Patent Application
20240068356
Embodiments of the technology relate generally to tracking fatigue damage in subsea wellhead systems.
Offshore production of hydrocarbons requires drilling and completing wells in addition to interventions for ultimately abandoning the wells at the end of the well life cycle, which is often over 30 years. The offshore wells are sometimes located in challenging deepwater environments, requiring highly specialized subsea equipment for ensuring the well construction operation and production is carried out safely. The foundation of a subsea well is the wellhead system, which is installed during the first phase of drilling operations to provide pressure containment and structural support for the extreme loads derivate from installing temporary drilling and intervention equipment (i.e., subsea blow-out preventer stack) and permanent equipment (i.e., casing, tubing head spools, production trees). The subsea wellhead system typically includes the low-pressure housing installed with the jetted conductor casing and the high-pressure housing installed with the surface casing, locked into the low-pressure housing, typically located at 10-15 feet above the sea floor. Next, a riser extending from the floating platform is connected to the wellhead system and the remainder of the well is drilled with casing strings landed either directly on the high-pressure housing or on sub-mudline hangers. The wellhead system will support the weight of the heavy subsea blow-out preventers installed directly on the high-pressure housing for drilling operations or either the tubing head spool or production tree for completions and intervention operations. For a typical deepwater subsea well, the blow-out preventer stack may be as heavy as 700 tons with heights over 50 feet, depending on the configuration. On top of the blow-out preventers stack, long subsea riser equipment extending upward from the wellhead system is installed as conduit for the fluids used for the operation in the well. The length of the subsea riser varies depending on the water depth, with lengths exceeding 5,000 feet above the blow-out preventer stack for deepwater wells. The subsea riser is subjected to forces from ocean currents, waves, and loading from surface vessels. The variation of the forces on the riser equipment causes stress cycles on the wellhead system, leading to fatigue damage on the wellhead system. Other sources of stress cycles on the wellhead system can include vibration of the equipment connected to the subsea wellhead system such as flowlines used during production. Furthermore, pressure and temperature cycles on the wellhead system can cause stress cycles and subsequent fatigue damage on the wellhead system. Wellhead system fatigue damage can accumulate and negatively impact the remaining useful life of the wellhead system and the well. Therefore, techniques for monitoring wellhead system fatigue would benefit the operation of subsea wells.
The present disclosure is generally directed to monitoring fatigue damage to a subsea wellhead system. In one example embodiment, a computing system comprises a processor, a memory, and a storage device comprising a fatigue tracking service comprising computer-executable instructions that perform a method. The method of the fatigue tracking service comprises determining, using historical environmental data, a fatigue damage rate for a wellhead system, the fatigue damage rate comprising a drilling fatigue damage rate for a drilling operation and a completion fatigue damage rate for a completion operation. The method further comprises receiving a total maximum allowable fatigue damage for the wellhead system during its entire life cycle and assigning a number of drilling days for the drilling operation and a number of completion days for the completion operation, and number of days for other operations if applicable. The method includes determining a drilling fatigue allowance and a completion fatigue allowance based upon the drilling fatigue damage rate, the completion fatigue damage rate, the total maximum allowable fatigue damage, the number of drilling days, and the number of completion days. Lastly, the method includes determining an accumulated amount of fatigue damage for the wellhead system during actual offshore operations such as drilling, completion and intervention; and providing a comparison of the accumulated fatigue damage to the determined fatigue allowance for specific operations such as drilling, completion and intervention.
Another example embodiment is a computer-implemented method for monitoring fatigue damage to a wellhead. The method comprises determining, by a fatigue tracking service using historical environmental data, a fatigue damage rate for a wellhead system, the fatigue damage rate comprising a drilling fatigue damage rate for a drilling operation and a completion fatigue damage rate for a completion operation. The method further comprises receiving a total maximum allowable fatigue damage for the wellhead system and assigning a number of drilling days for the drilling operation and a number of completion days for the completion operation. The method includes determining a drilling fatigue allowance and a completion fatigue allowance based upon the drilling fatigue damage rate, the completion fatigue damage rate, the total maximum allowable fatigue damage, the number of drilling days, and the number of completion days. Lastly, the method includes determining an accumulated fatigue damage for the wellhead system based upon at least one of drilling fatigue damage measurements for the wellhead system and completion fatigue damage measurements for the wellhead system; and providing a comparison of the accumulated fatigue damage to at least one of the drilling fatigue allowance and the completion fatigue allowance.
In yet another example embodiment, a non-transitory computer-readable medium comprises computer-executable instructions that when executed by a hardware processor perform a method. The method comprises determining, by a fatigue tracking service using historical environmental data, a fatigue damage rate for a wellhead system, the fatigue damage rate comprising a drilling fatigue damage rate for a drilling operation and a completion fatigue damage rate for a completion operation. The method further comprises receiving a total maximum allowable fatigue damage for the wellhead system and assigning a number of drilling days for the drilling operation and a number of completion days for the completion operation. The method includes determining a drilling fatigue allowance and a completion fatigue allowance based upon the drilling fatigue damage rate, the completion fatigue damage rate, the total maximum allowable fatigue damage, the number of drilling days, and the number of completion days. Lastly, the method includes determining an accumulated fatigue damage for the wellhead system based upon at least one of drilling fatigue damage measurements for the wellhead system and completion fatigue damage measurements for the wellhead system; and providing a comparison of the accumulated fatigue damage to at least one of the drilling fatigue allowance and the completion fatigue allowance.
The foregoing embodiments are non-limiting examples and other aspects and embodiments will be described herein. The foregoing summary is provided to introduce various concepts in a simplified form that are further described below in the detailed description. This summary is not intended to identify required or essential features of the claimed subject matter nor is the summary intended to limit the scope of the claimed subject matter.
The accompanying drawings illustrate only example embodiments of a system, method, and computer-readable media for monitoring fatigue damage to subsea wellhead systems. Therefore, the examples provided are not to be considered limiting of the scope of this disclosure. The principles illustrated in the example embodiments of the drawings can be applied to alternate methods and apparatus. Additionally, the elements and features shown in the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of the example embodiments. Certain dimensions or positions may be exaggerated to help visually convey such principles. In the drawings, the same reference numerals used in different embodiments designate like or corresponding, but not necessarily identical, elements.
The example embodiments discussed herein are directed to systems, methods, and computer-readable media for monitoring fatigue damage on subsea wellhead systems. Existing approaches to managing wellhead fatigue damage rely on estimates of the amount of fatigue damage that may occur at the wellhead. However, because the estimates are highly variable and uncertain, with uncertainty exceeding one order of magnitude in some cases, overly conservative assumptions must be used in fatigue analysis. The overly conservative assumptions lead to conservative estimates of the amount of fatigue damage on the wellhead system. The amount of fatigue damage on the wellhead system can affect planning for the rig at the surface, planning with respect to various operations performed on the well, and planning with respect to the operational life of the well. Using overly conservative estimates of the amount of fatigue damage in managing the well operations can result in unnecessary downtime, such as waiting for a weather system to pass before performing an operation on the well, and the performance of unnecessary operations, such as disconnecting the riser or BOP from the well, and such operations can result in unnecessary added complications and risks. Overly conservative estimates of the amount of fatigue damage on a wellhead system also can unnecessarily shorten the operational life of the well. Given the complexity of drilling and operating a subsea well, unnecessary downtime and unnecessary limiting of the life of the well can add operational risk, loss of recoverable reserves and result in substantial expense. Accordingly, more accurate techniques for monitoring wellhead fatigue damage allows for better planning decisions regarding the well, including improved operational safety and more flexibility and efficiency in the operation of the well.
The techniques described in the following example embodiments employ a more detailed analysis of fatigue damage by analyzing the drilling operations, the completion operations, and intervention operations. Furthermore, the techniques described herein can use a more granular approach because they also can analyze the phases within the foregoing operations. Another advantage of the techniques described herein is that they can modify fatigue damage allowances as measured fatigue damage data becomes available thereby providing flexibility in the operation of the well.
While the example embodiments for performing wellhead system monitoring are provided in the descriptions that follow, modifications to the embodiments described herein are within the scope of this disclosure. In the following paragraphs, particular embodiments will be described in further detail by way of example with reference to the drawings. In the description, well-known components, methods, and/or processing techniques are omitted or briefly described. Furthermore, reference to various feature(s) of the embodiments is not to suggest that all embodiments must include the referenced feature(s).
Referring now to
As illustrated in
As illustrated in
Referring now to
As is commonly known for computing systems, computing system 105 includes one or more processors 110, memory 115, and input/output interfaces 120. The storage device 125 can be an integrated component of the computing system 105, as illustrated in
The computing components illustrated in
Beginning with operation 305, the FTS 130 uses hindcast model data, or environmental data, to determine one or more fatigue damage rates. The hindcast model data describes typical conditions in the area of the well and can include one or more of ocean current data including current speed and current direction, wind data including wind speed and wind direction and wave data including wave speed and wave direction. The FTS 130 uses the hindcast model data to model the conditions that are likely to be encountered during the life of the well. The hindcast model data are used to estimate the forces to which the well system will be subjected and the resulting stress on the wellhead system. Tools known in the industry for use in estimating fatigue damage rates, such as finite element analysis methods can be used in determining fatigue damage rates for the wellhead system based on hindcast model data The FTS 130 can calculate fatigue damage rates for one or more particular operations associated with the well, including drilling of the well, completion of the well, intervention operations associated with the well, and other operations, if applicable, during the entire life cycle of the well. As will be described further below in connection with
In operation 310, the FTS 130 receives a total maximum allowable fatigue damage that the wellhead system can sustain during its or the well's entire life cycle. For example, the wellhead system will have an estimated failure point at which the amount of accumulated fatigue damage at one or more locations on the components of the wellhead system causes the wellhead system to begin to fail. Using the failure point as a reference, the operator of the well can determine what percentage of accumulated wellhead fatigue damage is within acceptable risk parameters. For example, the operator may determine that limiting accumulated fatigue damage to 70% of the failure point for the wellhead system provides a sufficient buffer for operating the well. The 70% value will be treated as the total maximum amount of fatigue damage allowance that the wellhead system can sustain and still be operated within acceptable risk parameters. The operator can provide the total maximum allowable fatigue damage to the FTS 130 or the FTS 130 can calculate the value based upon the operator's parameters.
In operation 315, once the one or more operations commence on the well system, the FTS 130 can receive measurement data providing an indication of a fatigue damage rate, and subsequently the amount of fatigue damage, to the wellhead system. As described previously in connection with
In operation 320, the FTS 130 can compare the allowable fatigue damage from operation 310 to the accumulated fatigue damage from operation 315. The FTS 130 can generate a report, such as a data plot or a table, illustrating the comparison of allowable fatigue damage to accumulated fatigue damage to determine whether the accumulated fatigue damage from operations being performed on the well system is approaching the allowable fatigue damage. The report can be useful to operators of the wellhead system to ensure that the operations do not result in exceeding the allowable fatigue damage. Additionally, the report can be used to adjust planning and operations relating to the well system. For example, if a metocean condition or a weather system is approaching that may result in increases to the accumulated fatigue damage during an operation, the operator may choose to delay the operation or disconnect equipment from the well if the accumulated fatigue damage is approaching the allowable fatigue damage. Alternatively, if the comparison indicates the accumulated fatigue damage is well below the allowable fatigue damage, this buffer can provide the operator with greater flexibility in planning operations on the well.
Referring now to
Beginning with operation 405 of
In operation 410, the FTS 130 receives a total maximum allowable fatigue damage value for the wellhead system during it entire life cycle. Similar to operation 310, the total maximum allowable fatigue damage can be a percentage of the estimated failure point for one or more locations on the components of the wellhead system and can be set by an operator of the well or can be calculated by the FTS 130. In the example data of
In operations 415 and 420, the FTS 130 assigns a number of drilling days, or operating days of drilling, for the drilling operation as well as a number of completion days, or operating days of completion work, for the completion operation. The number of drilling days and number of completion days can be based on historical data for similar wells and/or the work plan for the particular well that is to be drilled and completed. The example data in
The number of drilling days and the number of completion days are projected estimates. In the example data of
In operation 425, the FTS 130 determines a drilling fatigue allowance and a completion fatigue allowance based upon the drilling fatigue damage rate, the completion fatigue damage rate, the total maximum allowable fatigue damage, the number of drilling days, and the number of completion days. In the example of
As indicated in the example data of
The FTS 130 can determine drilling fatigue allowance and completion fatigue allowance for a variety of scenarios. For example, depending on the various engineering challenges that may be encountered during the drilling operation or the completion operation, different well system equipment may be employed that may result in different stresses on the wellhead system. Similarly, the phases of the drilling operation may vary resulting in an actual number of operating days that differs from the estimated projections. The FTS 130 can store these various scenarios in the fatigue tracking database 140 for adjusting fatigue allowance and well construction planning during the drilling and completion operations.
In operation 430, the FTS 130 receives drilling fatigue damage measurements from the sensors, such as accelerometers and/or strain gauges and/or an inclinometer, on the well system equipment and determines an accumulated fatigue damage for the wellhead system.
Similar to operation 430 but for the subsequent completion operation, operation 435 indicates that the FTS 130 can determine an accumulated fatigue damage based upon completion fatigue damage measurements from sensors on the well system equipment. As described in operation 430, the FTS 130 can compare the completion fatigue damage measurements to the projected completion data for completion days and completion fatigue allowance to determine whether the completion operation is proceeding within the projected estimates. If the work has not yet reached the completion operation, the FTS 130 would skip operation 435 and proceed to operation 440. As another optional step, the FTS can determine the accumulated fatigue damage from measurements of other operations, such as intervention operations.
In operation 440, the FTS 130 can provide one or more reports illustrating the comparison between the fatigue damage measurements, such as those illustrated in
In operation 445, the FTS 130 can use the comparison illustrated in
General Information Regarding Computing Systems
As described in connection with
The computing systems used in the foregoing embodiments can include typical components such as one or more processors, memories, input/output devices, and a storage devices. The components of the computing systems can be interconnected, for example, by a system bus or by communication links. The components of the previously described computing systems are not exhaustive.
The one or more processors can be one or more hardware processors and can execute computer-readable instructions, such as instructions stored in a memory. The processor can be an integrated circuit, a central processing unit, a multi-core processing chip, an SoC, a multi-chip module including multiple multi-core processing chips, or other hardware processor in one or more example embodiments. The hardware processor is known by other names, including but not limited to a computer processor, a microprocessor, and a multi-core processor.
The memory can store information including computer-readable instructions and data. The memory can be cache memory, a main memory, and/or any other suitable type of memory. The memory is a non-transitory computer-readable medium. In some cases, the memory can be a volatile memory device, while in other cases the memory can be a non-volatile memory device.
The storage device can be a non-transitory computer-readable medium that provides large capacity storage for a computing system. The storage device can be a disk drive, a flash drive, a solid state device, or some other type of storage device. In some cases, the storage device can be a database that is remote from the computing system. The storage device can store operating system data, file data, database data, algorithms, and software modules, as examples.
Assumptions and Definitions
For any figure shown and described herein, one or more of the components may be omitted, added, repeated, and/or substituted. Accordingly, embodiments shown in a particular figure should not be considered limited to the specific arrangements of components shown in such figure. Further, if a component of a figure is described but not expressly shown or labeled in that figure, the label used for a corresponding component in another figure can be inferred to that component. Conversely, if a component in a figure is labeled but not described the description for such component can be substantially the same as the description for the corresponding component in another figure.
With respect to the example methods described herein, in alternate embodiments, certain steps of the methods may be performed in a different order, may be performed in parallel, or may be omitted. Moreover, in alternate embodiments additional steps may be added to the example methods described herein. Accordingly, the example methods provided herein should be viewed as illustrative and not limiting of the disclosure.
Terms such as “first” and “second” are used merely to distinguish one element (or state of an element) from another. Such terms are not meant to denote a preference and are not meant to limit the embodiments described herein. In the example embodiments described herein, numerous specific details are set forth in order to provide a more thorough understanding of the invention. However, it will be apparent to one of ordinary skill in the art that the invention may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.
The terms “a,” “an,” and “the” are intended to include plural alternatives, e.g., at least one. The terms “including”, “with”, and “having”, as used herein, are defined as comprising (i.e., open language), unless specified otherwise.
Values, ranges, or features may be expressed herein as “about”, from “about” one particular value, and/or to “about” another particular value. When such values, or ranges are expressed, other embodiments disclosed include the specific value recited, from the one particular value, and/or to the other particular value. Similarly, when values are expressed as approximations, by use of the antecedent “about,” it will be understood that the particular value forms another embodiment. It will be further understood that there are a number of values disclosed therein, and that each value is also herein disclosed as “about” that particular value in addition to the value itself. In another aspect, use of the term “about” means±20% of the stated value, ±15% of the stated value, ±10% of the stated value, ±5% of the stated value, ±3% of the stated value, or ±1% of the stated value.
Although embodiments described herein are made with reference to example embodiments, it should be appreciated by those skilled in the art that various modifications are well within the scope of this disclosure. Those skilled in the art will appreciate that the example embodiments described herein are not limited to any specifically discussed application and that the embodiments described herein are illustrative and not restrictive. From the description of the example embodiments, equivalents of the elements shown therein will suggest themselves to those skilled in the art, and ways of constructing other embodiments using the present disclosure will suggest themselves to practitioners of the art. Therefore, the scope of the example embodiments is not limited herein.
