Casing collapse resistance is one of the key factors in well integrity design especially for production casings and the aim of the current study is investigating the physical phenomena that define the mechanism of failure in presence of two concentric cemented casing strings. Collapse load mode, especially in specific conditions, becomes the governing load of the well. Typical examples are salt or other creeping formations, which represent the most difficult load combinations to design and analyze. Salt creeping movements create three loading mechanisms that may result in a production casing failure: uniform loading, non-uniform loading and shear loading. The current oil industry approach, to deal with salt formations, is using two casing strings or either an individual "high collapse" casing column. This paper describes results of a joint activity between Eni and Tenaris aimed at evaluating on full field scale the combined collapse resistance of two casing strings in three different cementing configurations. The experiment consists of two different laboratory test set-ups. The first set is a collapse test, performed in a high-pressure vessel under hydrostatic conditions, to reproduce salt distributed Uniform Loading. Meanwhile the second test set, which is one of the first worldwide experiments of its kind, reproduces punctual Non-Uniform and Shear Loading. This second test is conducted with a mechanical press equipped with an ad-hoc designed indenting tool. The scope of the tool is to reproduce the effect of hard formation inclusions, in salt layers, acting on the casing's external surface. Test set-up and specimen's geometric configuration are optimized by specifically developed FEA analyses. To simulate real stress conditions, as the ones found in the well, tests are performed on different specimen configurations. The base configuration consists of perfectly concentric casings with standard cement slurry in the annulus. Moreover, a configuration with 10% stand-off is also tested. At last, a configuration simulating the effect of contaminated cement or poor cement job is evaluated. The latter allows a better cement contribution assessment to final collapse resistance. The results of the first set of experiments allows empirically defining a coefficient, "K-value", used to define collapse resistance of the assembly; the second set provides an indication about the entire system resistance to punctual loads and cement sheath integrity. Purpose of these tests is to extend the outcomes to several casing sizes thru the utilization of FEA model. The obtained result of full-scale experiments is the way forward to better understand the collapse phenomena and approach the casing design for "pipe in pipe" cemented strings, with a significant impacts on well final cost and integrity.

A physical evidence of an injector well failure caused by transient thermal behavior in cooling operations has lead to technical actions in order to provide a safe operational envelope. A modified thermal analysis was developed to predict the transient thermal behavior that can result in a cascade casing collapse. The as built approach was applied in a number of wells already constructed in a Brazilian offshore field resulting in a better way for selecting which mitigation method can be appropriate for each case. One of the main results from the study was to establish a controlled injection flow rate in order to avoid a cascade casing collapse due to thermal shock in the wellbore. In some cases, it was necessary to provide an annulus pressure communication in the wellhead using a ROV for bleeding off the excessive pressure in C annulus. With these actions, the wells studied were able to present a safe operational envelope. The approach commonly employed in the industry takes into account just steady state injection operations, which are not enough to describe what is happening in the field and also are not sufficient to support a suitable casing design. The industry must put efforts to develop and consolidate a methodology based on transient thermal analysis to deal with thermal shock events in the well, as proposed in this paper. Furthermore, this work also proposes four alternatives to mitigate the well integrity loss based on the transient thermal simulations and a comprehensive well risk assessement.

The annulus seal assembly is an essential component of the subsea wellhead system, providing hydraulic isolation to other annuli. A failure of that device can lead to a very costly replacement intervention, due to the need of removal of the subsea equipment and production string, or even serious integrity consequences, such as underground blowout or cascade collapse of the casing strings. During the well lifetime, the annulus seal assembly is submitted to various types of loads, depending on the well temperature and the operated pressure of the "A" annulus. The analysis of those loads identified critical moments for the annulus seal assembly, which could exceed the capacity of that device if the proper lock mechanism is not installed, and cyclic loads could further depreciate its capacity. The objective of the present paper is to present a methodology to evaluate the critical loads, failure modes and qualification procedures for long-term well integrity.

The operation described in this paper is related with an ultra-deep-water exploration well drilled in the Mexican waters of the Gulf of Mexico and the first drilled by the operator in the area. From the onset of planning the base case was to integrate a Managed Pressure system into the drilling program to mitigate prognosed pore pressure uncertainty, pressure ramp increase, and narrow PP/FG window operations including; drilling, tripping, running casing. Although Managed Pressure cementing was not originally in the scope of work, it was required due to the tight drilling window and successfully executed. A narrow pressure window (1.07 sg – 1.13 sg) encountered in the 12-1/4" × 16-1/2" section resulted in the managed pressure system being required to run and cement the 13-3/8" casing string while managing the annular pressure profile. Placement of the cement was critical to isolate a permeable zone below the previous casing shoe and reduce the chances for aremedial cement work. The main objective for using the MP system during cementing was to ensure the EMW at both TD and the previous casing shoe did not fall below the set limits throughout the job. While the secondary objective was to reduce and/or eliminate losses. With the total depth being 4,151m, water depth of 3301m, surface mud weight 1.03 sg with down hole equivalent mud weight of 1.047sg due to compressibility and temperature. The main objective for using the MPD system during cementing was to ensure the EMW at both TD and the previous casing shoe did not fall below the set limits throughout the job. While the secondary objective was to reduce and/or eliminate losses. With the operator depth being 4,151m (13,619 ft), water depth of 3,276m (10,748 ft), surface mud weight 1.03 SG (8.58 ppg) with down hole equivalent mud weight of 1.047SG due to compressibility and temperature Planning for the job required input and collaboration from various personnel from the operator as well as third party services working together to run simulations, calculations, and analyses to create a detailed program. With the casing on bottom, the execution phase of the operation again required significant planning and organization on the rig to successfully implement and execute the step by step instructions for the job. MP cementing was executed as planned, with no losses measured, following the displacement sequence and surface backpressure step down until observing the plugs bump. Zonal isolation was achieved, confirmed through an adequate pressure test of the casing, as well as, a sufficient FIT to drill the subsequent section. The focus of this paper is on the planning and execution of an ultra-deep water managed pressure cement job drilled in the Mexico side of the Gulf of Mexico. Learnings and observations were collected during the planning and execution phases. These learnings may assist other managed pressure operations to successfully implement and execute MP cement on ultra-deep water operations in the future.

As operators in the oil and gas industry continue to search for larger oil deposits in areas that are considered High Pressure and High Temperature (HPHT) environments, manufacturers of liner hanger/packer systems must conceive and validate designs that can support these projects. The XPak™ liner hanger/packer system is an expandable product that offers metal-to-metal and elastomer sealing capabilities at the liner top in host casing, capable of superior hanging capacity and seal integrity for installing casing strings of various lengths. The expansion process is achieved using a multi-piston hydraulic running tool with pressure application to displace an Expander inside the XPak hanger body. The displacement of the Expander inside the XPak hanger body relies on interference between the components to radially grow the hanger body to contact and interfere with the host casing. This interaction provides the sealing and anchoring capability of the XPak system. The Expander provides tieback capability via a polished bore receptacle and remains installed inside the hanger body for the lifetime of the installation. Operators are implementing robust host casing designs with less variance in wall thickness to utilize tubulars with higher burst and collapse ratings than those manufactured to API standard variances. The combination of higher burst pressure ratings for the host casing and limited variance on the inner diameters provides an ideal partner for the XPak system. Expandable products rely on a narrower host casing inner diameter range to create the interference needed for optimum performance, as opposed to conventional liner hanger systems which work over a broader diameter range. An ISO 14310 V0 qualification of a 7-5/8 × 12-1/4 HPHT XPak liner hanger/packer system for a major operator in the Gulf of Mexico successfully achieved testing milestones of 15 ksi internal pressure with a combined loading of 1,000 kips in tension at 375°F. The system was also qualified at a low temperature of 60°F reaching a successful test pressure of 21.75 ksi internally with a combined tension load of 1,000 kips. These testing requirements were provided in the customer's statement of requirements to handle extreme well loading conditions. FEA modeling is the primary tool for XPak design and focuses primarily on identifying and predicting material strain to help determine the system capabilities under simulated pressure and loading conditions. The distinct geometry and controlled deformation of the hanger body during expansion are simulated using FEA software to provide guidance to meet design parameters to reach high levels of performance. The initial conceptual design is taken through a complete range of potential well scenarios including: casing inner diameter ranges, maximum and minimum setting forces, geometric tolerancing, friction factors, and transient thermal loading. The results are compiled and reviewed to determine the optimal design model to satisfy the customer's requirements. Validation testing and field installation performance for this product line has been successful. The use of analytical tools for design along with improvements in material options and manufacturing processes has been instrumental in the continued growth of the XPak liner hanger/packer system.

The estimation of casing wear from USIT or Caliper logs requires a proper evaluation of the shape of the tubular inner surface prior to casing wear. In the absence of a viable baseline log, this shape must be deduced through analytical means. Manufacturing deviations from perfect circularity result in eccentricity and ovality, so that the pre-wear shape is in general, elliptical in nature. Owing to the fact that a standard ellipse may not be adequate to capture this shape in all situations, an approach using a distorted and shifted ellipse is proposed. The shift from the geometrical centerline of the ellipse co-ordinates in order to capture the effect of improper centralisation of the logging tool. The approach uses a least-squares minimisation technique to determine the distorted ellipse parameters such that the overall radial discrepancies between the pre- and post-wear shapes are minimised. A multi-pass approach wherein detected wear grooves are censored results in better predictions of the pre-wear shape as was determined from several validation test cases with known wear groove depths. The methodology was also applied to an actual USIT log with over 20,000 stations with 72 radial measurements at each station. The methodology also enables the detection of true locations of high wear from spurious ones. As proposed, the method is also capable of using either internal radius or wall thickness as the evaluation metric, and is stable in the presence of significant noise in the measurements.

The industry standard that governs the testing of casing and tubing connections is API Recommended Practice (RP) 5C5. Due to the complexity and variety of load combinations that a connection can experience in the field, especially in deepwater/HPHT applications, a new version of API RP 5C5 was released in January 2017. (The previous version of RP 5C5 was the Third Edition published in 2002.) This latest version requires in-depth collaborative involvement from both the operator and supplier to ensure that the testing fulfills both the industry standard and any operator-specific functional requirements. In order to assess structural integrity and sealability, an operator requires validation testing of production tubing connections to demonstrate "fit-for-service." Due to the critical nature of production tubing, acting as the primary barrier for produced fluids, the most rigorous testing protocol was selected—API RP 5C5:2017 CAL IV. Of all the connection assessment levels (CALs) outlined in API RP 5C5:2017, CAL IV most accurately captures the sequence and severity of loading that may be experienced by production tubing in an HPHT environment. This paper outlines the evaluation and testing methods conducted collaboratively between a supplier and an operator, appropriate for a deepwater HPHT project. Three different oil-country tubular goods (OCTG) connection sizes were tested to API RP 5C5:2017 CAL IV. This paper includes a step-by-step overview of the process—initial review of the connection, gap analysis of product-to-testing requirements, modification of testing protocol, physical connection testing, and final reporting of the results. The operator and supplier wish to share their experience and lessons-learned in testing connections to the latest qualification standard. This experience includes the detailed coordination and communication needed among all parties involved.

Digital well planning, construction and maintenance have a lot of potential for cost reduction and improved HSE. Developing a software model to replace many of the tasks performed by humans can reduce administrative tasks and enables more focus on the quality of plans and operations. One single model to overlook engineering and activity through the life cycle of wells from the planning phase, through construction, production, maintenance to the final plugging unlocks many potential improvements. One possible feature for a Life Cycle Well Integrity Model (LCWIM) is to embed industry standards to supply guidance and recommendations during the life cycle of a well. Changing the format of standards so both computers and humans understand their content can benefit the planning and operational phases of well construction, intervention, production and finally plugging. Typically, standards are used broadly in the planning phase. However, in the later phases of the life cycle of the well, it is often more difficult to accommodate both changes in operations and updates to industry standards. Embedding the industry "best practice" into software for planning well construction and maintenance, can prevent potential human errors and ensure an appropriate well construction. Having standards as "digital eye" on the engineering and well construction parameters can help to ensure safer operation and help to ensure that no regulations are overseen due to human error. Standards can be considered a collection of experiences gathered over decades in the industry, and they represent the common ground for description of methods and procedures for safe and sustainable operations. When digital well planning gradually replaces the traditional manual planning processes, the vast experience of standards can support engineers more actively and directly compared to text documents. This paper describes an approach to merge the digital version of a standard into the LCWIM so it actively provides relevant information to ongoing operations similar to a help function. The user would experience this as "relevant information" by just a mouse-click. The method of choice elaborated in this article shows a life cycle standard in the shape of an active support module to the LCWIM. The reasons behind the selected approach is twofold: (1) LCWIM is a life cycle tool, which incorporates life cycle standards to support all activities in all phases, (2) Standards support LCWIM by verifying that tests and procedures are in compliance. The focus of this paper is to demonstrate how a life cycle standard like the NORSOK D-10 Rev. 4, June 2013 can be completely digitalized to take an active part in planning and operations. The scope is limited to section 5.6 "Casing design" with elaboration of section 5.6.3 "Load cases" to stepwise show one way the standard can become interactive.

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.

A new generation software for well construction and maintenance is under development. The working name is Life Cycle Well Integrity Model (LCWIM) as its main focus is to support work with wells and fields from the planning stage to final P&A. LCWIM is a systematization of a fully digitalized software model that can provide many advantages for the industry. This paper focusses on four main objectives: Firstly, reduction of workload and direct human involvement by replacing many tasks in well construction and well integrity engineering by automatization. The goal is to shift the focus of humans towards supervision of computerized processes. Secondly, a modern software architecture should provide a fluent interlink between all stakeholders to provide and share information. A fully digitalized module should reduce repetitive tasks. Building on the architecture and metadata of LCWIM, future digitalization projects in e.g. administrative routines such as invoicing can be linked to establish a work process dominated by computerized events which are supervised by humans. Thirdly, the model will store all relevant data pertaining to a well through its life cycle, providing a potent self-service information hub that is easy to use for all disciplines. Fourthly, the scope of the LCWIM is to improve HSE and significantly reduce non-productive time in three ways: (1) interactive experience transfer, (2) embedding of interactive standards and governing documentation to support planning and operation, (3) elevation of personnel out of direct involvement into a supervisory role to reduce human error. Access and availability favours a cloud based solution. With increasingly more data and information to process, a modern software will require significant processor capacity that is scalable according to the number of users. By combining the capacity of both servers and local computers, the software can provide advanced calculations and graphical representations at interactive response times.

Section milling is a method used in plug and abandonment operations to remove casing over a specified interval, enabling a barrier to be placed for complete isolation across the wellbore. This method is preferred and often required when an annulus behind a casing string is not properly isolated and cannot be appropriately remediated by conventional methods such as cutting and pulling the casing, or squeezing cement through perforations. Section milling and placement of a rock-to-rock cement barrier is a highly effective method for achieving proper wellbore isolation for plug and abandonment. However, this method poses unique challenges that can result in lengthy, complex operations and high costs to operators. A key challenge faced when removing high volumes of casing (up to and exceeding 50 meters (165 ft.) per interval), is circulating the generated steel cuttings (swarf) out of the well, and safely capturing and disposing of them. Much of the time spent on section milling operations is dedicated to mitigating the health, safety, operational, and equipment risks associated with the removal and handling of swarf in the well and on surface. These challenges inspired a joint operator/ service company project to develop a method of section milling that would deposit swarf into the wellbore, creating a unique, and in-situ approach to debris management that reduces risk and costs to the operator. The prototype section milling system was extensively tested, with final, full-scale tests performed in a drilled and cased hole from a fully functioning land rig. Conclusions from the final test well operations yielded favorable results, resulting in a final system design that was qualified for field use. Currently, the system is in final preparations for its first field deployment, with candidate wells identified and equipment ready for use. First planned operations are scheduled for a platform well on the Norwegian continental shelf. This paper will detail the final testing phases, field trial preparations, and candidate well selection leading up to the first field deployment of a first ever ‘swarfless’ section milling system.

As the industry progresses into deeper waters with reservoirs that require more complicated well designs, there is an increasing need for equipment that can withstand higher pressures, temperatures, casing loads, and structural and cyclic loads. A 20,000 psi 350°F rated 18-3/4″ wellhead system has been developed to meet those needs. The system was designed and qualified to API 17TR8 with the addition of rigorous internal design and testing requirements. The system design is based on the field-proven technology of a legacy 20,000 psi 350°F 18-3/4″ wellhead system (reference OTC paper 19694) which completed development in 2008, prior to the release of API 17TR8. This API 17TR8 compliant wellhead system can support a total of 4,400,000 lb of casing weight inside the high-pressure wellhead housing, including up to 2,400,000 lb of intermediate casing weight in the first position and up to 2,000,000 lb in the second position. The system is provided with annulus seal assemblies (ASA) designed and tested through an extensive qualification plan made up of industry required testing in addition to testing identified by a detailed Failure Modes, Effects, and Criticality Analysis (FMECA). Operators can install and test the first position and second position ASAs, up to 20,000 psi, in a single trip with the use of a specially designed single trip tool. A spring-loaded tool and wear bushing also allows the operators to test the blowout preventer (BOP) to 20,000 psi while isolating the ASAs. The design of each component involved detailed elastic-plastic finite element analysis (FEA) per ASME BPVC Sec. VIII, Div 3 and a rigorous qualification plan generated through the FMECA process. The goal of this paper is to provide an overview of the development (verification and validation) of the 20,000 psi 350°F wellhead system per API 17TR8 and the independent third party (I3P) review as required by BSEE for an HPHT wellhead system.

In an attempt to reduce the capital expenditure (CAPEX) costs of field development, the development and adoption of focused, bespoke equipment can provide significant cost savings. With rig based technology consistently accounting for over 40% of a well construction or de-construction project, it is an area with significant cost reduction potential if alternative facilitating technology is deployed. The paper describes alternative facilitating technology. Modification and project specific integrated engineering that allows for potential cost reductions, through early engagement with an operator and project stakeholders. A well construction project case study presents the early interfacing with a Yangon based operator, concerning the development of an Intervention and Completions Unit (ICU) for operations in a segregated well construction project, to undertake well completion and stimulation activities. A well rejuvenation project case study presents the engineering modification of a Hydraulic Pulling and Jacking Unit (PJU) to undertake well slot preparation activities for mature asset rejuvenation activities for a Gulf of Mexico (GoM) operator. The focused engineering presented in the well construction and well rejuvenation case studies, and the identification of functionality requirements that can be improved to operate in high cost base projects, demonstrates the potential savings that can be achieved. Detailed operational analysis appraisal, and identification of those activities with empirically high levels of non-productive time (NPT), are categorized and technology solutions are developed. Technology solutions provide the required technical capabilities for the intended operations, whilst reducing the associated base construction, maintenance, certification and operational costs that are commonly experienced with over specified equipment. Both case studies present the benefits to the operator in the pre-engineering and design phases, allied to operational benefits.

As the industry's need for upstream oil and gas equipment designed and engineered to work in deeper water and harsher environments grows, so does the importance of challenging the thoroughness of wellhead system validation testing. With virtually no ability for operators to standardize on wellhead system configurations (ie, casing sizes, weights, BOP stacks, rigs, riser systems, etc.), the capability of these systems must be equally comprehensive. Increased flexibility in individualized components may be realized through more effective validation testing which would serve to minimize the need for specialty equipment. Current industry requirements are not prescriptive enough to ensure that certain claimed capabilities of these systems are effectively validated in such a manner as to accurately reflect the as-installed scenarios of the components, most notably with respect to the subsea casing hanger/seal lockdown performance. This paper proposes what the authors believe should be considered the standard industry requirements for validating subsea seals/casing hangers, for casing hangers held in place by mechanical means, within the next generation of wellhead systems. The proposed requirements are intended to meet the demands of current and future wells. In the development of these propositions, many challenges are illustrated in association with effectively producing testing methodology which accurately reflects the field operations for the equipment being qualified. The subsea wellhead system functions in a dynamic, complex environment; however, the qualification process of this system commonly employs relatively static test fixtures. The test configurations for this equipment may lack assemblies which would prevent hardware movement generated by thermal growth, annulus pressure buildup and/or other factors due to the conditions of normal or even extreme/survival (e.g. worst-case discharge) events. These critical seal/casing hanger barriers within the next generation wellhead system are presented, discussed and shown with exhaustive validation efforts necessary to evaluate relevant failure modes and the ability to standardize across various wellhead configurations. Within the wellhead system, loads are typically resultant of a combined state including pressure and temperature. The validation of these components is aimed at defining the performance of the system in these states while detailing the limitations that one performance aspect may have on another. Well-defined subsea seal/casing hanger validation testing requirements to accurately simulate the installed configuration are provided. Loads are applied independent of pressure within these assemblies, and in doing so, the performance of the components have been defined throughout a distinct operating envelope of combined loads and pressures. The operational envelopes validated by this testing offer the information a well designer needs to ensure that the hardware selected is suitable for a variety of applications. The antiquated claims of not being able to provide metal-to-metal sealing in dynamic applications are dispelled based on performed validation testing of a metal-to-metal seal (with no elastomeric/thermoplastic elements) which accurately represents field scenarios, in which combined pressure/temperature, load and hanger movement are applied. The need for costly equipment installed within the system to withstand certain dynamic conditions is shown to be unnecessary with a fully defined high capacity casing hanger/seal lockdown operational envelope.

Well abandonment operations represent pure cost to the operator without return on their expenditure. However, to manage future liability, these activities are critically important. Performing them correctly involves detailed planning. Good practice places a permanent barrier across the wellbore in competent cap rock and embeds all tubulars in the cement. Herein lies the main challenge for well abandonment; annular isolation is sometimes compromised or wasn't there from the start (e.g., subsea wells). Addressing these annular isolation issues results in extra steps in the well abandonment process, translating into extra time and money for the operator. This paper will discuss field-proven, cost-effective solutions for casing removal including reducing the surface footprint or providing a single-trip solution that lowers the overall cost of operation. Multiple case histories will highlight different challenges, solved by novel ideas and a combination of surface systems and downhole equipment. Case History 1: 13⅜-in. casing partially stuck in the well needs to be removed, a single cut-and-pull operation was not successful and milling was not an option due to shallow/weak formation and equivalent circulating density (ECD) issues. Advanced milling technology enabled 30 casing cuts in a single trip in short sections, allowing each section to be pulled free using the rig's pulling capacity while minimizing surface handling. Case Study 2: Platform load capacity or pulling capacity limitations often lead to challenging casing removal operations for slot recoveries and/or permanent well abandonment. Exercising downhole pulling force by anchoring in a larger casing size and utilizing pump pressure instead of overpull enables freeing of pipe with limited surface capabilities. Multiple examples will be shown, including time saved. Case Study 3: Platform conductor removal operations can be very challenging when the type of connectors cannot carry the full conductor load with inner casing strings. A Rigless solution performing simultaneous operations with the main platform rig, using a sacrificial casing string to pull from the bottom provided a cost-effective solution. Case Study 4: Platform conductor removal where the conductors have been previously cut and now stand in the water column present challenges of a different kind. The limited platform size led to a casing jacking solution with guide wires that safely and cost-effectively remove the conductors from below the mudline without bringing in a jack-up rig. A "now what" selection guide at the end of the paper provides an overview of different solutions available, depending on downhole scope of work and the surface capabilities.

Now, more than ever, the integrity of the wellbore before the recommencement of drilling operations or production of reservoir fluids, is fundamental to safe operations. Stricter well control policies have been instated in recent years, so it is critical to perform casing inspection, and cement evaluation measurement surveys to ensure adherence to regulatory codes. As exploration and development drilling activity breach new horizons, it brings new challenges to cementing operations and subsequent cement evaluation surveys. Heavy drilling muds, extra-large casing sizes, and narrow drilling windows: cement to mud weight ratios which can led to cement contamination are just a few. Until recently these constraints limited the usefulness and reliability of ultrasonic measurements under the said conditions. This paper describes a new generation of ultrasonic sensors and technology that fills the gaps left by predecessor technologies and allows operators to feel confident and at ease with the integrity of their wellbores, even under the most taxing conditions. The advantages and associated cost savings enabled through the utilization of this technology are illustrated in the case studies at the end of the paper.

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.

Well construction in increasingly water depths makes harder to design, manufacture and install surface casings to support loads imposed on them. In addition to the static loads, that designers are accustomed, dynamic loads are present in surface casing due to rig movement caused by sea waves. In recent history, there are some cases of unexpected break off or disconnection at the top while running surface casing. The objective of this work is to model and analyze the axial dynamic behavior and loads generated by the movement of the tubular element system during installation of surface casing in water depths up to 3,000 meters and casings up to 1,500 meters. The idea is to verify if this dynamic behavior compromises the surface casing or the drill pipe used, leading to failure. To achieve this goal, an analytical model is obtained for the equations of motion governing the tubular element system while running surface casing. From the solution of the equations obtained, several simulations are made in various scenarios to support the conclusions regarding the behavior and the consequences that these movements can cause are predicted. Although this study uses some equations and modeling already published, the modeling of the boundary condition on the float shoe and the application of models and analysis of surface casing axial dynamic behavior are unprecedented.

The oil and gas industry is targeting operations in much deeper waters and well depths resulting in high pressure and high temperature (HPHT) applications, creating a need for development of new technology to meet the challenges faced in these new frontiers. Considering the higher loads encountered in these environments, the existing industry equipment are reaching their limits and the manufacturing sector is looking into the development of the next generation equipment. Subsea wellheads form a critical part of the drilling and production systems, and they are the driver for designing and sizing other equipment, such as connectors, risers, BOPs, and casing programs. The typical wellhead systems that the industry currently uses include mandrels with 27 in. and 30 in. OD and conductor casing with up to 36 in. OD. However, these configurations may not be able to resist the high load magnitudes and combinations expected in these new applications. Moving to higher capacity wellhead systems will require a larger mandrel and conductor casing size to accommodate the high loads encountered during drilling and production operations for normal, extreme, and survival loading conditions. Considering the ongoing industry efforts to standardize equipment, it is a great opportunity to define the anticipated loads and select an appropriate larger wellhead size that will cover the needs of the industry for the coming decades. Numerous analytical studies using 3D finite element analysis (FEA) and other advanced tools have been performed looking into the changes needed and an innovative solution is presented for the next generation subsea wellhead equipment. This is tied with the development of new wellhead connectors with much higher static capacities and the appropriate conductor sizes needed. Considerations are given to structural integrity, fatigue performance, and metal-to-metal sealing capability. Various load combinations (bending, tension/compression, pressure) were applied to generate the wellhead system capacity envelopes covering a wide range of operating windows. The need for the industry to define the anticipated normal, extreme and survival loading requirements and a standard set of fatigue loads is discussed. The fatigue performance and life expectancy of the equipment, as well as challenges faced with the lack of material properties at various HPHT environments are discussed. Testing facilities to validate designs and safety margins at both component and system levels have been developed to accommodate the various high load magnitudes and their combinations. Validation testing is absolutely paramount to verify analysis methodologies and ensure high performance, safe, robust and reliable equipment designs.

Watch circles are established by operators to ensure a dynamically positioned vessel does not induce loads that exceed wellhead system equipment capacities. In the event the vessel moves off station, beyond the boundary of the watch circle, loads could be transmitted that may approach or exceed the equipment ratings and possibly cause failure. A whole system weak point analysis approach is required to determine and identify the likely failure modes and locations throughout the system. This paper presents a system weak point analysis using a 3D finite element analysis (FEA) of an API Studded BOP Flange, Hydraulic Wellhead Connector, and Subsea Wellhead System. The FEA models include the first 200 ft below the mudline and are used to evaluate the capabilities of the entire system to failure. To ensure accurate load transfer between the components the actual field installation sequence was modeled, which included contact between components, all preloads, soil resistance, casing string weights, and cements. Subsequently, the global external loads from the rig were incrementally increased beyond the rated load capacities of the entire system to determine failure points. Loads, stresses, and strains in each component were determined as a function of the global external loads. Each component of the system was modeled using elastic-plastic material properties per ASME BPVC, Section VIII, Division 3, Paragraph KD-231.4. Critical points throughout the wellhead system were monitored for failure which was defined as either through wall plastic strain or through wall stress above yield across the entire wall of a component. A sequential order of limiting locations, or weak points, was determined (first limiting location, second limiting location, etc.). The weak point analysis performed provided valuable information to assess and help mitigate risk. The analysis results also provided valuable insight and context to the equipment manufacturer to develop more robust and reliable system designs. The insights gathered by doing a weak point analysis using large 3D FEA models of the entire system, inclusive of the wellhead system, wellhead connector, and flanged connection, are presented and provide a better understanding of the system behavior and failure mechanisms.