In recent years, monitoring of the subsea BOP in order to keep track of movements, loads, and fatigue accumulation on subsea wellheads has been performed. On the Norwegian Continental Shelf, more than 50% of the semisubmersible drilling rigs have equipment for measuring the motion and load on the subsea BOP. A typical setup is to have motion sensors installed and calculate the loads on the lower part of the BOP and the subsea structure from indirect methods where knowledge of system parameters such as tension, weights and drag coefficients is used to establish the loads. Direct measurement of the load using strain gauges or LVDT's has proven challenging due to time consuming installation, fragile measurement equipment, and difficulties finding suitable areas to mount the sensors. The objective of this paper is to present a novel sensor technology that allows for accurate measurement of strains in a wide measuring range. In contrast to existing measuring equipment this new sensor technology enables a compact, robust, and easy to install strain sensor. The new sensor is small enough to be mounted behind the bolts/ nuts on an 18 ¾″ BOP flange neck. The sensors can be used to increase the accuracy and reduce unnecessary conservatism in the measured wellhead loads. This can again reduce the need for expensive load reducing measures or disconnects. This paper will present the core principles of the new strain sensor. Laboratory tests showing the performance and accuracy of the sensor will be shown, and the benefits of this sensor versus existing technologies will be demonstrated. The introduction of this new sensor enables direct measurement of the loading on the subsea wellhead system. The new measuring process will be presented and compared with the traditional indirect measurement process. This comparison will illustrate where in the measuring process increased accuracy and reduced conservatism can be achieved, and then quantifying the improvements. Further, the paper will present results from use of the sensor in actual measurement campaigns from drilling operations in harsh environment on the Norwegian Continental Shelf. The paper will present the findings from the first measuring campaigns using this new sensor technology. The measured results will be compared with the traditional indirect measurement method and the improvement, in terms of reduced conservatism and increased accuracy, will be shown. Then finally, the consequence in terms of reduction on measured extreme and fatigue load, will be presented. This paper will show how new sensor technology can be used to obtain more accurate and less conservative measurements of the loading on a subsea wellhead system in order to reduce the need for expensive load reducing measures.

The Intervention and well P&A are considered high-risk and complex operations that must be carried out in a fully managed and controlled environment. This can be achieved through enhancing the existing intervention systems or introducing new solutions. The intervention riser system and the riser-less open-water abandonment module introduce new technologies that will expand today's operating envelope to deeper and higher temperature environments while maintaining costs and risks firmly under control. Improved synergies can also be achieved through new alliances when different types of operating assets are lumped together, delivering seamless service through integration.

The objective of the campaign was to safely and efficiently complete a plug-and-abandonment (P&A) operation in a harsh Norwegian North Sea well using a high-performance conductor-recovery tool. The operation used the newly reinvented, second generation mechanical, outside-latch, single trip (MOST) tool system. Along with recovering the subsea wellhead, the associated casing strings and conductor were to be cut and retrieved. The standard MOST tool is a field-proven system, which latches externally to the wellhead, then cuts and recovers subsea wellheads. The newly released second generation system is a reinvented P&A tool that includes several innovative technologies to increase tool capabilities and performance. The latest release of the MOST tool includes a newly designed tension-cut mandrel, nonrotating flexible stabilizer (NRFS), large-diameter cutter, and high-angle knives. The system confirms the cut without the need for tripping, easily latches and releases to inspect the cutting knives, and does not cause damage to the internal wellhead sealing profile. Furthermore, the external-latch mechanism helps to prevent swarf buildup by allowing more flow area in the high-pressure wellhead, which permits the cuttings to easily exit. The latch and unlatch function can also be visually confirmed using a remotely operated vehicle (ROV) on the seafloor. External latching provides superior lateral support for the wellhead assembly to eliminate any lateral whipping that might impede cutting. The second-generation design of the MOST tool, with the tension-cut mandrel, provides pulling capabilities up to 1,000,000 lb (453,592 kg) and fail-safe features, which enable the outside latch to be released by the ROV, if needed. The newly deployed system successfully recovered multiple subsea wellheads in Norway and demonstrated its operational effectiveness with reduced cutting times compared to traditional cut-and-pull operations. With advanced features, the subsea wellhead-retrieval system reduces rig time by cutting and retrieving multiple cemented or uncemented strings in a single trip. The NRFS and large-diameter cutter increase stabilization and minimize vibration during cutting, and the high-angle knives increase cutting efficiency when compared to traditional retrieval systems. The MOST system supports quick wellhead recovery, minimizes operational expenditure, and reduces rig time. The new developments to the next generation MOST tool system give the customer several additional application choices. The various interchangeable components allow for a wide range of cutting options including abrasive cutting, tension cut, motor cut, and umbilical support for laser cutting.

The oil and gas industry continues to face low energy prices, which has pushed manufacturers to re-think conventional designs and methods that may not be at the efficiency levels required to operate under today’s environmental and economic conditions. This paper describes the development of a new and advanced subsea tree technology that reduces equipment cost and installation time, thereby reducing risk and adding significant value to the end user. Traditional completion systems have become increasingly complex as efforts were made to address individual problems as they arose. These challenges included wellhead interfaces capable of handling the stack-up tolerances of casing hangers, and a need to orient the tubing hanger relative to a flowline connection system. The solution utilized by most conventional systems was the incorporation of a tubing head spool or some other elaborate means of orienting within the BOP, which created the need for temporary well barriers, required costly workover riser systems and wireline trips, and ultimately led to concentric bore systems with annulus valves located on a tubing head spool. The VXTe subsea tree system solves the problems associated with wellhead stack-up tolerances and orientation of the tubing hanger, in a simple, robust and elegant manner. The simplicity of the system allows the tubing hanger to be installed like a casing hanger. In this way, the drilling and completion operations may be undertaken without the cost and safety concerns normally associated with temporary well suspensions or BOP trips, and the orientation requirements for flowline connections are completely decoupled from the tubing hanger installation. The requirement for well barriers is also eliminated, thereby trimming the costs of additional spools, and further eliminating leak paths and failure modes. By eliminating the cumbersome solutions employed by conventional systems, our system also eliminates the need for the extensive SIT testing required to validate working interfaces. The VXTe system is a simple, robust and elegant answer to the industry's most pressing subsea tree challenges and aligns with the IOGP requirements agreed upon by most of the major operators. The VXTe system has undergone a number of verification analysis and validation testing adhering to API standards. In addition to meeting applicable API testing requirements, additional cycle testing was performed to validate the performance of the system over the anticipated life cycle. This included installation and removal cycle testing in addition to pressure and temperature testing. The design details, analysis, and test results will be presented.

Downhole conditions of oil and gas reservoirs change with time. Monitoring this change is critical to enhance hydrocarbon recovery from the reservoir. Conventionally, downhole measurements of physical and chemical properties of downhole formation fluids are taken using wireline logging or using permanent downhole sensors. Wireline logging is a complex operation that requires several miles of wireline cable, a winch, a crane and a specialized crew that knows how to operate this equipment [ 1 ]. In addition, a blowout preventer, a lubricator and a specialized crew to install and operate are needed. The complexity and cost of wireline operations makes it difficult to acquire reservoir data frequently. The other alternative for gathering downhole data more frequently is installing permanent sensors or optical fibers in the well [ 2 - 3 ]. However, due to the harsh downhole conditions, these sensors need to be extremely reliable and continuously maintained. Moreover, surface data acquisition systems for these sensors increase their cost significantly and reduces their applicability to every well. Both methods have their own limitations and there is a need for more practical and less expensive oil field instruments for well logging. Engineering small, inexpensive and robust logging instruments has its own challenges. Solving these challenges has been the main focus area of Sensors Development Team at Aramco Research Center in Houston. This paper describes one of the concept ideas that was successfully engineered and tested in our facility and successfully deployed and retrieved in the field in Saudi Arabia in collaboration with our EXPEC ARC and Northern Area Production Engineering and Well Services Divisions in Saudi Arabia.

The Aasta Hansteen Subsea Production System is a part of a new major deep water gas development located in the Norwegian Sea, north of the Arctic Circle and 300 km from shore, west of the city of Bodø in Norway. With a water depth of 1300m, this development is a new water depth record in Norwegian waters and it is characterized by its remote location and harsh environment. The objective of this paper is to present the concept selections, technology development, design and fabrication for the subsea production system including umbilical and workover system. The paper demonstrates the importance of solid preparation in early phase planning, continuous implementation of lessons learned and an extensive test program in order to verify the new technical solutions for the Aasta Hansteen subsea deepwater development. This included development of a new mono-pile "toast rack" template designed for guideline less installation of manifolds and X-mas tree systems. This paper also presents a new deep water Workover system, involving an extensive qualification program and several new technical features such as a new safety joint, heave compensator and automated make-up of riser joints and more, in order to improve operational efficiency and increase safety under given challenging conditions. The paper also addresses a full scale wellhead testing in order to verify the design for fatigue performance. Several novel technologies were qualified and implemented as part of the Aasta Hansteen Subsea Production System to adapt to deep water operations, to enhance HSE performance and improve efficiency of the system. The experience is that the new technologies and new system solutions have improved HSE performance, operational performance and installation friendliness.

It is instructive to think about the current state of subsea well system design in its historical context. That is especially true if you look first at the earliest years, then at the years following the 1969 Santa Barbara blowout and spill, and then at the years following the Macondo blowout and spill. These last two periods illustrate both important similarities and important differences in equipment design, standardization, and regulation. This paper examines the advances in design, standardization, and regulation of subsea well control and well containment equipment. This progress has continued the conservative, step-wise advances that have characterized the history of the subsea drilling and well control industry. This paper uses as an example the recent project developing a new 20,000 psi/350F capping stack.

We have simulated onshore and offshore blowouts of an idealized CO 2 injection well using T2Well, a state-of-the-art coupled well-reservoir simulator. The purpose of the study is to understand dynamic multi-phase non-isothermal flow phenomena in CO 2 wells to inform risk assessment studies for offshore geologic carbon sequestration sites. The scenario we chose consists of a vertical well of 3050 m length completed in a mature geologic carbon sequestration reservoir filled with CO 2 connected to a horizontal surface pipe. At time zero, we assume the surface pipe was breached producing a 2-inch diameter hole. In the onshore scenario, the pipe blowout causes CO 2 to enter the ambient air at 0.101325 MPa and 22.78 °C, whereas in the offshore scenario the blowout is into the water column at a depth of 50 m where pressure and temperature are 0.598 MPa and 22.78 °C, respectively. The simulations show that the overall CO 2 leakage rates are very similar for the onshore and offshore scenarios, with subtle differences in flow rates of various phases likely arising from differences in pressure at the leakage point. Overall, the main differences between onshore and offshore CO 2 blowouts are expected to arise mostly after discharge due to differences between how CO 2 disperses in ambient air versus in the water column.

Floating vessels with dry tree production equipment are large capital expenditure projects with multiple interfaces often spanning several entities, including the Operator, Engineering Procurement and Integration Contractor (EPIC), Rig Builder, Production and Drilling Top-Tensioned Riser (TTR) supplier, Subsea Wellhead supplier, and Surface Wellhead/Tree supplier. Design and Interface Management play a significant role in the success of a project of this magnitude. The Shell Malikai Single Combo Casing Top Tensioned Riser (SCCTTR) was successfully deployed and commissioned on the first TLP in Malaysia. The Malikai SCCTTR is an industry first and an example of innovative design configuration coupled with rigorous project execution to deliver a system that is an enabling technology for current industry market conditions. The SCCTTR is a single riser used first for drilling and then remains in place for the full field life. This provides significant cost savings, both in hardware and operational time for large field developments, but introduces technical challenges to meet the requirements of both traditional drilling and production/water injection risers. This paper presents key design challenges to meet the requirements for ‘multi-purpose’ configuration and identifies how they were addressed to accomplish the project goal of flawless delivery. Project management was a key factor in achieving this goal. Shell chose a one-stop solution for delivery of the subsea wellhead and SCCTTR which provided advantages in management of interfaces and overall delivery. While this minimized interfaces, it still required a significant effort to coordinate components from multiple continents to deliver a single system. In addition to project management, the system required innovative design, as illustrated by the tensioner system, which introduced new features such as deflection absorbing bearing pads to limit the impact of the SCCTTR on the TLP hull design. Even with the additional features, the new tensioner system was designed, manufactured, and qualified within the project schedule. The Malikai SCCTTR stands as a testament to what can be accomplished when innovative design approach is coupled with robust project management and collaborative efforts between operator and equipment suppliers.

During operation, the structural casings of a well experience two types of cyclic loads due to the heating-up and cooling-down of the well, which are: i) cyclic thermal induced forces on the structural casings themselves; and ii) cyclic thermal forces at the top of the structural casings generated due to the expansion and contraction of the inner casings and tubing (against the restraint from the structural casings). Combined with the nonlinear, hysteretic and degradable behavior of the surrounding soil, the interaction between the structural casings and surrounding soil have a significant effect on the overall performance of a well. This paper presents recent advances in the numerical modeling techniques of the well system, focusing on the axial interaction between the structural casings and surrounding soil under cyclic thermal loading. The complex structural casing – soil interaction under cyclic loading has been successfully modelled by using advanced cyclic t-z springs. The springs are integrated into a structural model representing the multi-string well system and the associated cement. In the model, the soil specific behavior of the t-z spring is accounted for by calibrating the t-z model against laboratory model tests on the particular soils encountered along the structural casings. The developed modeling approach can capture the variation (e.g. degradation) of the casing-soil interface strength under cyclic loading; thus allowing accurate prediction of well head movement, post-cyclic axial capacity of the structural casings, and oscillation and distribution of axial force along the structural casings during cyclic thermal loading. The predicted wellhead movement with thermal cycles is found to be consistent to the field observation. The insights gained from the modeling exercise enhance our understanding of the casing-soil interaction mechanism and could greatly benefit optimization of well design. The developed modeling technique is also equally applicable to conventional and energy pile designs in degradable material, and capable of accounting for the coupling effect between the axial and torsional loads.

Operators are looking to drill and develop deep-water wells with pressures over 15,000 psi and temperatures exceeding 300°F. Designing for high pressure, high temperature (HPHT) conditions present a number of engineering challenges, which can push conventional subsea technology designs to their limits. Therefore, there is a need to understand the feasibility of riser systems in these conditions and consequently to close any potential gaps between the current qualified technology and the outlined project specifications for a number of key riser components. For conventional reservoirs, the merits of using wet tree and dry tree systems are well understood after years of design, fabrication, installation and operating experience. For HPHT riser applications, various design challenges exist with respect to the technology readiness of various riser system components of a wet or dry tree system development. Key riser design issues and technology challenges, applicable to wet and dry tree HPHT systems, are addressed in this paper. For a wet tree development, HPHT conditions require the use of thick wall pipes driven by burst sizing requirements, which in turn will lead to challenges associated with fabrication of pipes, pipe welding and inspection as well as meeting applicable sour service requirements. Furthermore, design of riser hang-off systems of wet tree applications is a critical area that requires consideration. The use of High-Integrity Pressure Protection Systems (HIPPS) to overcome HPHT obstacles is also discussed in this paper. The use of high strength steel pipe with threaded mechanical connections provides a weight benefit for a dry tree system. However, the qualification of connectors is required and is expected to be a critical activity. In addition, the dry tree system has many other sealing surfaces and connections subject to HPHT loads at the surface and subsea wellhead locations, each of which presents their own design and qualification challenges.

In the current market, operators are exploring the potential opportunities to optimize the production of existing assets. The goal was to tie a respudded well into existing field architecture, with minimum equipment, time, and cost. The operator respudded a cluster manifold well approximately 50 meters from the tie-in manifold. At roughly twice the distance of the existing well jumper, this approach posed a challenge for a traditional vertical in-plane jumper. A study was completed to compare a few traditional approaches. The options considered were a 50-meter-long jumper able to reach from existing manifold to the new subsea tree a tie-in skid with a flow loop supported by a mud mat and two approximately 25-meter-long jumpers a tie-in skid with a flow loop supported by the abandoned wellhead from the replaced tree a step-over jumper (SOJ) supported by a suction pile a SOJ supported by the abandoned wellhead. Evaluation concluded that the last option was the most cost-effective solution, with 60% capex savings when compared with the SOJ with a suction pile. The benefit of using the SOJ is that the vessel size can be significantly reduced while minimizing the amount of subsea hardware on the seafloor. Essentially, the SOJ works as an extension of the production jumper. First, the production fluid travels from the subsea tree into a conventional jumper. Then, the production fluid travels through the SOJ, where one end of the SOJ is supported by the abandoned subsea wellhead. Finally, the production fluid travels into the manifold. The SOJ is similar to a conventional half-"M"-shape jumper, which has one outboard hub (connector) at each end. The SOJ, however, replaces one of the connectors with an inboard hub and a step-over module (SOM). The SOM provides a firm connection and an inboard hub interface to connect a conventional jumper. The firm connection is accomplished by landing and attaching the SOM to the plugged and abandoned wellhead. Then, a conventional 25-meter half-"M"-shaped vertical jumper is installed between the tree and the SOM to make the final tie-in to the new respudded well. This is an opportunity for operators to utilize their existing subsea architecture to accomplish cost-saving ventures in their brownfield assets. The SOJ is an efficient solution that allows tie-ins to respudded wells that are farther away from the core field architecture.

Wellhead fatigue monitoring was performed during Plug and Abandonment (P&A) activities of a well in the Gulf of Mexico (GOM). Fatigue monitoring was deemed necessary for several reasons: an older vintage of wellhead system with uncertain fatigue life consumption from previous drilling activities, excessive wellhead stick-up, potentially large rig motions from a moored drilling rig for P&A. Fatigue monitoring was performed to ensure the integrity of the wellhead during P&A operations. The wellhead fatigue monitoring methods previously developed by several of the coauthors was applied in the wave-dominated GOM environment. Motions of the Blow Out Preventer(BOP) stack were measured and combined with a model of the riser/BOP/wellhead/casing system to reconstruct fatigue damage in the wellhead, conductor and surface casing. To measure wellhead motions, Subsea Vibration Data Loggers (SVDLs) were run with the riser and retrieved via Remotely Operated Vehicle (ROV). Fatigue damage reconstruction in the wellhead, conductor and surface casing was performed directly using the measured motion data and an analytical transfer functions obtained from the calibrated Finite Element (FE) model. Results were provided with fast turnaround time to support operations. Results demonstrated that fatigue damage rates compared well with pre-deployment predictions, though measured fatigue demand was slightly higher. It was also demonstrated that the primary cause of fatigue damage was due to wave activity at the site. Analysis of low frequency response at the riser natural frequencies indicated that the first few riser modes may have been excited by currents. It was also demonstrated that the low frequency response did not contribute significantly to fatigue life. The wellhead monitoring methods discussed result in rapid turn-around of valuable fatigue life consumption information, enabling informed decisions to be made in challenging conditions. The monitoring instrumentation and fatigue analysis methods increase the safety and efficiency of drilling, workover and P&A activities. In a larger sense, measured data also serves as a benchmark for analytical model calibration activities, reducing the known conservatism in stress and fatigue in future deployments.

The coupling effects between MODU and slim drilling riser are of primary importance in analysis of dynamic response of drilling riser system. However,, the effect of MODU on drilling riser is simplified in conventional model in a way of only considering RAO of MODU in frequency-domain, ignoring the response of MODU on current and wave in time-domain. In practical, the fitness-for-purpose assessment of drilling riser and wellhead is over-conservative by using conventional model, which will induce redundant design of wellhead strength, MODU capacity requirement, and drilling riser emergency evacuation response plan, consequently increase design and operating cost. As a result there is a requirement for more refined methodologies and finite element models to evaluate the coupling effect between MODU and drilling riser in time-domain. This paper proposes a new model, an integrated coupling model incorporated MODU, drilling riser and wellhead system, in which the response of MODU on current and wave in time-domain is considered, In addition, a case study of the new model accounting for South China Sea environmental loading is presented in this paper. A number of conclusions drawn from the case study are outlined. Firstly, it is found that drilling riser has an inhibiting effect on the movement of MODU under wave and current loading, the more MODU drift-off, the stronger restoring force acts on MODU. This will actually improve drilling riser capacity against MODU drift-off. Secondly, hysteresis effect is found between drilling riser and wellhead stress peak and MODU drift-off peak. There are some lag between each other, When the MODU drift-off reaches its peak, the stress of drilling riser and wellhead does not reach its peak. It is shown in a case study, the peak stress of drilling riser lags 40s behind the peak MODU drift-off, and the peak stress of wellhead lags 60s behind the peak MODU drift-off. As a conclusion the integrated coupling model is a more refined model to simulate the interaction between MODU and drilling riser system in time domain, which enhances the accuracy of drilling riser and wellhead fitness for purpose assessment and lead to a more optimal design of drilling riser system.

Awareness of the challenge with lower available Wellhead fatigue life has increased as the Oil and gas industry has gained more knowledge through advanced analysis and tests. Loads on Wellhead are influenced by movements from drilling rig transferred through Marine Riser and BOP. These loads cause cyclical bending moments and Wellhead fatigue degradation. The intention of Reactive Flex-Joint (RFJ) is to lower the fatigue damage by reducing cyclical bending moment, which is a main contributor for Wellhead fatigue. It's was built a technology demonstrator (scale 1:25) in 2006 and patent of the system was approved. Later a full-scale workshop test model was constructed including a Flex-Joint (FJ) for simulation of environmental conditions. In addition there were preformed thousands of transient dynamic simulations with irregular sea conditions. An independent company duplicated these analyses and all results are verified by 3rd party. The 3rd party company also approved product qualification and use before offshore deployment. An environmental test through a complete drilling campaign of a new well was preformed spring 2016, verified the technology and efficiency covering a wide variety of environmental conditions. The BOP was instrumented to monitor live bending moments and inclination with and without the RFJ. More than 50 subsea tests proved 55 - 65% reduction of cyclical bending moment meaning 10 - 15 times extension of the remaining Wellhead fatigue life. The conclusion is that a modified FJ can reduce dynamic bending moments transferred from Riser to Wellhead during drilling and Work-Over operations. Reduced fatigue exposure gives increased Well access, improved Well Integrity and significant extended Wellhead fatigue life. The reduction of cyclical bending moments on Wellhead give extension of available days for connection, enabling additional Workover and/or side track drilling resulting in Increased Oil Recovery.

Due to increased functional and pressure capacity requirements of subsea BOPs, there is a steady increase of weight and height. A down-side is that the loading of subsea wellheads due to marine riser loads is also increasing. This becomes particularly critical when deep-water rigs with large BOP stacks are used for drilling in the relatively shallow water in the Norwegian Continental Shelf. These loads may be characterized by their maximum single load and by their cyclic load variation and number of load cycles. Several wellhead system designs incorporate a rigid lockdown mechanism, where the wellhead housing is vertically pre-loaded down onto an internal reaction shoulder in the conductor housing. The pre-load and force reaction pre-stress the components that make up the lockdown mechanism. This pre-stress in particular may limit the bending capacity of the wellhead. The purpose of this study is to evaluate a lateral reaction force couple for the load transfer between the wellhead and conductor housing, instead of a traditional vertical pre-load, per the request of an operator experiencing extremely high fatigue loading in the subsea wellheads. The aim is to show favorable fatigue performance with a lateral based reaction system. Three new wellhead concept designs were developed, analyzed, and evaluated following the practices of DNVGL-RP-C203 and using generic load parameters for soft-clay and loose-sand soil types. M-N curves of all hotspots were plotted and compared against the M-N curve of a perfect 36" × 2" WT girth weld with C1 quality (considered the best fatigue performance a wellhead system can achieve for this particular conductor size) found in NORSOK U-001, Appendix B. The fatigue resistance was presented as an M-N curve. The new concept designs were refined through a series of iterations around the areas of high stresses until the worst hotspot in the system was isolated around the 36" × 2" WT conductor housing weld. The new concept designs were each evaluated and a single one was selected to continue with the fatigue optimization work. For the selected concept design, additional iterations were analyzed with and without pre-load between the wellhead housing and the conductor housing. The results are presented in the form of M-N curves for individual hotspots and for the entire wellhead system. Based on detailed FE analysis, the first iteration of all three conceptual designs showed promising results when compared to the 36" × 2" WT benchmark. For the non-preloaded conceptual design selected, analysis showed a possible solution, both with respect to fatigue resistance and structural capacity. The new conceptual wellhead design consists of only four major components. Although the overall size of the system has increased slightly compared to conventional systems, a preliminary commercial review shows reduction/simplification in manufacturing processes involved.

The scope of this paper is to show how digitized, structured data, as a combination of design data, operational data, riser analyses and measured riser response can be used to enable drilling operations on a subsea exploration with well challenging soil or/and harsh environmental conditions. The structural integrity of the well foundation and soil support has been verified by combining the structured data obtained from measurements with the design information. A sensor system has been fitted to the riser and BOP on mobile drilling units to monitor soil and structural integrity. The combination of pre-operational assessments and monitoring during operations has been carried out for 7 consecutive drilling campaigns, with two different semi-submersible drilling rigs. The work presented in this paper will give a comparison between the measured response and the up-front design analysis, and show show to combine the design information with operational data and measured response to enable future operations. During the design phase of a subsea exploration well a wide range of design assumptions must be considered. The range in high and low estimates for parameters such as soil support or riser and BOP mass and damping forces may be considerable. In general conservative parameters must be selected, leading to worst case scenarios, which again may lead to limited operational windows, introduce high cost mitigating actions or in worst case prevent operations from being carried out. This paper will present the benefit of using actual measured response and operational parameters back into the design loop when planning upcoming drilling campaigns. Structured operational data and measured response is used to improve analysis models; which lead to reduced conservatism. For cases of re-entry on an existing exploration well with heavier equipment, the measured soil support can be used to rule out some worst-case scenarios, and enable the upcoming operation. A case example of an exploration campaign enabled by the design loop will be shown.

Subsea equipment design verification and validation are to be performed by analysis and testing, respectively. Two of the most important aspects of this process for high-pressure, high-temperature (HPHT) applications are load estimation and fatigue assessment. This paper presents dynamic loading scenarios typically considered in the design of subsea wellhead in HPHT applications during service life as well as load estimation of these scenarios, particularly on riser loads. Fatigue damage to the subsea wellhead is also included to examine the significance and effect of the loads from each of the loading scenarios. Dynamic loading scenarios in drilling and production phases are evaluated in the paper. In the drilling phase, typical loading scenarios for the riser in connected conditions with wellhead are evaluated. A typical drilling system, generic sea state scatter diagram, soil condition and operational profile are selected to estimate the dynamic loads for each of the scenarios. In the production phase, typical loading scenarios are also evaluated. A typical subsea production system with the same sea and soil condition as drilling but with different operational profile is selected to estimate the dynamic loads for each of these scenarios. A typical wellhead system including wellhead housing, conductor, and casing system is selected for the riser load estimation and the wellhead fatigue assessment using fracture mechanics method is carried out in accordance with API 17TR8. Dynamic loads estimated from the scenarios in drilling and production phases are compared at the top of the wellhead in terms of maximum load and load histogram. The significance and effect of these loading scenarios are also evaluated from the fatigue standpoint at select hotspots on the wellhead system. From the study, it is observed that loading from drilling and production phases are equally important and both should be considered to verify the subsea wellhead's structural capability. In the paper, an analysis procedure to evaluate the riser load to the wellhead and fatigue assessment of the wellhead is proposed, which may be used for the design verification of subsea wellhead in HPHT applications.

Fatigue damage predictions of risers and wellhead/casing systems due to drilling operations require predictive modeling techniques for load calculation/estimation. This work attempts to address the uncertainty as to whether the global riser analyses are overly conservative due to model idealizations, analytical assumptions, the use of time- or frequency-domain techniques, and incorporation of certain linear or non-linear behavior. To address these questions, a field measurement program was executed to obtain vessel, riser and stack motions data, which were used to validate analytical models and procedures. A real-time monitoring system was deployed on a 6 th generation semi-submersible mobile offshore drilling unit operating in a shallow water, harsh environment region. Accelerations and angular rates were captured on the Lower Marine Riser Package (LMRP), drilling riser and vessel. The metocean data consisting of measured seastates and full-depth current profiles, as well as riser tensions, mud weights, and vessel offsets were also concurrently recorded. The global models of the riser, wellhead, stack, casing and soils were created using two in-house software, DERP (frequency-domain) and RAMS (both frequency- and time-domain), using "as-designed" input information. Analytically predicted motions (displacements and rotations) of the LMRP, riser, and vessel were compared with the measured motions. It was found that the frequency-domain analytical results match the measured data well over all the measured significant wave heights, which ranged from 6.5-ft to 26-ft. Since the riser and LMRP RMS motions are well predicted by models, it follows that wellhead loads are well estimated from analytical models. The frequency-domain analytical results were further verified for a few cases by time-domain analyses. Both measured and analytical spectra generally exhibit peaks at similar frequencies. While the first analytical riser mode is clearly identified in the measured data, the analytical blow out preventer (BOP) stack/riser mode is not as evident in the measured data. Further, the measured peak close to the analytical stack/riser frequency is very broad. These observations and additional sensitivity studies showed that further investigation for sources of damping due to soil and/or stack hydrodynamics is required. This work shows that the modeling techniques used presently for analyzing the global riser/stack response in frequency- domain are reasonably accurate for the analyzed conditions.

The objective of this paper is to present the field test results of a subsea casing annulus monitoring system utilizing wireless through-wall communication technology which recorded and transmitted pressure and temperature data from a casing annulus in real-time during the drilling, logging, and capping phases of a subsea well. The annulus monitoring system used off-the-shelf sensors to acquire pressure and temperature data in the casing annulus. The data was communicated from inside the casing annulus to the outside of the subsea wellhead system using a novel wireless telemetry technique through solid casing layers instead of traditional bulkhead connected equipment to avoid penetrations to the high pressure housing. The sensor module was attached to a 13-3/8" casing joint below the casing hanger and was configured to fit into the annular space between the 13-3/8" casing string and a 20" casing string. Additional telemetry equipment was adapted to the outside of the low pressure wellhead housing and a 30" conductor casing string which received and processed the transmitted data. Once installed, the monitoring system continuously transmitted temperature and pressure data throughout the rest of the drilling program until the well was plugged and abandoned. The annulus data revealed how high the annulus pressure increased due to thermal effects while drilling and circulating fluids in the wellbore bottoms-up. Upon completion, the system confirmed that the trapped annulus pressure below the 13-3/8" casing hanger annulus seal assembly was low enough that the wellhead and casing could be safely cut and retrieved. The field test confirmed that the monitoring system is suitable to survive drilling operations and communicate data from the wellhead casing annulus to the end user in real-time. This marks a first for a drilling-centric wirelessly transmitted annulus monitoring product that takes the guesswork out of annulus pressure well-control or remediation concerns. It allowed the drilling group to see live data on the fluid pressure and temperature in the annulus of a wellhead system without any type of penetration while drilling the remaining critical sections of the well and did not require any modification to existing subsea wellhead components or operating procedures.