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    • 专利摘要:
    A dual gradient cementation system is modeled in a modeled underwater wellbore. The modeled dual gradient cementation system comprises a plurality of components including a standing lift pump (MLP) coupling an underwater rotating device (SRD) to a surface mud return line, wherein the MPL is located at a Underwater depth and SRD diverts fluids from the ring ring away from the riser. The modeled double gradient cementation system is simulated in operation, assuming a 100% fluid loss value at the MPL underwater depth, and a fluid property of a non-static fluid simulated in the MPL. the double gradient cementation system simulated in operation is estimated. Then, a real double gradient cementation operation in a real underwater wellbore, in which a real non-static fluid corresponding to the simulated non-static fluid demonstrates the property of the fluid.
    公开号:FR3040518A1
    申请号:FR1657478
    申请日:2016-08-01
    公开日:2017-03-03
    发明作者:Gaurav Gupta；Zhuoming Lou；Dhaval Trivedi
    申请人:Halliburton Energy Services Inc；
    IPC主号:
    专利说明:

    SOFTWARE SIMULATION METHOD FOR ESTIMATING FLUID POSITIONS AND PRESSURES IN THE WELLBORE
    FOR A DOUBLE GRADIENT CEMENT SYSTEM
    CONTEXT
    The present disclosure relates to operations of underground formations, and more particularly, software simulation methods for estimating fluid characteristics in a wellbore during a simulated or real double gradient cementation operation.
    [0002] Hydrocarbons (ie, gas and oil) are found in reservoirs in underground formations on land, inland waters and in offshore areas around the world. The term "submarine" describes the exploration, drilling and development of hydrocarbons in submarine ocean locations. The development of subsea hydrocarbon reservoirs requires specialized equipment to safeguard the environment, protect underwater operators and make underwater exploration economically viable.
    [0003] A variety of underwater systems are available for drilling a borehole into an underground formation below a water surface (eg, below the seafloor) and for production. hydrocarbons therefrom, including floating drillships, floating oil platforms, fixed offshore platforms, self-raising platforms, etc. The type and complexity of such underwater systems often increase with increasing depth of water in which drilling is performed. As water depth increases, so does the cost and technical difficulty of drilling wells. Such costs and technical difficulties include the management of dynamic and static fluid pressures within the wellbore to maintain drilling within acceptable pressure ranges between the interstitial pressure and the fracture gradient pressure of the wellbore. underwater formation, particularly at increased depths in which the fracture gradient decreases.
    [0004] A method used to dig subsea wellbores at such deep water depths is double gradient drilling. Double gradient (DG) drilling techniques seek to adjust the density of the fluid column contained in the wellbore. Conventional simple gradient drilling technology controls wellbore pressure by using a column of drilling fluid at a substantially constant density from the bottom of the wellbore upwards, eg, to the platform. On the other hand, DG drilling attempts to control the wellbore pressure using a low density fluid, with about the same density as the water above the formation (eg, salt water above ocean floor), from the platform to the ocean floor, and a higher density drilling fluid within the actual formation, from the ocean floor down to the wellbore. DG drilling techniques actually stimulate the drilling platform that is located on the sea floor and thus manages the pressures present during the drilling operation. This temperature management also relieves the previous constraints on the depth to which the casing could be inserted without making large reductions in the diameter of the train.
    After drilling a wellbore in a submarine location, a zonal isolation of the wellbore is performed by forming a cement sheath therein. The cement sheath is formed by introducing a casing string into the wellbore, thereby forming a ring between the wall of the wellbore and the casing string, and pumping a cement slurry. The cured cement slurry to form the cement sheath which inter alia supports and positions the casing string in the wellbore, binds the outer surface of the casing string to the formation, maintains a zonal isolation between the environment and the wellbore (eg, prevents contamination) and increases the structural integrity of the wellbore. This process is called "primary cementing" or simply "cementing" as it is used here.
    [0006] Both drilling and primary cementing in a DG system (ie, a "DG operation and drilling system" and "DG operation and cementing system", respectively) present challenges, despite advanced pressure management. For example, during drilling and cementing, leaks, backflows, water hammers and potential eruptions are possible. As an example, an increase in water hammers during the descent of the casing string into the wellbore can induce a loss of fluid that could compromise the wellbore. In addition, subsidence of formation in the ring during the cementing operation may also cause pressure fluctuations causing fluid losses to the formation.
    BRIEF DESCRIPTION OF ILLUSTRATIONS
    The following figures are presented to illustrate certain aspects of the present disclosure, and should not be considered as exclusive embodiments. The object of the invention described may be subject to considerable modifications, alterations, combinations and equivalents in form and in function, without departing from the scope of this description.
    [0008] Figure 1 illustrates a conventional simple gradient well system as described herein.
    Figure 2 illustrates a dual gradient well system, according to one or more embodiments of the present disclosure.
    Figure 3 is a graph illustrating the difference in hydrostatic pressures between a double gradient well system and a simple gradient well system, according to one or more embodiments of the present disclosure.
    Figure 4 is a graph illustrating the difference in hydrostatic pressures exerted on a work train and a ring in the context of a dual gradient well system, according to one or more embodiments of the present disclosure. .
    Figure 5 illustrates a dual gradient well system during a cementing operation, according to one or more embodiments of the present disclosure.
    Figure 6 is a graph illustrating the difference in hydrostatic pressures exerted on a work train that has been raised to the seafloor and a ring in a dual gradient system, according to one or more embodiments of the invention. present disclosure.
    Figure 7 illustrates a screen shot of an iCEM® service developed to implement the systems and methods of some embodiments of the present disclosure, a 100% fluid loss being assumed at depth. of the MLP, which could be like a modified lost traffic case.
    Figure 8 is a flowchart of an exemplary system that can operate to implement one or more embodiments of the present disclosure.
    DETAILED DESCRIPTION
    The present disclosure relates to operations of underground formations, and more particularly, software simulation methods for estimating fluid characteristics in a wellbore during a simulated or real double gradient cementation operation.
    More specifically, the embodiments of the present disclosure allow the monitoring and estimation of a property quality of the fluid during a simulated or real double gradient cementation (DG) operation. Such monitoring and estimation allows the development of a DG cementing system for real use that is optimized for actual operation, adjusting actual DG cementing operations in real time to perform real-time optimization, and generally to increase the reliability and success of DG cementing operations. Therefore, some embodiments described herein allow operators to simulate a DG cementing operation and then perform manipulations on the simulated system to increase the reliability and efficiency thereof. In other embodiments, the operators can simulate a real DG cementing operation in real time and perform one or more manipulations on the actual operation to increase the reliability and efficiency of a cementing operation DG that is already ongoing, including the use of the data received in real time.
    One or more illustrative embodiments disclosed herein are set forth below. All features of an actual implementation are not described or illustrated in this application for the sake of clarity. It should be understood that in developing an actual embodiment incorporating the embodiments disclosed herein, many implementation-specific decisions must be made to achieve the developer's objectives, such as compliance with the constraints imposed by the system, through lithology, commercial activities, government and other constraints, which may vary from one implementation to another and from time to time. Even though developer efforts can be complex and time-consuming, such efforts would, nonetheless, be a routine task for the tradespeople who benefit from this disclosure.
    In addition, it will be understood that although the embodiments of this document are described with reference to subsea operations, the methods and systems described herein are equally applicable to other operations of cementing underground formations. using a DG system for the recovery of hydrocarbons from an underwater location, including freshwater, deep shallow seawater, etc., without departing from the scope of this disclosure.
    Although the compositions and methods are described herein in terms of "comprising" various components or steps, the compositions and methods may also "consist essentially of" or "consist of" various apparatus or steps. When the term "comprising" is used in a claim, it is undefined.
    As used herein, the term "substantially" means greatly, but not necessarily totally.
    The use of directional terms such as above, below, above, below, up, down, left, right, up the hole, down the hole, etc., are used in relation to the illustrative embodiments as illustrated in the figures, the upward direction being upwardly of the corresponding figure and the downward direction being downward of the corresponding figure, the direction towards the the top of the hole being towards the surface of the well and the downward direction of the hole being towards the well's hoof.
    The embodiments described herein relate to methods and systems for monitoring, detecting, controlling and / or logging that are capable of tracking any one or more of the plural parameters of a plurality of actual fluids. or simulated non-static during a DG cementing operation using software simulation and / or monitoring. As used herein, the term "during a cementing operation DG" includes operations, fluids used therein, etc., which are performed directly before or after the cementing operation. For example, the movement of drilling fluid from a wellbore in anticipation of primary cementation is included in the term "during a cementing operation DG". As used herein, the term "non-static", which can be used interchangeably with the term "circulating", with reference to a real or simulated fluid describes a fluid in motion or undergoing movement ( eg, a vibration). The fluids described herein are generally non-static as they flow through the DG cement system at one or more locations, including transfer to a surface location above the surface of the cementation system. water. As used herein, the term "surface" (including "water surface" or "sea surface") describes the interface between water (eg, the ocean) and the atmosphere. The term "ocean floor" (or "sea floor") describes the interface between the earth's crust and water (eg, the ocean).
    As previously described, unlike conventional underwater cementing and drilling systems, the dual gradient cementation and drilling systems described herein utilize two fluid densities to manage system pressures and simulate drilling. as for a surface location. As an illustration, Figure 1 illustrates a conventional single gradient underwater well system 100 (eg, for drilling and cementing). The system 100 can be used to dig and cement a wellbore 102. An underwater riser 106 extends from the drilling platform 104 at the surface 108 across the sea floor, and is coupled to an underwater wellhead 112 located on the ocean floor 110. The riser 106 may be coupled to an anti-blowout device (not shown) in the underwater wellhead 112. As it is As used herein, the term "riser" refers to a hollow pipe that connects a drilling platform to an underwater wellhead and receives fluid for return over the sea surface; the riser prevents such fluids from spilling out of the upper part of the underwater well head and onto the sea floor. The riser often has a large diameter and acts as a temporary extension of the wellbore to the surface. As used herein, the term "drilling rig" describes a platform located above the sea surface (eg, a floating, permanent, self-elevating platform, etc.) containing machinery and equipment. equipment for drilling a wellbore. Such drilling platforms generally include sludge tanks, mud pumps, derrick or mast, winches, turntable, drill string, and the like. The term "underwater wellhead" (or simply "wellhead") as used herein describes the termination end of the seafloor side of a wellbore that incorporates at least equipment for the installation of the casing suspension devices during the wellbore cementation phase, and which provides a certain level of pressure control.
    As it is demonstrated, a work train 114 extends inside the riser 106 from the drilling platform 104, through the underwater well head 112 and into the well. The work train 114 may be a drill string for drilling the wellbore 114 or a conduit for conveying the cement slurry, eg, in a cementing operation. The term "work train" as used herein refers to any tubing string used to introduce a fluid or to perform a downhole operation, including an articulated or coiled tubing string (eg, to convey suspension of cement to form a cement sheath).
    Referring to a drilling operation, simple gradient systems, such as system 100, circulate drilling mud or other fluids (e.g., separation fluid) from the bottom portion. of the work train 114 while drilling through the subsurface formation 116 below the seafloor 110 to form a wellbore 102. The slurry then exits the work train 114 to enter the ring 120 into the wellbore 102 and higher through the underwater well head 112 into the ring 122 between the riser 106 and the work train 114 above the seafloor 110. The density of the drilling mud for the drilling of the wellbore 102 is necessary to maintain drilling within the acceptable pressure ranges between the interstitial pressure gradient and the fracture gradient pressure of formation 118. Failure to do so could result in failure lances, which may lead to leakage of drilling mud or other fluids from the wellbore into the ocean, failure or damage to wellbore 120, or rash at the underwater wellhead 112, among other risks. As used herein, the term "interstitial pressure gradient" (or simply "interstitial pressure") describes the fluid pressure within the formation pores (eg, a wellbore) at a point in time. given depth. The term "fracture gradient" as used herein describes the pressure required to induce fractures in a formation (eg, a wellbore) at a given depth.
    When the drilling mud comes out of a drill bit at the bottom of the work train 114, and passes through the subsea drilling head 112 in the ring 122 of the riser 106, the difference in density drilling mud in the ring 122 of the riser 106 and the ocean water surrounding the ocean results in the formation of extreme pressures at the "sludge line" or seafloor, and thus, at the underwater wellhead 112. Therefore, only a pressure gradient exists that begins at the surface 108 and extends down the wellbore 102 and the complete pressure of the entire the drilling mud column manifests itself, which raises the pressure on the underwater wellhead 112 as well. Such elevated internal pressures at the subsea wellhead 112 increase the likelihood of eruption and require additional casing trains, shallow casing points, heavier and longer risers 106 and plates. Larger and more expensive forms 104.
    In order to thwart the pressure problems experienced by conventional simple gradient systems, the DG systems have been developed, as shown in FIG. 2. Referring now to FIG. 2, while referring to FIG. , which illustrates an underwater DG well system 200 (eg, for drilling and cementing). Like the simple gradient system 100 of FIG. 1, the DG 200 system comprises a drilling platform 104, a work train 114, a riser 106, an underwater wellhead 112 and a wellbore 102. Further, as a portion (i.e., integral to) of the subsea wellhead 112 or in operation in association with it, an underwater rotating device (SRD) 124 is in line with a head 112. As used herein, the term "underwater rotary device" is equipment configured to move back fluids in the ring (eg, drilling mud) from the ring. 122 of the riser 106. That is, the SRD 124 does not interfere with the work train 114 or the fluids within the work train 114 that pass through the SRD 124, the wellhead. underwater 112 and into the wellbore 120, and likewise does not prevent any fluid from returning to the sea floor 11 0 in the ring 120 of the wellbore 102. However, the SRD 124 blocks the flow of such fluids that pass through the SRD 124 and to the ring 122 of the riser 106. It will be understood that even though the SRD 124 is illustrated as being above the subsea wellhead 112, the SRD 124 may be located below the underwater wellhead 112 or integral with the subsea wellhead 112 without deviate from the scope of this disclosure.
    The SRD 124 is fluidly coupled to a slurry lift pump (MLP) 126 through a surface mud return line 128. The mud surface return line 128 can deliver the ring fluids. to a receiving tank 130. The term "slurry pump" describes a pump configured to deliver fluids (eg, slurry or drilling fluid, separation fluid, etc.) from a location below. ocean floor (eg, in the borehole below the seafloor, or in some cases in the riser above the seafloor, but below the sea surface) to a line of back of rising mud on the surface. The "surface mud return line" describes a hollow pipe for transporting fluids to a surface location. The term "casing string" describes a pipe (which may be threaded or otherwise attached to additional segments of pipe of the casing string, if any) that has descended into a wellbore and cemented into the wellbore -this.
    It will be understood that even if a receiving tank 130 is illustrated on the surface of the drilling platform 104, any receptacle capable of receiving the fluids from the surface mud return line 128 can be used in accordance with embodiments of the present disclosure, including a separate platform or floating vessel, a pipeline configured to transport fluids off site, etc. In operation, the DG 200 system includes a fluid (eg, seawater) in the ring 122 of the riser 106 which has a density similar or substantially similar to the surrounding seawater (e.g. ., low density). Therefore, the low density fluid (eg, seawater) thus remains static in the ring 122 of the riser 106. The drilling or cementing operations are performed by pumping fluids having the right densities through the work train 114 and into the ring 120 of the wellbore 102. However, unlike conventional simple gradient systems (e.g., the system 100 of Fig. 1), fluids from the ring 120 of the wellbore 102 to mount in the ring 122 of the riser 106 and are instead diverted to the surface mud return line 120 by the operation of the SRD 124 and the MLP 126. The configuration of the DG 200 system can reduce the internal pressure on subsea wellhead 122 at the seafloor by as much as 50% because, even if a high density sludge or fluid is used in the wellbore , this one does not enter not in the riser.
    Therefore, the DG 200 system creates two hydrostatic gradients, a seawater type gradient from surface 108 to seafloor 110 to handle wellbore 102, and a high density gradient from the floor. 110 to the bottom of the wellbore 102 to prevent the wellbore 102 from collapsing and to remove debris or other debris and fluids from the wellbore. Dual hydrostatic gradients do not affect bottom well pressure, which remains unchanged compared to a simple gradient system. FIG. 3 illustrates the difference in the hydrostatic pressures between a DG system and a simple gradient system, thus showing the double hydrostatic pressure phenomenon of a DG 200 system. Referring now to FIG. 3, the x-axis represents the pressure and the y-axis represents the depth. Dashed line 302 represents the sea floor 110 (FIGS. 1 & 2), also referred to as the "mud line". Line 304 represents a simple gradient system and line 306 represents a DG system. As can be seen, two pressure gradients are represented by line 306, but both line 306 and line 304 meet at the same downhole pressure 308.
    Referring now to Figure 4, a graph is shown showing the difference in the pressures experienced by a work train 114 and the rings in a DG 200 system (FIG 2). Referring now to Figure 4, the x-axis represents the pressure and the y-axis represents the depth. Dashed line 402 represents ocean floor 110 (FIG 2), also referred to as the "mud line". Line 404 represents the pressure experienced by the work train 114 (eg, a drill string) and a line 406 represents the pressure experienced by the rings 122 and 120, either in the riser 106 or in the wellbore. 102, respectively (FIG 2). C.-ad., the line 406 above the seafloor 110 represents the ring 122 in the riser 106, while the line 406 below the seafloor 110 represents the ring 120 in the wellbore 102 As can be seen, the pressure experienced by the work train 114, represented by the line 404, and the ring 120 is identical above the ocean floor 110, where it then diverges and the pressure experienced by the ring 120 in the wellbore 102 decreases relative to the work train 114. The reason is that the fluids of the ring 122 in the riser 106 are generally lighter than the fluids in the ring 120 in the wellbore 102 , creating different pressures.
    Referring now to Figure 5, while referring to Figure 2, there is illustrated a DG 500 well system during a cementing operation. As illustrated, the casing string 502 is deposited in the wellbore 102 and a ring 504 is formed between the outside of the casing string 502 and the wellbore 102. During a cementing operation, a The cement slurry is pumped out of the work train 114 (eg, using a coiled tubing, articulated pipe, etc.) into the ring 504 between the tubing string 502 and the wellbore 102. Prior to pumping of the cement slurry, a drilling fluid and / or a separating fluid can be pumped through the ring 504 and out through the wellbore 102 through the return line of the surface sludge 128. Therefore, the work train 114 at a given moment may contain one or more fluids, which are generally high density fluids, for the same reasons presented above in maintaining the equilibrium between the interstitial pressure and the pressure of the fracture of formation 1 18. In other cases, the end portion of the high density fluid (ie, the tail end of the fluid) may be in the work train 114 at any location along the the length of the work train 114. This location with reference to the work train 114 is called "the mud head". The term "sludge head" also applies to other components of the DG system and describes the highest point at which a fluid (eg, a slurry of cement, or other fluids such as separation fluid, drilling mud, etc., for placement in a wellbore) is within a work train 114, a mud return line at the surface, or another line of fluid flow in a circulating DG system.
    Referring now to Figure 6, a graph is shown showing the difference in the pressures experienced by a work train 114 that has been raised to the seafloor 110 out of the wellbore 102 and the rings in a DG 200 system (FIG 5). In Figure 6, the x-axis represents the pressure and the y-axis represents the depth. Dotted line 603 represents seafloor 110 (FIG.5), also referred to as the "mudline". The dotted line 602 represents the mud head in the work train 114. Line 604 represents the pressure experienced by the work train 114 and line 606 represents the pressure experienced by the rings 122 and 120, either in the riser 106 either in the wellbore 102, respectively (FIG.5). That is, line 606 above seafloor 110 represents ring 122 in riser 106, while line 606 below seafloor 110 represents ring 120 in the waterwell. drilling 102. As illustrated, the work train 114 is not pressurized until it meets the mud head, and from there it grows constantly. The pressure experienced by the two rings 122 and 120 is identical to that illustrated in FIG. 4; however, at the seafloor 110, the work train 114 encounters no pressure different from that of the ring 120 in the wellbore 102 because the MLP 126 can be adjusted to ensure that the pressures are the same.
    The graphs of FIGS. 3, 4 and 6 illustrate the function of a DG system. Embodiments of the present disclosure permit software simulation of such systems assuming a 100% fluid loss situation at a MLP location, which could be at seafloor level or at a certain location. In doing this, the simulation methods described herein allow the estimation and evaluation of various fluids within the DG system, including the fluid properties thereof. The 100% fluid loss assumption allows simulation of a DG system because it takes into account the diversion of the wellbore ring fluids from the wellbore without letting them flow into the wellbore. riser of I ring.
    Specifically, the embodiments described herein monitor and estimate a fluid property of a modeled DG cementation system, which may be based on a real or hypothetical underwater wellbore. Whether based on a real or hypothetical underwater wellbore, the modeled DG cementation system (and correspondingly the actual DG cementation system, if any) include a plurality of components, such as those described above, comprising a riser coupling to a drilling rig and an underwater wellhead, a slurry lifting pump (MLP) coupling to an underwater rotating device (SRD) at a surface mud return line, a work train extending from the drilling platform through the underwater wellhead and into the interior of a casing train, and a ring formed between an outside of the casing train and underwater borehole. The MPL is placed at a given submarine depth that is at or above the sea floor, and the SRD diverts fluids from the ring from the ring of the wellbore of the column. rising as previously described.
    The DG cementing system modeled, whether based on a hypothetical or real DG system, is simulated in operation using a simulation software in which it is assumed that the loss of fluid is 100. % at the depth of the MLP. Thus, the flow of fluid above the depth of the MLP location is not simulated, although, as described herein, such a fluid (e.g., riser fluid) can to be static. When this is the case, it is still within the strings of an operator to model certain fluid properties of the riser fluid (hypothetical or actual) and to determine the effectiveness of such a fluid based on the Surrounding properties in the embodiments of the present disclosure, without departing from the scope described herein.
    In some embodiments, iCEM® service simulation software, available from Halliburton Energy Services, Inc. in Houston, Texas can be used to simulate the modeled DG cementation system. In addition, the iCEM® service can be used to also model the hypothetical or current DG system, without departing from the scope of this disclosure. As shown in FIG. 7, which illustrates a screenshot of an iCEM® service developed to implement the systems and methods of some embodiments of the present disclosure, a 100% fluid loss being assumed. at the depth of the MLP, which could be like a modified lost traffic case. The configuration of other simulation software systems may appear different from the configuration of the iCEM® service illustrated in Figure 7, without departing from the scope of this disclosure, provided that the simulation software system is capable of assume a fluid loss of 100% at the depth of the MLP.
    Based on the model DG cementation model, simulated during operation, a fluid property of a simulated non-static fluid can be estimated and the information gleaned from the simulation used to perform a double DG cementing operation in a real submarine wellbore, the actual non-static fluid corresponding to simulated non-static fluids demonstrating the estimated fluid property. That is, a real DG cementing system that is identical in form and structure or extrapolated appropriately (eg, size, shape, etc.) to be simulated, a system DG modeled cementation is established and a DG cementing operation carried out based on information from the modeled, simulated DG cementation system.
    In other embodiments, a downhole tool may be introduced into a real DG cementation system at a depth less than the depth of the MLP. The downhole tool can be a logging tool that can make real-time measurements while the actual DG cementing system is in operation. Simultaneously with the operation of the actual DG cementing system, a simulated DG cementing system based on the shape and structure of a real DG cementing system can be executed. Data from the downhole tool can be entered into a real-time or simulated system. Based on the changes to the simulated system that received the actual data, adjustments to the actual DG cementing system during operation can be made to avoid risks or improve actual operation.
    In some embodiments, a control system comprising a readable non-transitory medium for storing instructions for execution by a processor is coupled to a downhole tool, and is capable of performing the steps described. here: Modeling a hypothetical or actual DG cementing system, simulating the model in operation and assuming a 100% fluid loss value at the depth of the MLP, obtaining at least one measurement from the downhole tool, entering the at least one measurement into a simulated, modeled DG cementation system and estimating at least one fluid property of a simulated non-static fluid that corresponds to a real non-static fluid.
    Referring now to Figure 8, which illustrates a flowchart of an exemplary system 800 that can operate to implement the activities of multiple methods, according to various embodiments of the present disclosure. The system 800 may include a tool housing 806 having a downhole logging tool. The system 800 may be configured to operate in accordance with the teachings herein to perform modeling, simulation, reception and capture measurement in modeling, simulation, and property estimation of a fluid. a non-static fluid as described above.
    The system 800 may comprise a control system 820 comprising a non-transitory readable medium, such as a memory 830 for storing instructions for execution by a processor 810. The memory 830 may include, without limitation, a ROM memory, RAM memory, magnetic disk storage device, optical storage device, flash memory and other electronic, magnetic and / or optical memory devices, and combinations thereof. The processor 810 may be configured to model, simulate in operation, and to estimate a fluid property of a simulated DG simulated cementation system, whether based on a simulated or real DG system. Processor 810 can be configured to execute, for example, iCEM® service simulation software.
    The system 800 may also include a bus 837, wherein the bus 837 provides electrical conductivity among the components of the system 800 (e.g., between the control system 820 and the logging tool 210). The bus 837 may comprise an address bus, a data bus and a control bus, a cable line, each independently configured or in an integrated format. The bus 837 can be realized using a number of different communication media for distributing components of the system 800. For example, the bus 837 can be a wired line or a network that allows a signal from of the downhole logging tool 110 to be transmitted to a control system 820, even if they are not physically in the same location (e.g., the control system 820 is located at the level of a surface location and the downhole logging tool 110 is in the wellbore). The use of the bus 837 can be regulated by the control system 820.
    The system 800 may include one or more display units 860, which may be used with the instructions stored in the memory 830 to implement a user interface to monitor the modeling, simulation, input, and estimation of data. Embodiments described herein and / or operation of logging tool 810. The user interface may be used to enter parameter values from downhole logging tool 110. Generally, the user interface is located near the 820 control system.
    As mentioned above, the embodiments described herein model and simulate a DG cementing system in operation, and may also include real-time data capture, for use in estimating a fluid property of a non-static fluid simulated in the model of the modeled simulated DG system, which could correspond to a real non-static fluid in the actual DG cementing operation (eg, an operation performed simultaneously with the simulation). The non-static fluid may include, without limitation, a drilling mud, a separating fluid, a cement slurry, and any combination thereof.
    The property of the fluid may be one or more of the fluid pressure, the position of a fluid, a flow rate, a fluid quality, and any combination thereof. . The fluid pressure describes both the hydrostatic pressure and the friction of the fluid. Hydrostatic pressure represents the pressure exerted by gravity at a given point within the fluid, and increases with depth relative to the surface. Fluid friction describes the friction generated as fluids move relative to a surface (eg, with respect to the casing string, work train, wellbore, etc., and combinations thereof) . The position of the fluid describes the location of a given fluid (eg, when two or more fluids are in a work train, a ring in a return line of the surface mud) and may describe any location. through the entire system of the DG cementing system, including a wellbore, riser, surface mud return line, etc. Fluid quality describes a characteristic (e.g., rheology) of the fluid itself including, but not limited to, viscosity, density, temperature, pressure, etc., and any combination thereof. Combinations of these fluid properties can also be estimated, e.g., the position of the fluid for one or more steps during a cementing operation and the fluid pressure associated with data points during one or more several steps of this type. For example, the simulation software can perform iterative estimates of fluid pressure and fluid flow at various fluid positions.
    In some embodiments, the property of the fluid that is estimated is the hydrostatic pressure in a ring between a casing string and a wellbore (ie, the ring 504 of FIG. ), the target hydrostatic pressure being between an underwater wellbore interstitial pressure and an underwater wellbore fracture gradient, as previously mentioned. When the estimated hydrostatic pressure of the ring is outside the target hydrostatic pressure between the interstitial pressure and the fracture gradients of the wellbore, corrective actions must be taken by the operator. Indeed, one or more components of the modeled simulated DG cementation system can be manipulated based on the information gleaned from one or more of the estimated fluid properties of the simulated non-static fluid. The manipulation can be done for any reason, such as, for example, to increase the efficiency of the simulated DG simulated cementation system, to ensure that the hydrostatic pressure is within the target values, to increase the efficiency of the simulated DG cementation system, etc., and combinations thereof.
    Such manipulation may include, without limitation, the manipulation of the modeled DG system itself, which is only possible when the modeled DG system is based on a hypothetical system, and not on an already existing real system. Manipulation of the system may include increasing or decreasing the width of the wellbore, increasing or decreasing the width of the riser, increasing or decreasing the speed of the MLP, increasing or decreasing the pressure of the MLP, increasing or decreasing the drilling speed, increasing or decreasing the size and number of casing trains, increasing or decreasing the size of the casing. ring between the casing string and the wellbore, etc., and any combination thereof.
    The manipulation of the fluid property of the simulated non-static fluid can also be used including, without limitation, the flow of the non-static fluid, the fluid pressure of the non-static fluid, the density of the non-static fluid. , the viscosity of the non-static fluid, the friction of the non-static fluid, etc., and any combination thereof. For example, the density and / or viscosity of the simulated non-static fluid can be manipulated by simulating foaming of the fluid, introducing weighing agents, introducing suspending agents, etc., and any combination of those -this. In another example, the frication of the simulated non-static fluid can be manipulated by simulating the introduction of a friction reducing agent.
    After manipulation of one or more elements of the simulated and modeled DG cementation system and / or simulated non-static fluid and that the simulated DG cementation system works as desired, a DG cementation system. real can be built and DG cementing operation can be carried out with the knowledge gleaned from the simulated DG cementation system, modeled in which the actual DG cementing system is now based for modeling. Therefore, the manipulations used to improve the simulated, modeled DG system are used to perform the actual DG cementing operation.
    In some embodiments, a real DG cementing operation is performed simultaneously with a simulated DG operation, modeled, the simulated DG operation being modeled based on the parameters (system and fluid parameters) of the operation. real. A downhole logging tool can be used to capture real-time measurements from the actual DG cementing operation in the simulated, modeled DG operation. Real-time measurements can include fluid flow, density, temperature, pressure, etc. By capturing real-time measurements in the simulated, modeled DG system, the effects of real-time measurements on the system as a whole can be monitored and any manipulations that could increase the efficiency or effectiveness of the operation. actual DG cementation can be identified. These manipulations include all the manipulations described above. The manipulations may first be performed by the simulated DG system, modeled and, if they are effective and desirable, can be performed in near real time at the level of the actual DG cementing system in operation. Therefore, e.g., true density, true viscosity and true fiction, etc., of the actual non-static fluid in the actual DG cementation system is manipulated based on the data from the modeled simulated DG system. For example, the actual non-static fluid may be foamed, or any of the additional components described herein (e.g., weighing agents, etc.) may be added thereto, or by any other means to obtain the desired handling results.
    Embodiments of the present invention include: Embodiment A: A method comprising: (a) modeling a dual gradient cementation system in a modeled underwater well bore, wherein the modeled dual gradient cementation system comprises a plurality of components including a riser coupled to a drilling platform and an underwater wellhead, a slurry lifting pump (MLP) which couples an underwater rotating device (SRD) at a surface mud return line, a work train extending from the drilling platform through the underwater wellhead into an interior of a casing train, and a ring formed between an outside of the casing string and the underwater well bore, wherein the MPL is located at an underwater depth, and wherein the SRD diverts ring fluids from the riser ring ; (b) the simulation of the dual-gradient cementation system modeled in operation, in which a 100% fluid loss value at the underwater depth of the MPL is assumed; (c) estimating a fluid property of a simulated non-static fluid in the simulated dual gradient cementation system in operation; (d) performing a true double gradient cementation operation in a real submarine wellbore, wherein the actual non-static fluid corresponding to the simulated non-static fluid demonstrates the property of the fluid.
    Embodiments A comprise one or more of the additional elements, in any combination: [0056] Element A1: in which the property of the fluid is chosen from the fluid pressure, the position of a fluid, a flow rate, fluid quality, and any combination thereof.
    [0057] Element A2: wherein the simulated non-static fluid is selected from a drilling mud, a separating fluid, a cement slurry and any combination thereof.
    [0058] Element A3: in which the property of the fluid is the hydrostatic pressure in the ring and a target of the hydrostatic pressure lying between an interstitial pressure of the subsea wellbore and a fracture gradient of the wellbore under -marine.
    [0059] Element A4: Also comprising the manipulation of one or more components of the simulated simulated dual gradient cementation system or a simulated non-static fluid characteristic prior to step (d).
    Element A5: Also including the manipulation of a pump flow of the MPL before step (d).
    Element A6: Also including the manipulation of a pump pressure of the MPL before step (d).
    Element A7: Also comprising the manipulation of a simulated non-static fluid flow before step (d).
    Element A8: Also comprising the manipulation of a simulated non-static fluid pressure before step (d).
    Element A9: Also comprising the manipulation of a simulated non-static fluid density before step (d).
    Element A10: Also comprising the manipulation of a viscosity of the simulated non-static fluid before step (d).
    Garlic Element: Also comprising the manipulation of at least one of the density and / or viscosity of the simulated non-static fluid prior to step (d), and wherein the manipulation comprises simulated foaming of the simulated non-static fluid.
    As a nonlimiting example, examples of combinations applicable to Embodiment A include: Al-Ail; Al, A3, and A5; A6 and A7; A4, A8, A9, and A10; A2 and A6; Al, A4 and Ail; etc.
    Embodiment B: Process comprising (a) introducing a downhole logging tool into a real double gradient cementation system when operating in an underwater wellbore, wherein the real double-gradient cementation system comprises a plurality of components comprising a riser coupled to a drilling rig and an underwater wellhead, a slurry lifting pump (MLP) which couples a sub-rotating device. (SRD) at a surface mud return line, a work train extending from the drilling platform through the underwater wellhead into an interior of the casing train, and a ring formed between a outside of the casing string and the underwater wellbore, in which the MPL is located at a first underwater depth, wherein the SRD diverts fluids out of the ring ring away from of the riser, and wherein the downhole logging tool is located at a second underwater depth below the MPL; (b) modeling the real double gradient cementation system, comprising the plurality of components, the first submarine depth, and the second underwater depth; (c) simulation of the dual-gradient cementation system modeled in operation, in which a 100% fluid loss value at the first submarine depth of the MPL is assumed, and (d) obtaining at least one measurement from the downhole logging tool; (e) capturing the at least one measurement from the downhole logging tool in the modeled dual gradient cementation system simulated during operation; and (f) estimating a fluid property of a simulated non-static fluid in the dual gradient cementation system modeled in operation, wherein the simulated non-static fluid corresponds to a real non-static fluid in the double real gradient during its operation.
    Embodiments B comprise one or more of the additional elements, in any combination: Element B1: in which the property of the fluid is chosen from the fluid pressure, the position of a fluid, a flow rate, fluid quality, and any combination thereof.
    Element B2: wherein the simulated non-static fluid is selected from a drilling mud, a separating fluid, a cement slurry and any combination thereof.
    Element B3: wherein the property of the fluid is the hydrostatic pressure in the ring and a target of the hydrostatic pressure lying between an interstitial pressure of the subsea wellbore and a fracture gradient of the wellbore under -marine.
    Element B4: Also comprising the manipulation of one or more components of the actual double gradient cementation system or a characteristic of the actual non-static fluid after step (f).
    As a nonlimiting example, examples of combinations applicable to Embodiment B include: B1 and B2; B1 and B3; B3 and B4; B2 and B3; B2 and B4; B3 and B4; B1-B4; Bl, B2, and B3; Bl, B2, and B4; B2, B3, and B4; B1, B3 and B3; etc.
    Embodiment C: System comprising: a real double gradient cementation system in an underwater wellbore, the real double gradient cementation system comprising: a plurality of components comprising a riser coupling a platform of drilling and an underwater wellhead, and a slurry lifting pump (MLP) coupling an underwater rotating device (SRD) to a surface mud return line, a work train extending from the drilling through the underwater wellhead and into an interior of the casing string, and a ring formed between an outside of the casing string and the underwater wellbore, in which the MPL is located at a first underwater depth, and in which the SRD diverts fluids from the ring ring away from the riser; a downhole logging tool located in the real double gradient cementation system at a second underwater depth below the MPL; a control system coupled to the downhole logging tool, the control system comprising a readable non-transient support for storing instructions for execution by a processor to perform a method comprising: (a) modeling of a real double gradient cementation system comprising a plurality of components, the first underwater depth, and the second underwater depth; (b) the simulation of the dual-gradient cementation system modeled in operation, in which a 100% fluid loss value at the first submarine depth of the MPL is assumed, and (c) obtaining at least one measurement from the downhole logging tool; (d) capturing at least one measurement from the downhole logging tool in the simulated dual gradient cementation system modeled during operation; and (e) estimating a fluid property of a simulated non-static fluid in the modeled dual gradient cementation system when in operation, wherein the simulated non-static fluid corresponds to a non-static fluid. -static real in the double real gradient during its operation.
    Embodiments C include one or more of the additional elements, in any combination: [0077] Element C1: wherein the property of the fluid is selected from fluid pressure, fluid position, d a flow rate, fluid quality, and any combination thereof.
    Element C2: wherein the simulated non-static fluid is selected from a drilling mud, a separating fluid, a cement slurry and any combination thereof.
    Element C3: in which the property of the fluid is the hydrostatic pressure in the ring and a target of the hydrostatic pressure lying between an interstitial pressure of the subsea wellbore and a fracture gradient of the wellbore under -marine.
    Element C4: Also comprising the manipulation of one or more components of the actual double gradient cementation system or a characteristic of the actual non-static fluid after step (e).
    As a nonlimiting example, examples of combinations applicable to embodiment C include: C1 and C2; C1 and C3, C3 and C4; C2 and C3; C2 and C4; C3 and C4; C1-C4; C1, C2 and C3; C1, C2 and C4; C2, C3, and C4; Cl, C3 and C3; etc.
    Thus, the disclosed systems and methods are well suited to achieve the stated purposes and advantages, as well as those inherent thereto. The particular embodiments described above are illustrative only, and the teachings of the present disclosure may be modified and practiced in different but equivalent ways that will be apparent to those skilled in the art who benefit from these teachings. In addition, no limitation is provided to the construction or design details disclosed herein, other than those described in the claims below. It is therefore obvious that the particular illustrative embodiments described above may be altered, combined or modified and that all such variations are considered within the scope of this specification. The systems and methods described illustratively herein can be conveniently practiced in the absence of any element not specifically described herein and / or any optional element described herein. Although the compositions and methods are described herein in terms of "comprising", "containing" or "including" various components or steps, the compositions and methods may also "consist essentially of" or "consist of" various components and steps. All figures and intervals disclosed above may vary by a certain amount. When a numerical range with a lower and upper limit is indicated, any number and range within the range are specifically indicated. In particular, each range of values (of the form, "from about a to about b" or, equivalently, "from about a to b", or, equivalently, "from about ab") indicated here should be understood as describing each number and interval within the widest range of values. But also, the terms in the claims have a clear and ordinary meaning, except in case of explicit and clear indication other defined by the applicant. In addition, the undefined articles "a" or "an" as used in the claims are defined herein to mean one or more of the element that it introduces. In the event of a conflict in the use of a word or term in this description and in at least one patent or other document that may be referred to herein, the definitions that are consistent with that description must be adopted.
    权利要求:
    Claims (20)
    [1" id="c-fr-0001]
    CLAIMS What is claimed:
    A method comprising: (a) modeling a dual gradient cementation system in a modeled underwater well bore, wherein the modeled dual gradient cementation system comprises a plurality of components, comprising a coupling riser a drilling platform and an underwater wellhead, a slurry lifting pump (MLP) coupling an underwater rotating device (SRD) to a surface mud return line, a work train extending from the a drilling platform through the underwater wellhead and into the interior of a casing train, and a ring formed between an outside of the casing string and the underwater wellbore, in which the MPL is located at an underwater depth, and in which the SRD diverts the fluids from the ring ring away from the riser; (b) simulation of the dual gradient cementation system modeled in operation, assuming a 100% fluid loss value at the underwater depth of the MPL; (c) estimating a fluid property of a simulated non-static fluid in the simulated dual gradient cementation system in operation; (d) performing a real double gradient cementation operation in a real submarine wellbore, wherein a real non-static fluid corresponding to the simulated non-static fluid demonstrates the property of the fluid.
    [2" id="c-fr-0002]
    The method of claim 1, wherein the property of the fluid is selected from a fluid pressure, a fluid position, a flow rate, a fluid quality, and any combination thereof.
    [3" id="c-fr-0003]
    The method of claim 1, wherein the simulated non-static fluid is selected from a drilling mud, a separating fluid, a cement slurry and any combination thereof.
    [4" id="c-fr-0004]
    The method of claim 1, wherein the property of the fluid is the hydrostatic pressure in the ring and a target of the hydrostatic pressure is between an interstitial pressure of the subsea wellbore and a fracture gradient of the wellbore submarine.
    [5" id="c-fr-0005]
    The method of claim 1, further comprising manipulating one or more components of the simulated simulated dual gradient cementation system or a simulated non-static fluid characteristic prior to step (d).
    [6" id="c-fr-0006]
    The method of claim 1, further comprising manipulating a pump flow of the MPL prior to step (d).
    [7" id="c-fr-0007]
    The method of claim 1, further comprising manipulating a pump pressure of the MPL prior to step (d).
    [8" id="c-fr-0008]
    The method of claim 1, further comprising manipulating a simulated non-static fluid flow prior to step (d).
    [9" id="c-fr-0009]
    The method of claim 1, further comprising manipulating a simulated non-static fluid pressure prior to step (d).
    [10" id="c-fr-0010]
    The method of claim 1, further comprising manipulating a simulated non-static fluid density prior to step (d).
    [11" id="c-fr-0011]
    The method of claim 1, further comprising manipulating a simulated non-static fluid viscosity prior to step (d).
    [12" id="c-fr-0012]
    The method of claim 1, further comprising manipulating at least one of the density and / or viscosity of the simulated non-static fluid prior to step (d), and wherein the handling comprises foaming simulated simulated non-static fluid.
    [13" id="c-fr-0013]
    A method comprising: (a) introducing a downhole logging tool into a real double gradient cementation system while operating in an underwater wellbore, wherein the subsurface wellbore system; real double gradient, comprises a plurality of components, comprising a riser coupling a drilling platform and an underwater wellhead, a slurry lifting pump (MLP) coupling an underwater rotating device (SRD) to a line return of mud on the surface, a work train extending from the drilling platform through the underwater wellhead and into the interior of a casing train, and a ring formed between an outside of the casing train and the underwater wellbore, in which the MPL is at a first submarine depth, and wherein the SRD diverts the fluids from the annulus of the ring away from the riser; and wherein the downhole logging tool is located at a second underwater depth below the MPL; (b) modeling the real double gradient cementation system, comprising the plurality of components, the first underwater depth and the second underwater depth; (c) simulating the modeled dual gradient cementation system in operation, assuming a 100% fluid loss value at the first underwater depth of the MPL; and (d) obtaining at least one measurement from the downhole logging tool; (e) capturing at least one measurement from the downhole logging tool in the modeled dual gradient cementation system simulated in operation; and (f) estimating a fluid property of a simulated non-static fluid in the simulated dual gradient cementation system in operation, wherein the simulated non-static fluid corresponds to a real non-static fluid in the double real gradient during its operation.
    [14" id="c-fr-0014]
    The method of claim 13, wherein the property of the fluid is selected from hydrostatic pressure, fluid position, fluid flow rate, fluid quality, and any combination thereof.
    [15" id="c-fr-0015]
    The method of claim 13, wherein the simulated and real non-static fluid is selected from a drilling mud, a separating fluid, a cement slurry and any combination thereof.
    [16" id="c-fr-0016]
    The method of claim 13, wherein the property of the fluid is the hydrostatic pressure in the ring and a target of the hydrostatic pressure is between an interstitial pressure of the subsea wellbore and a fracture gradient of the wellbore submarine.
    [17" id="c-fr-0017]
    The method of claim 13, further comprising manipulating one or more components of the actual double gradient cementation system or a characteristic of the actual non-static fluid after step (f).
    [18" id="c-fr-0018]
    A system comprising: a real double gradient cementation system in an underwater wellbore, the real double gradient cementation system comprising: a plurality of components including a riser coupling a rig and a wellhead underwater, a slurry lifting pump (MLP) coupling an underwater rotating device (SRD) to a surface mud return line, a work train extending from the drilling rig across the underwater well head and into a casing string, and a ring formed between an outside of the casing string and the underwater well bore, in which the MPL is at a first submarine depth, and wherein the SRD diverts fluids from the ring ring away from the riser; a downhole logging tool located in the real double gradient cementation system located at a second underwater depth below the MPL; a control system coupled to the downhole logging tool, the control system comprising a readable non-transient support for storing instructions for execution by a processor for performing a method comprising: (a) modeling the real double gradient cementation system, comprising the plurality of components, the first underwater depth and the second underwater depth; (b) simulating the dual-gradient modeled cementation system in operation, in which a 100% fluid loss value is assumed at the first submarine depth of the MPL; and (c) obtaining at least one measurement from the tool. well log logging; (d) capturing at least one measurement from the downhole logging tool in the modeled double gradient cementation system simulated in operation; and (e) estimating a fluid property of a simulated non-static fluid in the simulated dual gradient cementation system during operation, wherein the simulated non-static fluid corresponds to a non-static fluid real in the current double gradient during its operation.
    [19" id="c-fr-0019]
    The system of claim 18, wherein the property of the fluid is selected from a fluid pressure, a fluid position, a fluid flow rate, a fluid quality, and any combination thereof.
    [20" id="c-fr-0020]
    The method of claim 18, wherein the property of the fluid is the hydrostatic pressure in the ring and the hydrostatic pressure is between an interstitial pressure of the subsea wellbore and a fracture gradient of the subsurface wellbore. marine.
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    同族专利:
    公开号 | 公开日
    CA2992882C|2020-01-07|
    GB201801123D0|2018-03-07|
    GB2556551B|2021-07-07|
    NO20180088A1|2018-01-19|
    CA2992882A1|2017-03-09|
    WO2017039649A1|2017-03-09|
    US10990717B2|2021-04-27|
    AU2015408209A1|2018-02-01|
    MX2018001405A|2018-04-13|
    GB2556551A|2018-05-30|
    US20180196898A1|2018-07-12|
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    法律状态:
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    2021-05-07| ST| Notification of lapse|Effective date: 20210405 |
    优先权:
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    PCT/US2015/048069|WO2017039649A1|2015-09-02|2015-09-02|Software simulation method for estimating fluid positions and pressures in the wellbore for a dual gradient cementing system|
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