62 via riser 30 (FIG. 3 ). Testingfluid 29 has a temperature T1 as it flows frommud pit 25 toheat exchanger 26 a.Fluid 29 at this point has yet to be pressurized and thus temperature T1 is at an ambient level with respect to the surrounding environment. A cooled fluid is formed via passingtesting fluid 29 throughheat exchanger 26 a, coolingfluid 29 to a temperature T2, which is cooler than the temperature T1. In this example, T1 is approximately 90° F. while T2 is approximately 68° F. After passing throughheat exchanger 26 a,testing fluid 29 enters cementingunit 27. Cementingunit 27 comprises a high pressure pump suitable for forming a pressurized fluid via pressurizingtest fluid 29 from ambient pressure to pressures ranging from 5,000-12,000 pounds per square inch (psi). In this embodiment, cementingunit 27 comprises a triplex reciprocating pump that pressurizes fluid 29 between approximately 8,000-12,000 psi. Due to PVT effects, the pressurization offluid 29 byunit 27 increases the temperature offluid 29 from temperature T2 to a higher temperature T3. In this embodiment, the pumping action of cementingunit 27 increases the temperature of thetesting fluid 29 by approximately 22° F., and thus temperature T3 is approximately 90° F. or ambient with respect to the surrounding air temperature. Also, the pressurized testing fluid at temperature T3 is approximately equal in temperature as the first volume of fluid at temperature T1. Thus, the configuration ofheat exchanger 26 a and cementingunit 27 results in apressurized testing fluid 29 at approximately 10,000 psi at an ambient temperature T3 of 90° F. - Referring still to
FIG. 6 , in an embodiment,second heat exchanger 26 b is provided downstream of cementingunit 27. Astest fluid 29 passes throughheat exchanger 26 b, it decreases in temperature from temperature T3 to a temperature T4 of approximately 75°F. Heat exchanger 26 b is configured to lower the temperature of thetest fluid 29 to a temperature that is substantially equal to theambient water 13 surrounding riser 30 (FIG. 3 ) at shallow depths. For instance, as testingfluid 29 is pumped intodrill string 50, a portion of testingfluid 29 will be disposed within a segment of thedrill string 50 that is below thewater line 12. Because the temperature of the ambient water may 13 be cooler than the ambient air temperature, testingfluid 29 disposed below thewater 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 thetesting fluid 29 and the surroundingambient water 13 belowwater line 12. Each temperature T6-Tn, is measured at a corresponding depth from thewater line 12. T6 is measured atdepth 13 a, T7 is measured at depth 13 b and Tn is measured atdepth 13 n, where the depth of 13 n is greater than the depth of 13 a, 13 b and 13 c. Because the temperature ofwater 13 disposed at depth 13 b is greater than the temperature of the water at 13 a, the temperature offluid 29 disposed atdepth 13 a is cooled to a greater extent than the fluid 29 disposed at depth 13 b, etc. The amount of heat transferred out offluid 29, asfluid 29 flows throughheat exchangers unit 27, the temperature of water 26 i as it entersheat exchangers FIG. 5 ) as it entersheat exchangers - While the
testing fluid system 21 is shown inFIG. 6 as having two heat exchangers (26 a and 26 b), 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 testingfluid 29 enteringdrillstring 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 toFIG. 3 , is shown configured for pressure testingfluid 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 belowBOP 41, proximal towellhead 60. As shown inFIG. 7 , test plug 49 is configured to prevent fluid withindrill string 50 from flowing across plug 49. Test plug 49 also forms anannular seal 49 a, preventing fluid flow withinannulus 35 across test plug 49. A radial port or opening 45 is provided in thedrillstring 50 to act as a route of fluid communication betweendrillstring 50 and theannulus 35 axially above testing plug 49. Aram 42 ofBOP 41 may be actuated to form an annular seal, preventing fluid passing throughport 45 from flowing upward throughannulus 35 to therig 20. Thus,annular seals annular chamber 35 c withinriser 30. Pressure and temperature is continuously measured at different locations ofannulus 35 is detected via nodes 51. For instance, pressure and temperature of fluid withinchamber 35 c is continuously measured vianode 51 a. The measurements taken by sensors 57 of nodes 51 are continuously transmitted to rig 20 via electromagneticdownhole 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 withindrillstring 50 andannular chamber 35 c ofannulus 35 is increased to the required BOP testing pressure by injecting a volume of testingfluid 29 intodrillstring 50. Testingfluid 29 is pumped via cementingunit 27 intodrill string 50 viafluid flowpath 29 a that comprisesmud pit 25,passageway 26 c ofheat exchanger 26 a, cementingunit 27,passageway 26 c ofheat exchanger 26 b and passageway 50 a ofstring 50. Before entering cementingunit 27, testing fluid 29 passes through the tube side ofheat exchanger 26 a (FIG. 5 ), chilling thetesting fluid 29 to a temperature below the ambient air temperature at therig 20. Testingfluid 29 is pressurized to approximately between 5,000-12,000 psi, increasing the temperature of testingfluid 29 to a temperature substantially equal to the ambient air temperature atrig 20. Following pressurization by cementingunit 27, testingfluid 29 flows throughheat exchanger 26 b, lowering the temperature of testingfluid 29 to a temperature substantially equal to theambient water 13temperature surrounding riser 30. A volume of testingfluid 29 is then displaced intodrill string 50, pressurizing fluid withindrill string 50 and theannular chamber 35 c. In subsequent pressure tests of other elements of thefluid containment system 40, testingfluid 29 is also disposed withinchoke line 44 and killline 46. - Referring now to
FIGS. 8A and 8B , graphs of pressure and temperature of testingfluid 29 measured during the BOP pressure test ofFIG. 7 are shown.Pressure graph 500 illustratespressure curve 510 as measured by and transmitted fromnode 51 a during the BOP pressure test illustrated inFIG. 7 . As shown inFIG. 8A ,pressure curve 510 comprises a pumping phase 512, a shut-in phase 514 having a beginning 514 a and an end 514, and adepressurization phase 516. During pumping phase 512, testingfluid 29 is pumped intodrillstring 50 via cementingunit 27, which in turn displaces a volume of fluid intochamber 35 c, pressurizing thechamber 35 c to the BOP testing pressure. Once pressure withinchamber 35 c has reached the BOP testing pressure, the beginning 514 a of shut-in phase 514 takes place with the cessation of pumping from cementingunit 27, thus stopping the flow of testingfluid 29 intodrillstring 50 atrig 20. As part of a BOP pressure test shown inFIG. 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 thetesting fluid 29 that is now disposed withindrillstring 50 has been chilled viaheat exchangers pressure curve 510 is stable with respect to time, varying to a lesser degree over time than the pressure curves shown inFIG. 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 inFIG. 1 , as the requirement of holding the BOP test pressure (e.g., 10,000 psi) withinchamber 35 c 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 ofpressure 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 andchamber 35 c exhibits a stable shut-in phase 514 due to thetesting fluid 29 having a stable temperature following pumping phase 512. For instance, referring toFIG. 8B , atemperature curve 610 of the temperature of fluid proximal tonode 51 a (FIG. 7 ) withinchamber 35 c 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 thetesting 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 thefluid containment system 40, such as a leak withinannular seal 43 provided byram 42, rather than being caused by a decrease in temperature of testingfluid 29. - Referring back to
FIG. 7 , in addition to 7ram 42 ofBOP 41 being pressure tested, other components offluid containment system 40 may be pressure tested in a similar manner. For instance, other individual rams ofBOP 41 may be actuated to create an annular seal withinannulus 35, forming a cavity defined by the ram's annular seal and theseal 49 a produced by BOP test plug 49. Likewise, (inner and outer)lower valves valves choke line 44 and killline 46, respectively, may be pressure tested by placing nodes (e.g., nodes similar to nodes 51) withinchoke line 44 or killline 46 in order to continuously measure and transmit pressure and temperature readings fromlines choke line 44 and killline 46, highdensity testing fluid 29 is pumped throughheat exchangers drillstring 50 via cementingunit 27.Ram 42 ofBOP 41 may be actuated to createannular seal 43. However, instead of allowing fluid communication betweenchoke line 44 and killline 46 withchamber 35 c, a component oflines lower valve 44 a). In this embodiment, the sealed component (e.g.,valve 44 a) 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 toFIG. 3 is shown configured for pressure testingwell completion system 80. Wellcompletion system 80 generally includeswellhead 60,tubing hanger 82,tubing 84, casing 70 andcement 72. In this example,drillstring 50 has a lowerterminal end 50 c that couples totubing hanger 82.Tubing hanger 82, disposed withinwellhead 60, seals annulus 35 ofriser 30 viaannular seal 84 a.Tubing 84 couples totubing hanger 82 atterminal end 84 a, and extends downward intowellbore 62.Tubing 84 is configured to act as a route of fluid communication betweenformation 16 and a production riser (not shown) that is installed following completion.Tubing hanger 82 physically supportstubing 80 and allows for a route of fluid communication betweentubing 80 anddrillstring 50. Further,annular seal 84 a ofhanger 82 prevents fluid withinwellbore 62 from flowing upward and out ofwellbore 62 viaannulus 35.Casing 70 allows for selective fluid communication betweenwellbore 62 andformation 16. For instance, following the completion pressure tests, casing 70 is perforated at predetermined locations inwellbore 62 to provide routes of fluid communication with theformation 16 via the perforations. - Prior to installing the production system, well
completion system 80 is pressure tested in order to ensure thatcompletion 80 will not leak once fluid fromformation 16 begins to flow intowellbore 62 andtubing 84 once production of hydrocarbons fromformation 16 has commenced. As part of the pressure test, a radial port or opening 86 is provided withintubing 84 to allow for a route of fluid communication betweentubing 84 andwellbore 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 testingfluid 29 is pumped intodrillstring 50 viaconduit 28 and cementingunit 27. Testingfluid 29 is pumped frommud pit 25 where it is stored at ambient pressure and temperature (e.g., 90° F. and atmospheric pressure). - Testing
fluid 29 passes throughheat exchanger 26 a prior to pressurization by cementingunit 27, and flows through asecond heat exchanger 26 b prior to entering string 650. Thus, testingfluid 29 is chilled to below the ambient air temperature to a temperature of approximately 68° F. prior to pressurization via cementingunit 27, which increases the pressure offluid 29 from 5,000-12,000 psi, in this example. Due to PVT effects (e.g., friction from pumping), pressurization offluid 29 results in a temperature increase of the pressurized fluid such thatfluid 29 returns to ambient temperature (e.g., the temperature of thetesting fluid 29 as it exits mud pit 25). Before enteringdrillstring 50, fluid 29 passes throughheat exchanger 26 b, reducing the temperature offluid 29 to below the ambient air temperature to a temperature of approximately 80° F., in this example. Thus, the temperature offluid 29 as it enters string 650 is substantially equal to the temperature of thewater 13. - Although the temperature of the
water 13 proximal to rig 20 may vary by depth, because only a relatively small volume offluid 29 is pumped intodrillstring 50, thepressurized fluid 29 may be reduced to atemperature heat exchanger 26 b to a temperature substantially equal to the temperature of thewater 13 at shallower depths (e.g., 0-500 feet below water line 12). Further, the pump rate of cementingunit 27 and the flow rate ofchilled water 26 g (FIG. 5 ) may be varied to vary the temperature offluid 29 as it entersdrillstring 50. The temperature offluid 29 may be varied to match the temperature of thewater 13 at the depth belowwater line 12 where that portion offluid 29 will be disposed following the completion of pumping. For instance, a first portion offluid 29 pumped intodrillstring 50 may be cooled to a greater extent than a later portion offluid 29, because the first portion will occupy a lower depth indrillstring 50, which is surrounded by relativelycooler water 13, while the later portion will occupy a shallower depth withindrillstring 50, which is surrounded by relativelywarmer water 13. Thus, by ensuring a relatively small temperature difference between the pumped influid 29, and theambient water 13 disposed proximal to that fluid 29, heat transfer from between theambient water 13 and the pumped influid 29 may be minimized. - Referring still to
FIG. 9 , as testingfluid 29 is pumped intodrillstring 50, fluid withindrillstring 50 is displaced out of opening 86 and intowellbore 62, pressurizingwellbore 62. Oncewellbore 62 has reached a completion test pressure (e.g., 12,000 psi), pumping via cementingunit 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 andelectromagnetic network 56. Sensors 57 of Nodes 51 continuously measure pressure withinannulus 35 ofriser 30 and withindrillstring 50. - Referring now to
FIG. 10 , a well orproduction system 600 is shown.Production system 600 generally comprisesrig 20, aproduction riser 630 having a central axis 635 and ends 630 a and 630 b, aChristmas tree 410 having anupper end 410 a and alower end 410 b, andwell completion system 80.Production riser 630 extends fromupper end 630 a atrig 20 tolower end 630 b that is coupled to thefirst end 410 a ofChristmas tree 410. The second end 610 b ofChristmas tree 410 couples towellhead 60. Fluid communication between fluid withinformation 16 andproduction riser 630 is provided bytubing 84 disposed within wellbore 602. Production riser includes one or more nodes 51, which partly formelectromagnetic 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 thatproduction system 600 may contain a high pressure influx of fluid fromformation 16. In this example, testingfluid 29 may be pressurized and injected intoproduction riser 630 viatesting fluid circuit 21 disposed at therig 20.Christmas tree 410 may be isolated from theformation 16 via displacing a testing plug downward throughproduction riser 630 such that the plug is disposed withinwellhead 60, sealingtubing 84 fromtree 410 andriser 630. Testingfluid 29 is then pumped intoproduction riser 630, and a pressure test ofChristmas 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 byheat exchangers testing fluid 29 enteringproduction riser 630 is substantially equal to or below the temperature of thetesting fluid 29 exiting mud pit 25 (e.g., ambient air temperature at 90° F.). Thus, the time required for pressure testing ofChristmas tree 410 is reduced, as the transfer of heat out ofpressurized testing fluid 29 into the surroundingambient 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.
Claims (28)
1. A system for pressure testing a component of a well system comprising:
a wellbore penetrating a subterranean formation;
a tubular member extending into the wellbore having a first fluid passageway;
one or more nodes that are configured to measure fluid pressure and are coupled to the tubular member;
a heat exchanger having a second fluid passageway and is configured to cool a fluid passing through the second fluid passageway; and
a fluid flowpath that comprises at least a portion of the first fluid passageway and at least a portion of the second fluid passageway.
2. The system of claim 1 , wherein the tubular member comprises a drillstring.
3. The system of claim 1 , wherein the tubular member comprises a production riser.
4. The system of claim 1 , wherein the heat exchanger is a shell and tube heat exchanger.
5. The system of claim 1 , further comprising a first volume of fluid in the fluid flowpath having a first pressure.
6. The system of claim 1 , wherein the fluid flowpath further comprises an annulus surrounding the tubular member.
7. The system of claim 1 , wherein the fluid flowpath further comprises the wellbore of the system.
8. The system of claim 5 , further comprising a pump in fluid communication with the fluid flowpath and configured to pressurize fluid in the fluid flowpath to produce a pressurized fluid having a second pressure that is greater than the first pressure of the first of fluid.
9. The system of claim 8 , wherein the temperature of the first volume of fluid is substantially equal to the temperature of the pressurized fluid.
10. The system of claim 8 , wherein the temperature of the pressurized fluid is less than the temperature of the first volume of fluid.
11. The system of claim 1 , further comprising:
a test plug disposed within the tubular member;
a ram of a blowout preventer disposed at least partially within the tubular member; and
a sealed chamber formed by the tubular member, the ram and the test plug;
wherein one of the one or more nodes is disposed within the sealed chamber.
12. The system of claim 8 , wherein the pressurized fluid comprises a first portion and a second portion, and wherein the first portion of the pressurized fluid is cooled to a first temperature and the second portion of the pressurized fluid is cooled to a second temperature.
13. The system of claim 12 , wherein the first temperature is different than the second temperature.
14. A method for pressure testing a well system comprising:
cooling a first volume of fluid having a first pressure to produce a cooled fluid;
flowing the cooled fluid into a closeable chamber of the well system;
shutting in the chamber; and
measuring a pressure in the chamber using nodes distributed within the chamber.
15. The method of claim 14 , wherein 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.
16. The method of claim 14 , transmitting the pressure measurement to a remote location.
17. The method of claim 15 , wherein pressurizing the cooled fluid to produce a pressurized fluid comprises pressurizing the cooled fluid to a temperature that is substantially equal to the temperature of the first volume of fluid.
18. The method of claim 15 , wherein pressurizing the cooled fluid to produce a pressurized fluid comprises pressurizing the cooled fluid to a temperature that is less than the temperature of the first volume of fluid.
19. The method of claim 14 , further comprising determining the presence of a leak within the closeable chamber by monitoring the pressure measurement.
20. The method of claim 14 , further comprising filling the closeable chamber with the cooled fluid.
21. The method of claim 14 further comprising transmitting the measured pressure to a remote location.
22. The method of claim 14 wherein the measured pressure is transmitted via a network comprising wired drill pipe.
23. The method of claim 14 , wherein cooling the fluid to produce the cooled fluid comprises flowing the fluid through a heat exchanger.
24. The method of claim 14 , wherein the closeable chamber comprises an annulus surrounding a tubular body.
25. The method of claim 14 , wherein the closeable chamber comprises a wellbore.
26. The method of claim 14 , wherein cooling the fluid to produce a cooled fluid comprises cooling a first portion of the fluid to produce a first cooled portion of fluid and cooling a second portion of the fluid to produce a second cooled portion of fluid.
27. The method of claim 26 , wherein the first cooled portion of fluid is cooled to a temperature that is higher than the temperature of the second cooled portion of fluid.
28. The method of claim 14 , wherein:
flowing the cooled fluid into the chamber comprises pressurizing the cooled fluid to produce a pressurized fluid;
wherein cooling the fluid to produce a cooled fluid comprises cooling a first portion of the fluid to a first temperature and cooling a second portion of the fluid to a second temperature that is different than the first temperature.
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US13/559,133 US20140027113A1 (en) | 2012-07-26 | 2012-07-26 | Systems and methods for reducing pvt effects during pressure testing of a wellbore fluid containment system |
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US13/559,133 US20140027113A1 (en) | 2012-07-26 | 2012-07-26 | Systems and methods for reducing pvt effects during pressure testing of a wellbore fluid containment system |
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US20140123747A1 (en) * | 2012-11-05 | 2014-05-08 | Intelliserv, Llc | Systems and methods for conducting pressure tests on a wellbore fluid containment system |
US20150315903A1 (en) * | 2014-05-02 | 2015-11-05 | kongsberg Oil and Gas Technolgies AS | System and console for monitoring and managing pressure testing operations at a well site |
WO2016142656A3 (en) * | 2015-03-06 | 2016-11-24 | Oil States Industries (Uk) Limited | Valved tree member for a riser system and telescoping device for inclusion in a riser system |
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US20190383104A1 (en) * | 2018-06-14 | 2019-12-19 | Allegiant Energy Services, LLC | Drill string testing system |
US10690805B2 (en) | 2013-12-05 | 2020-06-23 | Pile Dynamics, Inc. | Borehold testing device |
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US20050269079A1 (en) * | 2003-12-26 | 2005-12-08 | Franklin Charles M | Blowout preventer testing system |
Cited By (14)
Publication number | Priority date | Publication date | Assignee | Title |
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US20140123747A1 (en) * | 2012-11-05 | 2014-05-08 | Intelliserv, Llc | Systems and methods for conducting pressure tests on a wellbore fluid containment system |
US10690805B2 (en) | 2013-12-05 | 2020-06-23 | Pile Dynamics, Inc. | Borehold testing device |
US11340379B2 (en) | 2013-12-05 | 2022-05-24 | Pile Dynamics, Inc. | Borehole inspecting and testing device and method of using the same |
US10330823B2 (en) | 2013-12-05 | 2019-06-25 | Pile Dynamics, Inc. | Borehole testing device |
US20150315903A1 (en) * | 2014-05-02 | 2015-11-05 | kongsberg Oil and Gas Technolgies AS | System and console for monitoring and managing pressure testing operations at a well site |
US10436014B2 (en) * | 2014-05-02 | 2019-10-08 | Kongsberg Oil And Gas Technologies As | System and console for monitoring and managing pressure testing operations at a well site |
WO2016142656A3 (en) * | 2015-03-06 | 2016-11-24 | Oil States Industries (Uk) Limited | Valved tree member for a riser system and telescoping device for inclusion in a riser system |
AU2016230931B2 (en) * | 2015-03-06 | 2020-08-13 | Oil States Industries (Uk) Limited | Valved tree member for a riser system and telescoping device for inclusion in a riser system |
EP3409883A1 (en) * | 2015-03-06 | 2018-12-05 | Oil States Industries (UK) Ltd | A telescopic device for inclusion in a riser system |
WO2017030868A1 (en) * | 2015-08-14 | 2017-02-23 | Pile Dynamics, Inc. | Borehole testing device |
JP2018523033A (en) * | 2015-08-14 | 2018-08-16 | パイル ダイナミクス インコーポレイテッド | Borehole test equipment |
CN108350734A (en) * | 2015-08-14 | 2018-07-31 | 桩基动力测试公司 | Borehole test device |
US20190383104A1 (en) * | 2018-06-14 | 2019-12-19 | Allegiant Energy Services, LLC | Drill string testing system |
US10914126B2 (en) * | 2018-06-14 | 2021-02-09 | Allegiant Energy Services, LLC | Drill string testing system |
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