In Systems Engineering CTR 6901, DeepStar developed a process to identify technologies that have good economic impact on 3 typical deepwater tie-back marginal reservoirs. This is accomplished with a life-cycle economic analysis which establishes benchmark economics using standard technologies. New technologies were then incorporated into these scenarios and the economic impact was compared to the benchmark field development results. Use of this process provides insights, for the conditions studied, into new technologies' ability to have commercial impact on deepwater marginal fields. This paper provides an overview of this work and findings. Introduction: DeepStar System Engineering CTR 6901 evaluated the life cycle economic aspects of three long offset marginal tie-back fields identified as Cottontail, Coyote and Hyena (all are scavenger names). The characteristics of these fields are given in Table 1. The evaluation was performed in two parts. The first part applied currently available technology to these 3 fields to establish the current industry capability and related commercial performance. Four of these "base cases" were established for each of the three reservoirs. The development scenario alternatives used in this evaluation were:Subsea tiebacks with heated flowlinesVertical well access (Dry Tree in 5,000 fsw)In-field processing system on structure.Subsea Processing System. Graphically, these 12 scenarios are illustrated in Figure 1. Each scenario was evaluated using a typical project economics approach which accounts for all CAPEX, OPEX, production profile, etc over the life of the field. An Excel spreadsheet developed by AkerKvaerner was used for this purpose to make all data visible and easy to understand. This is an important feature since this work only has value to a large and diverse group if the details can be understood, challenged & ultimately believed. This evaluation identified the "benchmark" scenario for each field with the most avorable economics from the Operator's perspective. These were:Cottontail - Case 1: A standard 4-well tie-back using an electrically heated flowline for flow assurance in 5,000 fsw with a 30 mile offset to the Host facility.Coyote - Case 14: This 10,000 fsw 50 mile offset field performed best with a 3-phase subsea processing system.Hyena - Case 6: For this 5,000 fsw West of Africa Field, a satellite structure with dry tree production wells gave the best economic results. This best economic scenario for each field became the "benchmark" example against which all other development alternatives and technologies may be compared. The second part of CTR 6901 evaluated the 10 selected technologies listed in Table 2 as if they were commercially mature and technically viable as projected by their sponsors. Each emerging technology was individually evaluated in the respective benchmark development scenario (or other scenario where appropriate) and the economic results were evaluated. None of these technologies generated an economic step change in the field life cycle economics for the tie-back field conditions evaluated. The technologies yielding (small) positive economics were consolidated together to determine their collective impact on these marginal tie-back field economics. The result identified a combination of emerging technologies, which together, have potential to improve the field's life-cycle economics.
Summary The offshore industry has shown significant interest in deep-water production in the Gulf of Mexico, as evidenced by the large number of deepwater leases. This paper addresses an innovative method to control cost of field-development wells on deepwater leases. Drilling tender rigs have been economically attractive in shallow water depths. The limitations experienced by conventional tenders in deep water with regard to mooring and motions in a seaway can be overcome by use of a semisubmersible tender. Introduction Significant oil-company interest has been demonstrated in deepwater acreage in the Gulf of Mexico, as indicated by the acreage currently under lease (Table 1). Active exploration programs that use semisubmersibles and drillships are proving the potential of these areas, and development plans for deepwater production are being formulated. In contrast to exploration drilling, development drilling may be performed from either floating mobile units or fixed structures of various types. Deepwater development concepts can be separated into two groups: those involving subsea wellhead completions and those involving surface completions. Examples of several systems of both types are shown in Figs. 1A and 1B. Note that each of these systems is represented by a state-of-the-art, proven working example. proven working example. Deepwater development inherently involves high costs, both for initial installations and for well maintenance. Reduction of these costs can be achieved with operationally efficient equipment; wells that are accessible and easy to work over; smaller, lower-cost structures; minimal and lightweight equipment on the structure; and facilities that may be relocated and reused to minimize capital investment in a given field. An example that incorporates these parameters is the wellhead tension leg platform (TLP). This wellhead protector is small and supports little more than the wellheads protector is small and supports little more than the wellheads and a small workover unit. The wells would be predrilled with a mobile drilling unit. The required process equipment would be located on a nearby floating production and storage vessel (FPSV). It is even feasible to use the wellhead TLP as a permanent mooring system for the FPSV. This, in effect, is a clever combination of platform and permanent mooring system for very deep water. platform and permanent mooring system for very deep water. When well-drilling, completion, and workover operations from a small TLP are considered, the operational criteria suggest that a tender for drilling operations can be used for exactly the same space and weight benefits that were achieved by removing the process equipment.
This paper presents important findings while executing a detailed qualified design of a large (3,000 + barrel), subsea (to depths of 10,000 fsw) production chemical storage and injection system. The design drivers for the system were safety first, extensive utilization of existing commercially available equipment / tools / methods, and a re-usable shuttle system that allows for delivery of production chemicals as a service versus the current approach where an operator / owner makes a capital investment. The system is designed to be compatible with existing production chemical formulations and features multiple barrier design between the chemicals and the environment. Placement of the storage and injection system directly on the seafloor in close proximity to the point of need eliminates expensive chemical umbilicals, removes significant topside chemical storage and injection kit weight and space requirements at host facility and isolates hazardous chemicals from platform workers. The re-deployable shuttle economically allows inspection, repair and maintenance to take place quayside with the ability to upgrade equipment as technology progresses and / or quickly and cost effectively adjust to ever-changing field requirements. Subsea wells have been proliferating over the last decade with ever-longer tie-backs to enable commercial recovery of small resource pools that are unable to support a traditional floating system development. Virtually all wells, especially subsea, require various volumes and types of production chemistries during their operational life. For subsea wells, the incumbent technology is chemistry delivery via umbilicals. In rare occasions, small volumes are sometimes delivered via single trip, disposable containers, principally during intervention activities. As tie-back distances have increased, so have the technical challenges with their attendant mushrooming costs. These challenges include the needs for; special corrosion resistant materials, resistance to high pressures differentials, material flexibility and ‘crimp – resistance’, and long term reliability. Additionally, some of these chemicals are high viscosity and as the tie-back distances increase, so does the pressure drop of the flowing fluids. In some cases, the risks of plugging and the magnitude of the delta-pressure drop in ½? – ¾? chemical tubing within the typical umbilical can preclude tie-backs of long offsets from the host / hub facility. The subject system overcomes many of these challenges by locating a large, pressure compensated storage and injection facility directly on the seafloor in close proximity to the point of need, thus qualifying it as enabling technology for extra-long tie-backs and enhancing technology for short tie-backs, de-bottlenecking, or early production system usage.
This paper describes the process used to determine, evaluate and rank technology gaps and possible enhancers in subsea and floating systems between 6,000 to 10,000 ft water depths. A consistent and logical process has been developed using modified Functional Analysis System Techniques (FAST) to identify the functional relationships of deepwater development systems and their components. Base case field development scenarios were used to "test" the FAST map information to identify any enabling technology gaps. Further, life-cycle field economics were prepared to quantify enhancing technology gaps. Each gap is then "valued" by considering development costs, maturity of the technology, risks, number of applications and other selected factors from which a ranking resulted. This allows a comparison between the alternate R&D opportunities. This paper identifies the system analysis philosophy and evaluation techniques used by DeepStar in the System Engineering Initiative. Goals and Objectives The primary systems engineering objective was to identify key deepwater research and technology development needs on the basis of an overall system from reservoir to landfall. A secondary objective was to prioritize these needs so DeepStar funds can be directed to resolving the most pressing problems in a cost-effective manner. The immediate work goals were to:Identify the state-of-the-art technology for Ultra deepwater productionIdentify gaps to using this technology in up to 10,000 feet water depthsIdentify high-impact enhancing opportunitiesValue and rank these gaps and enhancing opportunities Valuing Technology The value of new technology cannot be effectively assessed in isolation; therefore, DeepStar took a system economic approach when considering alternative technologies. As part of any system, the new technology must be benchmarked relative to the importance and impact that it has on the system which uses it. This requires the technology's economic value to be evaluated over the entire life-cycle of the system in which it is used. A system was defined as a group of interacting elements (or technologies) having a functional relationship that, when grouped together provide some process or service. In the DeepStar work, the required technologies for each system were identified for classification or analysis purposes. Several technologies are often linked to accomplish a specific system purpose. It became obvious that removing one technology from a required system chain could detrimentally affect the function of the entire system. This highlights the fact that any system performance is only as strong as its weakest technology element. Numerous technology alternatives may exist which are capable of fulfilling a system's functional demands; therefore, a systematic approach had to be used to map the technology alternatives and their functional relationships. System Engineering Approach A two phase approach was used in the DeepStar work. The first phase looked at extended-reach subsea systems by building upon previous subsea studies and Industry experience. The second phase evaluated deepwater host structures including:floating production systems (FPS),floating production and offloading (FPSO) systems,Spars, and?TLP's.
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