This paper describes the new API guidelines being proposed to establish design methodology, material functional specifications, design validation requirements for equipment designed to operating above 15 000 psi (103.5 MPa) rated working pressure and/or 350°F (177°C) operating temperature through API 17 Technical Report TR8: High Pressure -High Temperature (HPHT) Design Guidelines. The proposed design guideline is intended to provide the wording and the reference information which can be incorporated into any of the subsea hardware specifications, standards and recommended practices within the suite of subsea API (SC 17) documents. Its intent is to be a reference cited in part or in total, by the various API subsea hardware documents, allowing them to expand their working pressure and temperature classifications without having to re-write the relevant sections into their governing documents. API 17TR8 contains detailed guidelines on new design methodology, material property requirements, design validation testing, and special requirements for seals and fasteners when considering the effects of HPHT wellbore fluids passing through subsea equipment.

Over the last several years StatoilHydro has established demanding ambitions with respect to increased oil recovery from our subsea fields as these fields mature and new prospects become scarcer and harder to access while market demand continues to rise. From the recent past, a gap (12% -14%) in recovery from our fixed platforms relative to the subsea fields has emerged, even though the quality of the reservoirs is basically the same. To a large extent this gap is related to the high cost in subsea operations in general and well operations in particular. Many operators claim their wells are designed as 'intervention free' using sophisticated well designs to avoid future well operations cost. Experience however shows that efficient (i.e. low cost) well intervention solutions are of the utmost importance for increased field recovery as well; and riserless light well intervention (RLWI) is one tool helping to close the recovery gap. RLWI well interventions are steadily gaining industry acceptance since its introduction 2003. This activity has significantly increased since 2005 in the North Sea, requiring at least two concurrent vessels for planned operations in 2008.RLWI operations are now common in shallow water up to 600 m (2000 ft). However, the current concept is not the ultimate technical solution worldwide, just the first step. Considerable efforts have to be made to improve the concept with respect to efficiency, weather sensitivity and last -but not least -deep water compatibility. We envisage 3000 m (10000 ft.) water depth is well within reach. Technical improvements on the first two fronts are being introduced, building on the campaign results from the pioneering vessels which first deployed RLWI technology. Most likely the 'step change' technical improvements will appear when going deep. The paper will discuss important elements in deepwater RLWI operations from:• operations and experience in 'shallow' waters • technology solutions required to perform operations efficiently in deep waters ExperienceThe number of workovers using RLWI has steadily doubled over the last three years, first to prove the concept's viability then, over the last two campaigns, evaluating operational and hardware performance. In 2006, eleven wells were accessed in five different fields in water depths ranging from 140-310 m (450-1000 ft.) over a 241 day campaign. In 2007, seventeen wells were accessed in eight different fields in water depths ranging from 190-390 m (600-1300 ft.) over a 335 day campaign. Average intervention time per well was nineteen days in 2006 and seventeen days in 2007. These average intervention times included transit time (mobilization and de-mobilization between wells, and crew changes) during periods of poor weather. Typical wireline workover operations during these campaigns included:• Running calipers and gauging tools • Running production logging tools including leak detection • Setting tubing plugs to isolate intervals with high water content • Added perforation in new production intervals • Install i...

W paper WM selmcd fa pmmmdon by the OTC Prcgrun Comminec following review of infornmtion conwwd in an &tract mbmmd by the mttbor(s) Contcnu of the pspcr, u presented, bw'e not been reviewed by the OITshore Technology Confcfmce md we subject 10 axmc!ion by the uhf,) The mated, M presented, & m neccss.n Iy mfl w my pm iii." of the OtTslwre Tcchno Iogy Ccmf.rcme or IUoflbn Pmmisicm 10 WY i$ rexmzed to an abstract of mw more than 103 wrcb Illu.tr.tIOns may MI bc mpud ti Aamct dmuid oman mnspmcw tcknowledsmcn: of whae md by whom Lhe paper wu Abstract This paper reviews the continuing development of gate valve and actuator technology for subsea completions extending into ultra deep water. l%e basic technical challenges inherent to subsea valve actuators are reviewed, along with the various factors which affect the design and performance of these devices in deepwater applications. The high external ambient pressures which occur in deep water, coupled witti high specific gravity hydraulic control fluids, are shown to have a significant impact on the performance of the actuators. This paper presents design & analysis methods and the verification test procedures which are required to develop and qualify new deep water actuator designs.Gate valve actuators of the type described in this paper are currently in use on subsea christmas trees on the world's deepest subsea wells offshore Brazil (water depths >3000 feet). New applications of the deepwater actuators are in process for upcoming Gulf of Mexico subsea production systems in water depths approaching 6000 feet. The actuator/valve development method described in this paper has been confirmed by performance verification testing of full scale valves& actuators using a hyperbaric chamber to simulate ultra deepwater operating conditions. Performance of the test valves & actuators correlated very well with analytical predictions. Test resuhs have confirmed that the new valve actuator designs will satisfy API 17D performance requirements for water depths up to 7500 feet, well in excess of the upcoming GOM application.

This paper presents a state-of-the art review of the design options for subsea flowlines and production equipment for high-pressure service considering the High Integrity Pressure Protection System (HIPPS). Industry is finding prospects requiring High Pressure High Temperature (HPHT) equipment as oil and gas development extend into deeper offshore reservoirs. To develop these fields as subsea tiebacks, the design of flowlines and risers for HPHT conditions often becomes technically challenging or cost prohibitive. One of the options is to use a HIPPS system to allow the use of a lower-pressure rated flowline compared to the wellhead and tree equipment. However, it may not be obvious whether HIPPS is cost-effective, practical or operationally acceptable. Design issues for evaluating HIPPS include: field architecture, offset distance, line size, materials, pressure rating of the system components, length and pressure rating of "fortified zones", type of control system, system reliability, dynamic pressure rise resulting from a blockage and installed cost. Another fundamental issue is "Why are land-based HIPPS systems widespread and generally accepted in the industry, but not used as yet subsea?" For selected field architectures, the impact of using HIPPS will be illustrated with respect to these design issues. These design case studies will provide guidelines as to which combination of architectures and design parameters will be most suitable for taking advantage of the HIPPS system capabilities. The paper will also summarize current industrydesign guidelines that apply to the design of HIPPS. Introduction High integrity pressure protection systems (HIPPS) are the evolution of mechanical and electronic safety devices used in the process industry to handle production or transportation upsets. Simply put, HIPPS is designed to protect low-rated equipment against overpressure or abject flow accompanying the upset condition by either isolating or diverting the upset away from the low-rated equipment. However, HIPPS is more commonly referred to as a "high integrity pipeline protection system", because many HIPPS design/cost studies are associated with field layout pipeline designs. There are two fundamental methods for maintaining a "design break" between the pressure requirement associated with conventional rated equipment and the pressure requirement for low-rated equipment:Maintain an effective barrier at the boundary between the two sections (high and low pressure rating) with a safety shut-off device, and/orProvide a relief safety system in the low-rated system to reduce or maintain the excess fluid flow and thereby limit the build up of pressure in that system 1 Deciding whether to use any safety system (or what type) depends on its overall cost and its reliability compared to a more conventional design. The key is "fool proof" reliability taken into account during risk analysis exercises. The barrier or relief system must be both highly effective and reliable and have a low enough failure frequency to represent an acceptable level of risk. Without these features, HIPPS will most assuredly not be recommended, regardless of cost, because of possible adverse consequences to HSE or damage repair.

A project has been progressing for better part of two years developing an all encompassing deepwater, large bore completion riser system for installation of vertical and horizontal wet Christmas trees. Although the higher pressure is a formidable exercise, weight and metal usage exercise, the unique and challenging aspect of the project has been overcoming all of the issues surrounding the high temperature aspects of the equipment. The design of the riser system's various pressure containment packages was influenced by:Using current technology status with respect to metals derating, thermal life cycle issues, and selection of nonmetallic materials for 350 degree F temperature rating.Determining the maintenance replacement frequency cumulative usage of lower temperature rated non-metallic materials used for short-term durations at elevated temperatures, based on thermal life cycle curves.Dealing with a patchwork of Industry specifications and recommended practices addressing various aspects of component design, raw material fabrication, assembly and test as technology catches up with requirements. The paper will address the design and project management cost issues, the level of understanding of HPHT issues using project "risk management techniques to balance current capital investment against future upgrades and the likelihood of these requirements occurring again from a market perspective. Introduction Wells drilled beyond 25000 feet TD will, by nature, require HPHT equipment. Many of the current deepwater to ultra deepwater plays in the Gulf of Mexico are demonstrating the need for HP systems and intervention equipment to support their installation and maintenance. HT applications are more sporadic and therefore less market driven. Nonetheless, either application demands a technically challenging and often equally costly system. The biggest problem is to technically balance three divergent parameters: size, materials, or new configurations.1 Ultra deepwater workover/completion riser systems also have to deal with weight and external stresses associated with deploying in water depths beyond 6000 feet and large throughbore sizes of five inches or better to satisfy the latest generation of subsea trees and their high flow rate capacities. Second, deeper and larger requirements pose higher demands on rig tensioning requirements and stress levels in the riser pipe and their connectors. Higher pipe and connector stress equates to a need higher strength materials or thicker walled designs. Both are challenging in that more exotic materials and or thicker wall designs create more complicated fabrication processes, especially if manufacturing processes have to work within the limited boundaries imposed by fatigue and stress corrosion cracking. Third, radical new approaches in process, procedure, or hardware configurations are counter to the efforts in reliability and standardization the Industry is pushing for. Riser System The workover completion riser system is a high-pressure monobore configuration with options for separate paths to circulate wellbore and completion fluids. The monobore riser configuration has been in use for the last five years working on both horizontal and vertical subsea tree installation and intervention.3 The system is made up of five distinct entities: the lower riser workover package (LWRP), the riser pipe conduits, the tensioning interface, the surface tree (or terminal head), and the control system that operates it.