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This paper describes the design of one of the largest semi-submersible drilling vessels ever constructed. The arrangement and operating features of the drilling machinery and auxiliary underwater drilling equipment are also reviewed. The SEDCO 135-F is presently under construction at Victoria Machinery Depot in Victoria, B.C. Sister vessels have been completed and are in operation in the Gulf of Mexico, off Borneo, in the North Sea and off Nigeria.
The physical layout of the vessel is presented in terms of its unusual shape, size and arrangement of equipment and accommodations. The diesel-electric power plant provides D.C. power for the heavy machinery and A.C. power for miscellaneous ship service. Electrically driven deep-well pumps are used to deballast the vessel and to move water and fuel from the lower compartments to the operating deck level. Other mechanical features include three large cranes, pneumatic storage tanks and other special equipment required to handle the underwater drilling equipment.
Due to the severe oceanographic conditions off the west coast of Canada, a special mooring system was designed to secure the rig under adverse conditions. The design criteria, hardware and operation of this system are reviewed.
The vessel will be equipped with specialized underwater equipment to enable it to drill exploratory wells in water depths of up to 800 feet. The hydraulically operated well control equipment is situated on the ocean floor during normal operations. This "diverless" equipment is described, along with its handling and operating procedures.
Abstract A tremendous amount of effort has been placed on subsea cap and containment in order to demonstrate the exploration and production industry's response to a subsea well control event. This paper will focus on the methods and processes planned to contain a subsea blow out beneath a Tension Leg Platform (TLP) in deepwater Gulf of Mexico. Response to a well control event of this type is divided into 3 major categories: 1) TLP Health and Stability Monitoring - Understanding the structure stability is key in planning the response and determining the time allowed to deploy containment assets, 2) Debris Clearing-a path must be cleared into the well pattern horizontally and vertically for the capping stack to be deployed and 3) Stack Deployment - with the TLP still floating above the well pattern the stack must be deployed laterally under the facility and onto the well. Several challenges were encountered during the design and approval of this containment method, leading to the development of alternative capping strategies, purpose built capping stacks, installation of permanent monitoring / response equipment and use of Delmar's Heave Compensated Landing System (HCLS) to accomplish these critical subsea tasks.
This paper describes the design considerations for selecting a blowout preventer control system and associated handling techniques required for drilling in 1,000 ft or more of water from a semi-submersible drilling vessel. Design, manufacture, fabrication and assembly testing have been completed. This system is described and a summary of test information is included. The control system is entirely hydraulic using either hose or remote pilot operated circuits, depending on response time required for each control. A steel wire-reinforced hose bundle was designed and built in one continuous length to allow operation without extra support or guidelines. Handling techniques have been developed which should allow the control equipment to be run and retrieved without pulling the marine conductor. A unique unitized triple ram blowout preventer unit was designed and built so that the over-all height of the drilling control wellhead could be reduced to allow it to be used with existing vessels. Other components such as the control panel, hose reel, kill and choke line assembles and underwater hydraulic connectors are discussed.
The problem was to secure a blowout preventer system capable of drilling in all water depths up to 1,000 ft or more. Previously used control systems were reviewed to determine what blowout preventer experience was directly applicable and what modifications or new developments would be required. In addition, this study took into account the sea conditions existing along the West Coast where this system will be tested. Maximum storm conditions in this area include wave heights exceeding 40 ft, current in excess of 3 ft/sec and winds in the range of 100 mph. Continuous operation under these conditions is not a requirement, but the equipment selected must survive the wave forces and rig motion which may occur during these storms. As explained in the report, the primary control linkage between the blowout preventer stack and the vessel is to be attached to the marine conductor. Successful operation of the marine conductor is assumed during the discussion of this primary control linkage. This report reflects the effects of sea environment on the controls, reviews the developments required and describes the final system which is now awaiting drilling tests. This review places many of the significant design factors for a subsea blowout preventer system and associated operating techniques in one place. There may be disagreement with the equipment and techniques selected, but the effect of the severe environment (depth and sea conditions) on the design should be appreciated. Hopefully, additional design criteria concerning the vitally important blowout preventer operation will be presented by others as it is revealed both by experience and study. Analytical solutions for design problems were used several places. Some of these data are to display the order of magnitude to be expected rather than to be used for detailed design. In some cases data are restricted to a particular item, good only for that item but furnishing characteristics which may be expected from similar items. Many times, however, simple tests provided adequate design information with much less effort. For instance, full scale tests of the control circuits were used to evaluate the feasibility of remote, pilot operated hydraulic controls. Design data for the control hose bundle were obtained by subjecting a full-sized prototype bundle to maximum forces calculated to exist during actual operation. Finally, full scale land assembly tests of the equipment were accomplished to further check handling and operational characteristics.
The equipment to be used in this blowout preventer system will be identified in ascending order, from the sub sea wellhead to the control equipment located on the drilling vessel. A symmetrical four line system will be used to guide the blowout preventer stack and other drilling equipment to the wellhead. One of the basic design criteria was that the control system should be in place and fully tested on the spider beams of the vessel before the stack was lowered into position. The blowout preventer stack will normally be lowered and retrieved while attached to the marine conductor.
The Modular Blowout Preventer (BOP) stack integrates, in a compact way, the main components of an underwater BOP assembly. In this approach the annular BOP, the ram BOP's and the wellhead connector are locked together using four hydraulically pretensioned stud bolts that extend the pretensioned stud bolts that extend the full height of the stack, outboard of the BOP bodies.
The development of modern, large bore, high pressure control equipment has brought with it greater efficiency for the marine drilling industry. But, these larger assemblies are also taller in their conventional form. Eliminating the individual connections between the stack components in the modular concept has resulted in a substantial savings in overall height. This compact BOP architecture is possible because of side ram exit allowing possible because of side ram exit allowing easy packer change in tight spaces. Also, by using four large bolts to preload the entire BOP and connector assembly, the ability of the modular stack structure to carry high bending and pressure induced loads has been greatly enhanced, (also confirmed in a finite element analysis of the complete assembly).
Four large stud bolts extended through two circular termination plates located on top around the annular BOP and the wellhead connector below. These plates or reaction rings, transmit the bolts loads that are developed during a bolt tensioning process, compressively preloading all stack process, compressively preloading all stack components. Metal-to-metal sealing between the stack components is accomplished at this time as well. All four studs are simultaneously preloaded during initial assembly using detachable hydraulic tensioners. The net result is a rigid and compact stack assembly that will safely handle large bending moments and pressure applied loads. pressure applied loads
The trend in recent years to 18-3/4" - 15,000 psi drilling systems, has produced for the industry greater efficiency and improved safety. The modern high pressure blowout control equipment required for such drilling has now almost completely displaced the older two stack systems. These large preventer and collet connector assemblies are typically taller than the older equipment they replace. (See Figure 1)
Also with the continuing trend to deeper water, the riser applied stack loads are higher than those experienced in shallower water drilling. Not only are these risers applied loads that are transmitted into the stack structure larger, but the corresponding bending moments at the wellhead are higher as well, because of the increased distance between the flex joint and the wellhead connector. Therefore, for new rig construction as well as for rig upgrades, especially for deep water drilling, short, stout BOP assemblies are desirable.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 119762, "Pull Your BOP Stack - Or Not? A Systematic Method to Making This Multimillion- Dollar Decision," by Jeff Sattler, SPE, WEST Engineering Services, prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed. Pulling the blowout-preventer (BOP) stack, particularly in deep water, is costly. While in most cases this action is proper, circumstances arise when the stack pull could be avoided. Case studies are presented in which planned stack pulls were circumvented or could have been. A systematic protocol can be developed before starting a well to define the decision-making process for stack pulls. Introduction Current deepwater-rig downtime costs approach USD 1,000,000/D. Pulling a BOP stack, particularly in deep water, is financially significant. This action is necessary most of the time. However, on occasions when the stack pull could be avoided, all parties to this action rightfully question how to take advantage of the unfortunate learning situation. Avoidable stack pulls occur for a variety of reasons, including: Inadequate information about the situation or equipment Inadequate staff training Unclear understanding of regulatory requirements Unclear understanding of company requirements Lack of access to experts who could assist in the decision The full-length paper details a systematic protocol to use before starting a well or during the drilling, if necessary, to help define the decision-making process for stack pulls for a specific program. Once a problem develops, the root cause should be identified, if possible, and necessary steps taken to analyze the situation and decide if drilling can continue safely. Often, this part of the process requires the advice and experience of one or more experienced drilling experts from within or outside the parties directly involved in the drilling operation. Predrilling Planning To help ensure a good decision when an abnormal BOP event occurs, preparations should be made before drilling starts. While several items presented here require time to investigate or review, often this process is not engaged because much of the information is considered to be intuitive. However, after drilling begins and because time is expensive (up to USD 700/min or more), the time required to analyze a situation fully is sometimes not allocated. Predrilling planning, as shown in Fig. 1 of the full-length paper, should include the following items. Assess Staff Training. Review staff experience and training to determine if additional training before drilling could reduce the risk of downtime. For example, does the subsea engineer need to be educated on the functionality of a revised circuit or control component? Would the subsea engineer benefit from a refresher on the latest variable-bore-ram capabilities and limitations?