Case History: Hydraulic Workover Unit Utilized to Recover Highly Corroded 30-Year Old Completion from a Live Gas Well in the United Arab Emirates

In the UAE, an Operator needed to perform a completion change out in a gas well, where the existing completion has been installed for over 30 years. Logging operations had revealed several leaks point in the production tubing due to corrosion. To rectify the situation, a Hydraulic Workover (HWO) Unit was proposed integrating a punch ram in the Blowout Preventer (BOP) Configuration to manage the bleed off of potential pressure trapped between the isolated sections of the completion at surface. This document describes how the highly corroded completion tubing with eleven retrievable plugs set in a live gas well was recovered. The HWO Unit was modified so that one of the cavities in the BOP stack was dressed with customized punch rams for five inch pipe, with the objective of allowing control of any potential leaks due to plug failure. The pressure relief operation could then be completed by means of punching the tubing in the controlled environment that a Stripping BOP Stack provides. This paper compiles the details of the BOP configuration and operating procedures to recover the completion by stripping out of the well and operating the punch rams with the snubbing unit. This includes the pre-job preparation required for a successful operation and the overall design with where to locate the collars and plugs for an accurate punch, and how to confirm that the plugs are holding the pressure to continue retrieving the next completion section. In the end, a safe operation was completed with zero incidents or down time allowing the intervention to continue to the next stage of recompleting the well and putting it back to production. The customer was able to get the well back to production with an alternative solution to what was initially considered, representing a significant cost and time saving.

The Integration of Managed Pressure Drilling MPD and Automated Well Control Technology

Digitalisation and automation can account for massive efficiencies in wells operations. Managed Pressure Drilling (MPD) and Automated Well Control are examples of "smart" technologies that can mitigate risks and costs associated with drilling wells. The Automated Well Control system was developed to monitor the well, identify an influx, take control of the rig equipment and shut in the well. MPD provides annular pressure control, real-time information of the well parameters and conditions downhole and very accurate and immediate influx detection. However, if a high intensity influx is taken that exceeds the pre-planned operational limits of the MPD package, then secondary well control is required. Therefore, a combination of Automated Well Control and MPD has been developed to deliver both pressure control and well control in a safe, efficient and less error-prone manner. On an MPD operation, the Automated Well Control system shuts-in the well as soon as it is required to do so. With Automated Well Control in MPD mode, the MPD system decides when to shut in and the Automated Well Control technology will immediately space out, stop the mud pumps and top-drive, and shut in the well using the pre-selected blowout preventer. This interface between the two systems mitigates drilling hazards using automation. The sensitivity of MPD, combined with Automated Well Control technology enables fast identification, decision making and reaction to well control events. Consequently, this fully integrated solution improves safety and operational efficiency. The MPD and Automated Well Control systems were integrated into a test rig and several tests were efficiently performed. The tool enabled immediate action in the event of influxes, providing a valuable solution for the industry. This paper briefly describes MPD and Automated Well Control and summarises the interface between the two technologies, detailing how the integrated system works on a rig. Moreover, rig trialling results and further developments are presented.

Subsea Tree Fatigue Mitigation Solutions For Shallow Water Drilling

The offshore drilling industry is advancing technologies to extend deep water drilling technologies and attain feasibility of operations at deeper depths and higher pressures. However, shallow water operations themselves pose a certain unique set of challenges that need to be addressed with customized and innovative solutions. While shallow water poses certain benefits and conveniences to the operations, like ease of retrieval and better access to wells, there are significant challenges in terms of operational down time caused by limited operability and poor drilling riser and subsea hardware fatigue performance. Shallow water operations do not have the advantage of deep water drilling where the motions and loads imparted to the subsea blowout preventer (BOP) are relatively decoupled and damped out by hydrodynamic damping from the significant length of the water column. Thus, the vessel motions and wave hydrodynamic loads imparted on the riser are transferred to the wellhead and subsea hardware. In this paper the fatigue challenges encountered for drilling wells in 530 ft water depth from a sixth generation moored semi-submersible rig are explored. The fatigue loading is critical for the subsea tree connector which is characterized by a high stress amplification factor (SAF). Multiple riser space-out solutions were evaluated including fairings, helically-grooved buoyancy, joints with rope, and modifications to the telescopic joint each of which will be presented in the paper along with combination of different damping parameters to optimize the fatigue performance. The paper will present the subsea tree connector fatigue performance for different riser space-out options and make recommendations for future operations with similar conditions. Other challenges encountered in fatigue evaluation will be discussed. This will highlight the current assumptions and unknowns in data that can form the subject of evaluation for a future joint industry study.

The Challenge of Elastomer Seals for Blowout Preventer BOP and Wellhead/Christmas Trees under High Temperature

It is critically important for elastomer sealing components in blowout preventers (BOP) and wellheads to meet the pressure and temperature rating requirements under the newly released American Petroleum Institute (API) standards, API 16A (fourth edition) and API 6A (twenty-first edition) respectively. Extrusion resistance under high pressure and high temperature is one of the most critical challenge for the elastomer sealing components to meet the above API standards. This challenge is related to the basic properties of elastomer materials and mechanical design of the sealing components. This paper outlines how a simple and low-cost approach was developed to evaluate extrusion resistance of elastomer sealing components, and the correlation between critical tear pressure and extrusion gap of the two elastomers seals was evaluated using a power law equation. This correlation revealed that the above challenges of elastomer sealing components for BOPs and wellheads/Christmas trees is related to the weak strength of elastomers under high temperature and large clearances (extrusion gap) in current designs. New materials and/or new mechanical design to overcome such a challenge were also provided and discussed in this paper. The paper will help practicing engineers understand the challenge of material selection, mechanical design, and API testing as well as better understand the capability and limitation of sealing components for blowout preventors and wellhead applications under high pressure and/or high temperature (HPHT).

Lies, Damned Lies, and Simulation Results: How to Change the Conversation and Build a Thriving Simulation Ecosystem

Engineering simulation has become the pivotal tool for research and development in industries including offshore oil & gas, aerospace, automotive, mobile/off-highway, health care, and others. This case study will explore the financial and time-based savings achieved through detailed simulations and a system-based design approach in two hydraulic valve development projects. The applications in this scope include subsea blowout preventer and off-highway mobile equipment controls. Tools like 1D system simulation, computational fluid dynamics, and finite element analysis are widely accepted; verification and validation (V&V) of these models is imperative in building confidence in simulation. Some V&V reference standards have been developed by groups like ASME and API, but they do not encompass all aspects of simulation regularly utilized by the modern analyst. This places the onus for the creation of V&V guidelines onto individual analysts and their respective employers. Lack of detail in these guidelines can lead to flawed interpretations of results and a corresponding loss of trust in analytical methods. Interdisciplinary organizations can provide forums to help bridge these gaps and create more comprehensive V&V guidelines. Through a study of the development cycles of a subsea valve and an off-highway mobile valve, examples will be outlined which illustrate the benefit of extensive upfront simulation validated by physical testing. Simulation work serves as a cost avoidance measure against many cycles of building and testing prototypes beyond what is truly required in the early stages of design. Accurate simulation is a key component of successful product development, but another often neglected factor is the collaboration between subject matter experts from the component suppliers and the OEM or system integrator. High performance teams comprised of seasoned designers, analysts, and market experts can collaborate to create devices that excel when integrated into a final product. Component designers may wish to isolate the design problem to the component in question, but critical engineering detail will be missed by avoiding a system approach. Expanding the scope of the design analysis to include as much of the application as possible as well as utilizing V&V techniques (beyond minimum industry standards) is key to ensuring that laboratory test data is representative of how a product will perform in its intended application. As the industry continues to evolve, powerful digital twins of systems like blowout preventers can be used for OEM validation of new technology proposed for these systems. However, the fidelity of these digital twins is contingent upon the inputs from thoroughly validated analytical models of the components that comprise the system. By collaborating across the customer-supplier value chain and investing heavily in simulation, offshore manufacturers can strategically position themselves to win in times when both customer expectations and the costs of failure are at an all-time high.

Fracture Failure Analysis of the Blowout Preventer Ram in an Oilfield

This paper gives a thorough investigation on the fracture failure of the blowout preventer (BOP) ram. Through appearance inspection, magnetic powder inspection, physicochemical inspection, metallographic inspection and scanning electron microscope (SEM), the main fracture reason of the BOP ram is that there was some original cracks in the BOP ram before fracture, during the service process the bop ram is subjected to impact load, therefore brittle fracture occurs due to the high brittleness of the gate material (which is caused by large internal structure) and low anti-crack propagation ability. Key words: Blowout preventer (BOP) ram; Fatigue break; Brittle fracture; Failure analysis

Advanced Well Control Reduces Risk of a Blowout

There are still concerns about well control especially for operations in sensitive environments. Currently the final barrier while drilling oil and gas wells is a valve system (blowout preventer or BOP) located on top of wells. These valves can isolate wells by sealing around or shearing through obstructions in the well (e.g. drilling pipe and casing). If these valves fail or if some other barrier in a well fails, hydrocarbon loss to the environment is possible. Adding barriers capable of responding to a well control loss could alleviate these concerns. ExxonMobil is currently evaluating concepts to provide two additional methods to kill an out-of-control well. One utilizes rapid crosslinking polymers to form a polymer-plug seal inside a BOP after a failure. The other is to rapidly pump seawater into a well to produce back pressure that overpressures the entire well bore to keep hydrocarbons from escaping oil / gas bearing zones. Mixing dicyclopentadiene (DCPD) and other monomers with a ruthenium-based catalyst causes a rapid polymerization reaction that forms a high-strength, stable solid. These reactions can occur under extreme temperatures and pressures while withstanding significant contamination from other fluids and solids. The well-control concept is to rapidly pump the monomers and catalyst into a leaking BOP to form a polymer seal that prevents further flow. The seawater injection concept uses high-pressure and capacity pumps located on a surface vessel and a conduit from these pumps to a port on a BOP. If a blowout occurs, seawater at high rate is pumped in the BOP. If BOP seal failure is the reason for containment loss, then the seawater will overpressure the BOP and seawater will displace the hydrocarbons passing through the leak point. Seawater injection will also overpressure the entire wellbore to keep hydrocarbons from escaping anywhere in the well. For example, if a leak occurs deep in the well, seawater injection into the BOP will overpressure the entire well and the seawater will replace the hydrocarbon flowing through the leak point. We have conducted testing of the polymer plug concept at representative temperatures and pressures using a small-scale BOP. Polymer seals were formed when the scale BOP was flowing drilling mud, a crude-oil surrogate, and water. The seals held up to 5,000 psi pressure for almost 18 hours. We have completed modeling of the seawater injection concept to define pumping needs. This paper describes the current status of concept development.