Patent Application
20230366293
This disclosure relates to the production of oil, gas, or other resources from subterranean zones to the surface.
Hydrocarbons trapped in subsurface reservoirs can be raised to the surface of the Earth (that is, produced) through wellbores formed from the surface to the subsurface reservoirs. Wellbore drilling systems are used to drill wellbores through a subterranean zone (for example, a formation, a portion of a formation or multiple formations) to the subsurface reservoir. At a high level, the wellbore drilling system includes a drill bit connected to an end of a drill string. The drill string is rotated and weight is applied on the drill bit to drill through the subterranean zone. Wellbore drilling fluid (also known as drilling mud) is flowed in a downhole direction through the drill string. The drilling fluid exits the drill bit through ports defined in the drill bit and can be circulated in an uphole direction through an annulus defined by an outer surface of the drill string and an inner wall of the wellbore to the surface and then recirculated downhole after filtering and other treatment processes, in a closed (or partially closed) loop.
Certain aspects of the subject matter herein can be implemented as a system for cooling drilling fluid circulating in a wellbore drilled by wellbore drilling system. The system includes a drilling fluid conduit positioned at a surface location separate from a wellhead of the wellbore. Drilling fluid flowed from the wellbore and an outer jacket passes through the drilling fluid conduit. An inner surface of the outer jacket at least partially defines an interior volume within which the drilling fluid conduit is at least partially disposed. The interior volume is at least partially filled with liquid nitrogen, such that the drilling fluid passing through the drilling fluid conduit is cooled by heat exchange with the liquid nitrogen across a wall of the drilling fluid conduit prior to flowing back into the wellbore via a mud pump.
An aspect combinable with any of the other aspects can include the following features. The system can also include a coolant injection system configured to selectively inject liquid nitrogen into the coolant volume.
An aspect combinable with any of the other aspects can include the following features. The drilling fluid flowed from the wellbore can pass through a shale shaker prior to passing through the drilling fluid conduit.
An aspect combinable with any of the other aspects can include the following features. The drilling fluid can flow from the drilling fluid conduit to a mud pump, the mud pump configured to pump the drilling fluid back into the wellbore.
An aspect combinable with any of the other aspects can include the following features. At least a portion of the drilling fluid can flows from the drilling fluid conduit to an insulated circulating tank and thence from the insulated circulating tank back to the drilling fluid conduit, prior to flowing from the drilling fluid conduit to the mud pump.
An aspect combinable with any of the other aspects can include the following features. The drilling fluid conduit and the outer jacket are can be coaxial tubulars.
An aspect combinable with any of the other aspects can include the following features. The interior volume can be at least partially defined by an outer surface of the drilling fluid conduit.
An aspect combinable with any of the other aspects can include the following features. The drilling fluid conduit can be concentric with the outer jacket.
An aspect combinable with any of the other aspects can include the following features. The drilling fluid conduit can be a first drilling fluid conduit of a plurality of drilling fluid conduits disposed within, the outer jacket.
An aspect combinable with any of the other aspects can include the following features. The liquid nitrogen can be in direct contact with an outer surface of the drilling fluid conduit.
An aspect combinable with any of the other aspects can include the following features. The liquid nitrogen may not be in direct contact with an outer surface of the drilling fluid conduit.
An aspect combinable with any of the other aspects can include the following features. The system can further include an intermediate tubular coaxial with and disposed within the outer jacket and within which the drilling fluid conduit is disposed. An annular volume can be defined by an inner surface of the intermediate tubular and an outer surface of the drilling fluid conduit and can be at least partially filled with water. Cooling the drilling fluid flowing through the drilling fluid conduit by heat exchange with the liquid nitrogen across the wall of the drilling fluid conduit can include cooling the water filling the annular volume at least partially by heat exchange with the liquid nitrogen and cooling the drilling fluid at least partially by heat exchange with the water filling the annular volume.
An aspect combinable with any of the other aspects can include the following features. The system can also include a plurality of fins extending radially from an outer surface of the drilling fluid conduit
Certain aspects of the subject matter herein can be implemented as an apparatus for cooling a drilling fluid circulating in a wellbore drilling system configured to drill a wellbore. The apparatus includes a main body, a drilling fluid conduit disposed within the main body, and an outer jacket. An inner surface of the outer jacket at least partially defines an interior volume within which the drilling fluid conduit is at least partially disposed. The interior volume is configured to be at least partially filled with liquid nitrogen. The apparatus is configured such that, when the apparatus is positioned at a surface location separate from a wellhead of the wellbore and configured so as to receive a volume of drilling fluid flowed from the wellbore, the volume of drilling fluid can pass through the drilling fluid conduit and the drilling fluid is cooled by heat exchange with the liquid nitrogen across a wall of the drilling fluid conduit prior to flowing back into the wellbore via a mud pump.
An aspect combinable with any of the other aspects can include the following features. The wellbore drilling system can be a wellbore drilling system for drilling a wellbore at a first wellsite, and the apparatus can be an assembly configured to be transported as a unit from the wellbore drilling system at the first wellsite to a wellbore drilling system at a second wellsite.
An aspect combinable with any of the other aspects can include the following features. The apparatus can be configured such that liquid nitrogen from a coolant injection system can fill the coolant volume. The coolant injection system can be a component of the apparatus.
An aspect combinable with any of the other aspects can include the following features. The liquid nitrogen can be in direct contact with an outer surface of the drilling fluid conduit.
An aspect combinable with any of the other aspects can include the following features. The apparatus can also include an intermediate tubular coaxial with and disposed within the outer jacket and within which the drilling fluid conduit is disposed. An annular volume can be defined by an inner surface of the intermediate tubular and an outer surface of the drilling fluid conduit and can be at least partially filled with water. Cooling the drilling fluid flowing through the drilling fluid conduit by heat exchange with the liquid nitrogen across the wall of the drilling fluid conduit can include cooling the water filling the annular volume at least partially by heat exchange with the liquid nitrogen and cooling the drilling fluid at least partially by heat exchange with the water filling the annular volume.
Certain aspects of the subject matter herein can be implemented as a method of cooling a drilling fluid circulating in a wellbore drilled by a wellbore drilling system. The method includes filling, with liquid nitrogen, an interior volume of a cryogenic heat exchange system positioned at a surface location separate from a wellhead of the wellbore. The interior volume is at least partially defined by an inner surface of an outer jacket of the cryogenic heat exchange system. A drilling fluid flowed from the wellbore is flowed through a drilling fluid conduit of the cryogenic heat exchange system at least partially disposed in the interior volume. The drilling fluid is cooled by heat exchange with the liquid nitrogen across a wall of the drilling fluid conduit and is flowed via a mud pump back into the wellbore.
An aspect combinable with any of the other aspects can include the following features. The method can also include flowing the drilling fluid from the drilling fluid conduit to an insulated circulating tank, flowing at least a portion of the drilling fluid from the insulating circulating tank back to the drilling fluid conduit, cooling, by heat exchange with the liquid nitrogen across the wall of the drilling fluid conduit, the portion, and flowing, by the mud pump, the portion from the drilling fluid conduit to the wellbore. The flowing, via the mud pump, the drilling fluid back into the wellbore can include flowing the portion into the wellbore.
The details of one or more embodiments are set forth in the accompanying drawings and the description below. Other features, objects, and advantages will be apparent from the description, drawings, and claims.
The details of one or more implementations of the subject matter of this specification are set forth in this detailed description, the accompanying drawings, and the claims. Other features, aspects, and advantages of the subject matter will become apparent from this detailed description, the claims, and the accompanying drawings.
High temperatures within a wellbore can interfere with the functioning of downhole magnetometers, downhole electronics, downhole sensors, and other downhole components of a drillstring or other assembly. For example, long lateral wellbores in high temperature subsurface environments (with, for example, bottomhole temperatures greater than three-hundred degrees Fahrenheit) can present particular drilling challenges. Such circumstances can cause higher frequency of temperature-related measurement-while-drilling (MWD) and logging-while-drilling (LWD) failures and also strongly affect the performance of drilling fluids, cements, well casing and tubing, elastomers and seals in packers. It has also been established that, in long horizontal wells under certain operating well conditions, the bottom-hole circulation temperature can rise above the static bottom-hole temperature.
In accordance with embodiments of the present disclosure, a cryogenic fluid system is used to cool drilling fluid or other wellbore fluid after it comes out from the well through the flowline and before being recirculated downhole. In accordance with some embodiments, liquid nitrogen at extremely low cryogenic temperatures is used as a heat exchanger medium to cool the wellbore fluid. The cryogenic heat exchange system of the present disclosure can be a simple, on-site, mobile unit that can be easily plumbed into the mud pits and/or other rig systems to provide in-line cooling of the wellbore fluid as it comes out of the hole. In some embodiments, drilling fluid cooled by the cooling system can be recirculated through a loop system back to cooling system for further cooling prior to being pumped downhole. The cooled wellbore fluid can reach a formation at a much lower temperature than otherwise possible with prior cooling systems, thus reducing or eliminating the negative effects of high downhole temperatures on drilling and other equipment and processes. The system, apparatus, or method of the present disclosure can be cost effective, easy to install, and relatively low risk system to lower the temperature of wellbore fluid, thus providing substantial HS&E benefits on surface, reducing equipment failures, providing better control of mud properties, and enabling drilling in higher-temperature regions. The system, apparatus, or method of the present disclosure can help extend the operating envelope of downhole tools, thus enabling the exploration of and production from hot reservoirs that are beyond reach with prior systems, apparatus, and methods.
The derrick 110 is a support framework mounted on the drill floor 102 and positioned over the wellbore to support the components of the drill string assembly 106 during drilling operations. A crown block 112 is positioned at top of the derrick 110 and connects to a travelling block 114 with a drilling line including a set of wire ropes or cables. The crown block 112 and the travelling block 114 support the drill string assembly 106 via a swivel, kelly, and/or top drive system.
In the wellbore drilling system 100 of
Wellbore drilling system 100 further includes a drilling fluid 180 (sometimes referred to as drilling mud) which can serve to control formation pressures, remove cuttings from the wellbore, seal permeable formations encountered while drilling, cool and lubricating the drill bit and other components of bottomhole assembly 120, transmit hydraulic energy to downhole tools and the drill bit, and maintain wellbore stability and well control. During a drilling operation of the well, circulation system 150 circulates drilling fluid 180 to the drill string assembly 106, receives and filters used drilling fluid from the wellbore, and returns clean drilling fluid to the drill string assembly 106. Specifically, circulation system 150 includes a mud pump 154 that fluidly connects to and provides drilling fluid from mud pit 152 to drill string assembly 106 via the kelly hose 156. The drilling fluid flows through the drill string assembly 106, flows out the drill bit in bottomhole assembly 120 and back up the annulus 107. Annulus 107 is the space between the drill string assembly 106 and wellbore 101 or formation or casing disposed within wellbore 101. The drilling fluid 180 returns to the surface in the annulus 107 with rock cuttings and flows out bell nipple 158 to the flow-out line 160. From flow-out line 160, the fluid passes through a shale shaker 162 and its associated components. Shale shaker 162 can include a mesh-like surface to separate the rock cuttings and other debris from the drilling fluid 180. Drilling fluid 180 flows from shale shaker 162 to mud pit 152. At least a portion of drill fluid 180 can then be pumped from mud pit 152 back to drill string assembly 106 by mud pump 154, thus completing the circulation loop.
In the illustrated embodiment, circulation system 150 further includes a cryogenic heat exchange (CHE) system 164. As described in greater detail below, CHE system 164 can cool drilling fluid 180 by heat exchange with liquid nitrogen. Mud pit 152 can include one or more compartments or valves to selectively divert at least a portion of drilling fluid 180 to an intermediate circulation pump 153 which can, in turn, pump that portion of the drilling fluid 180 to CHE system 164. Drilling fluid 180 cooled by cryogenic heat exchange system 164 can flow back into mud pit 152. In some embodiments, valves within or connected to mud pit 152 can return all or a portion of the cooled fluid from mud pit 152 to the drill string 106 via mud pump 154 and kelly hose 156 as described above.
In some embodiments, valves within or connected to mud pit 152 can divert all or a portion of the cooled drilling fluid back to CHE system 164 for further cooling prior to being returned to drill string 106, and such recirculation and re-cooling can be repeated until the desired level of cooling is achieved. In such embodiments, circulation system 150 can further include an insulated intermediate holding tank 170 for collecting such recirculating fluid and, when the cooled fluid has reached a suitably low temperature, the fluid can be redirected back to drill string 106 via mud pump 154. Such collection and recirculating through intermediate holding tank 170 can in some embodiments enable a reduction in drilling fluid temperature to super-cooling temperature ranges.
In some embodiments, a control module 190 can be connected to one or more of the valves, temperature sensors, and/or other control devices or sensors within or connected to mud pump 154, and/or to CHE system 164. Control module 190 can in some embodiments receive and display measurements such as temperature, flow rate, and fluid volume, and can receive inputs to divert, flow, collect, or recirculate fluids through CHE system 164, intermediate holding tank 170, and other components of circulation system 150. In some embodiments, circulation system 150 does not include an insulated intermediate holding tank.
In various embodiments of the present disclosure, CHE system 164 can be or can include, for example, CHE system 164a as described in reference to
In the illustrated embodiment, CHE system 164 is not (and is not part of) a pressure-control component of wellhead 104 or blow-out preventer 108. Instead, in the illustrated embodiment, CHE system 164 is located at a surface location separate from (for example, a surface distance 166 from) wellhead 104 on the low-pressure side of operations, and drilling fluid 180 flowing from wellbore 101 flows through cryogenic heat exchange system 164 after flowing through shale shaker 162 and prior to returning to mud pump 154. In some embodiments, surface distance 166 is about 50 feet; in other embodiments, surface distance 166 can be a greater or lesser distance. In the illustrated embodiment, a filter 163 is disposed between intermediate circulation pump 153 to filter out particulate matter from drilling fluid 180 prior to flowing into CHE 164.
In some embodiments, CHE system 164 is a transportable unit. For example, if wellbore drilling system 100 is for drilling a wellbore at, for example, a first wellsite, CHE system 164 can be configured to be disconnected and transported as a unit from wellbore drilling system 100 to another, separate wellbore drilling system drilling a separate wellbore at, for example a second wellsite.
The example well system 100 can take a variety of forms and can include fewer components and/or a number of different or additional components. For example, circulation system 150 can include various settling pits, valves, and other associated components in addition to those described above. Furthermore, while well system 100 is shown as a land-based drilling rig, the apparatus, systems and methods described herein can be applied to offshore drilling rigs and to other well systems other than drilling systems (for example production wells or workover rigs) and to wellbore fluids other than drilling fluids.
In the illustrated embodiment, liquid nitrogen 250a can be injected into interior volume 206a through an inlet port 252a by an injection system 254a, such that the liquid nitrogen 250a fills or substantially fills interior volume 206a. Drilling fluid 180 flowed from a wellbore and passing through drilling fluid conduit 202a can be cooled by heat exchange with liquid nitrogen 250a across a wall 222a of drilling fluid conduit 202a, prior to the drilling fluid 180 being pumped back into the wellbore or recirculated for additional cooling as described above with respect to
In the illustrated embodiment, annular volume 216a can be at least partially filled with water 270a. The cooling of drilling fluid 180 by heat exchange with the liquid nitrogen 250a across the wall 222a can include cooling the drilling fluid 180 by heat exchange with the water 270a, with the water 270a in turn being cooled by heat exchange with the liquid nitrogen 250a. In some embodiments, water 270a can sufficiently cooled by liquid nitrogen such that water 270a is in a solid (ice) state as the drilling fluid 180 flows through drilling fluid conduit 202a. In some embodiments, the CHE system of the present disclosure can provide water in the annular volume 216a at temperatures below 32° F. on surface. The heat exchanger will be available to deliver water in the temperature range of −4° F. to −30° F. which should be a significant improvement over the use of water chillers. Water 270a can act as a buffer between the liquid nitrogen and the drilling fluid and can, in some embodiments, afford better control of the heat exchange process than if no water buffer were present.
At step 606, the circulation and CHE systems are assembled and connected to the well system, with the CHE system positioned, for example, at a surface location separate from a wellhead of the wellbore, and the interior volume is at least partially defined by an inner surface of an outer jacket of the CHE system, as described above. At step 608, an interior volume of a CHE system is filled with liquid nitrogen.
Proceeding to step 610, drilling fluid is circulated in the wellbore (for example, in a downhole direction down a drill string and thence uphole through the wellbore annulus to the surface). In some embodiments, the liquid nitrogen filling step 608 occurs after the drilling fluid flow is initiated in the wellbore, or another suitable time. At step 612, drilling fluid is flowed from the wellbore to a drilling fluid conduit of the CHE system at least partially disposed within the interior volume. At step 614, the drilling fluid flowing through the drilling fluid conduit is cooled by heat exchange with the liquid nitrogen across a wall of the drilling fluid conduit.
At step 616, in some embodiments, the operator can determine (based on temperature measurements or other data or information) whether repeated cooling of the drilling fluid is desired or necessary, prior to returning the drilling fluid to the wellbore. If at step 616 it is determined that such repeated cooling is necessary or desirable, the method proceeds to step 618 in which at least a portion of the drilling fluid is diverted (for example, by a diverter that is a component of or fluidically connected to the insulated circulating tank) to an intermediate recirculating pump. Proceeding to step 620, the diverted portion is again cooled in the CHE system. After step 620, the method then proceeds back to step 616 in which the operator again can determine (based on temperature measurements or other data or information) whether repeated cooling of the drilling fluid is desired or necessary.
If at step 616 it is determined that no further cooling of the drilling fluid is desirable or necessary, the method then proceeds to step 622 in which the portion is flowed back to the wellbore (for example, via a mud pump). After step 622, the method returns to step 610 in which the drilling fluid continues to be circulated in the wellbore.
In some embodiments, the method may not include a repeated-cooling step and, in such embodiments, steps 616, 618, and 620 are omitted and, after step 614, the method proceeds to step 622 in which all of the drilling fluid flowed through the drilling fluid conduit is flowed by a mud pump back to the wellbore.
The term “uphole” as used herein means in the direction along a drill string, tubing, or the wellbore from its distal end towards the surface, and “downhole” as used herein means the direction along the drill string, tubing, or the wellbore from the surface towards its distal end. A downhole location means a location along the drill string, tubing, or wellbore downhole of the surface.
A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure. For example, example operations, methods, or processes described herein may include more steps or fewer steps than those described. Further, the steps in such example operations, methods, or processes may be performed in different successions than that described or illustrated in the figures. Accordingly, other implementations are within the scope of the following claims.
