Safety Valves Codes and Standards

Well completions for tension leg platforms require special consideration in key areas. Standard downhole equipment including subsurface safety valves can be used in a conventional manner from TLP's. Special designs, however, may be required for annular safety systems or sales risers.

New and extreme challenges, from engineering and operational standpoints, were faced during the preparation and execution of an exploration well in an HPHT environment. COVID-19 pandemic outbreak made it even more challenging leading to several issues in terms of material deliverability and personnel availability. The nature of the reservoir required hydraulic fracturing to be performed prior to test the explorative target. The entire fracturing treatment and well testing were performed through an instrumented well testing string which allowed to save rig time and, thus, costs. This paper goes through the selection of proper completion and hydraulic fracturing technologies to withstand the challenges that such environment poses to deliver the job safely and timely. The completion hardware selected to perform the job was a well test/frac string equipped with sensors, tester valve and circulating valve. A mechanical set down weight non-rotating packer isolated the reservoir from the annulus, a standard completion safety valve and a tubing hanger with X-Mas Tree completed the configuration of the DST string. Another important aspect was the need of heavy brine (i.e. bromide based) which exposed the equipment and material to aggressive environment. Hydraulic fracturing operations were carried out smoothly with the support of a dedicated frac vessel reaching up to 10,000 psi at wellhead and more than 12,000 psi at bottomhole. The total amount of proppant pumped into formation was one of the highest in the Operator experience and good results were achieved in unknown formations. The result of the stimulation job was a good values of proppant concentration in the fracture as long as a good frac width. During well testing operations high drawdown was reached without compromising the integrity of the string. This paper outlines and describes the completion and fracturing job engineering, preparation and execution phases including all the mitigation actions and lessons learned gathered during operations. Moreover, this experience showed how a resilient culture and an integrated approach between subsidiary operations and headquarter technical support, lead to successful operative results.

A case study was presented in the 1994 Abu Dhabi International Exhibition and Conference (ADIPEC, 94) which discussed the importance of investigating human factors in the design of a high integrity protection system (HIPS) to be installed on an offshore high pressure gas platform, (SPE reference ADSPE 80). This paper will follow up on the design changes, installation and operation of the HIPS with emphasis on practical implications as a result of improper integration of human factors in the system reliability and risk assessment studies. Introduction The importance of investigating human factors in the design and management of petrochemical plant has developed rapidly in the last ten years, Mainly following the implication of human error as a contributor to recent disasters in high technology/high risk industrial sites. Technology had made it easier to design more complex systems to improve efficiency, productivity and control of processes in the oil industry. However the safety and reliability of these systems are dependent on humans in varying complexity of organisational structures and in different environmental conditions. This implies that designers and managers must ensure that sufficient consideration is given to human factors at all stages of plant life and it is encouraging that such considerations are being legislated in many parts of the world. In a previous paper we demonstrated the technique and methodology for incorporating human factors in risk assessment (Fig. 1) and provided an examination of the deficiencies in the traditional approach to design and operation of relief protection in an offshore environment with emphasis on the need for designers, project managers and engineers to conduct a systematic risk assessment of identified hazards. The process system in the case study presented comprises installation of three satellite wellhead towers (Fig. 2) with three wellheads each producing high pressure sour gas routed to a nearby offshore treatment and export platforms. In this presentation, we concentrate on the sequence of events from design to full operation of these towers with respect to application of sound safety principles for protecting against overpressurisation. The hydrocarbons produced are very sour and extremely toxic to humans. Gas flows from each well through a choke valve into a common production header for the three wells (with by-passes to either the test separator or to the pig launcher) and then into subsea lines to collection and production platform (Fig. 3). The choke valve is set at the percentage required to control flow and pressure. The shut in pressure of the producing wells is up to 5700 psig, whilst the piping downstream of the choke valves are designed at a much lower pressure i.e production header and downstream is up to 900 psig (ANSI-900) and test header up to 2500 psig (ANSI-2500). This piping and equipment need to be protected against possible over pressurisation. This is to be achieved by a combination of pressure control, a high integrity shutdown system and instrumentation. The decision to install a modern HIPS instead of a standard pressure safety valve (PSV) was taken during the Coarse Hazop by the Project team on the basis of the following options:all pipelines and associated equipment to be designed for full close in pressure 5700 PSI. P. 317