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Abstract Oil and gas development is fraught with technical uncertainty. As hard as we try, subsurface anomalies continue to surprise the most gifted petroleum engineers, and as a result, we seek technology that can help manage reservoir uncertainty. A classic success story is 3D seismic technology, which has proven to enhance our reservoir knowledge and reduce capital investment uncertainty. Intelligent Well Technology is much the same, in that it reduces the negative effects of reservoir uncertainty on expected future production and cash flow. Intelligent Well technology can provide an operator continuous/permanent down-hole monitoring coupled with the ability to reconfigure the well completion upon demand (through remotely operated flow control) without additional investment in response to reservoir knowledge gained over time. This ability creates value through reduced well intervention costs, reduced operating costs (i.e. through reduced surface facility requirements), reduced capital expenditures through innovative Intelligent Well Field Development Programs, increased production through commingling and increased recovery through enhanced reservoir surveillance and management. Moreover, the combined capabilities of real-time monitoring and flow control allow an operator the flexibility to actively respond to unforeseen reservoir driven events (i.e. early gas/water breakthrough or coning), effectively reducing future cash flow uncertainty. Traditional discounted cash flow (DCF) models do not adequately value the benefits of operational flexibility, and thus often underestimate the value of intelligent well technology (i.e. the benefits of real-time monitoring and control). Real Option analysis has been shown to effectively quantify this value in cases regarding portfolio analysis and corporate capital management. In this paper, we describe a method to apply Real Options theory to quantify the value of Intelligent Well applications, including the value of reducing project volatility and risk. We derive the mathematics to quantify Intelligent Well value for four specific case scenarios and outline the methodology to manage more complex cases. Finally, we describe how the mathematical model can be incorporated into a larger workflow process to assess entire asset portfolios for potential Intelligent Well applications. Introduction The nature of reservoir uncertainty has a much larger effect on our business than we normally care to admit. Although companies generally aspire to achieve returns greater than 15, 18 or 20% (depending on their WACC) and only approve projects that meet these hurdle rates, the average return on net assets for our industry over the last ten years was found to be a disappointing 7%! Although many factors can drive these results, more often than not oil field economics are driven by oil price, project cost, and reservoir uncertainty. The last decade has seen major successes in cost management, to the extent where today, additional significant cost savings are nearly impossible to find. As we have no control of oil price, we must now focus our efforts on managing the deleterious effects of reservoir uncertainty if we are to meet shareholder expectations in the next decade. Reservoir uncertainty is often managed statistically, through large drilling programs, where poor individual well results are offset by better than expected wells. In his award winning SPE paper reviewing the results of over 1000 horizontal wells, Beliveau shows that it is unreasonable to expect the result of any single well to approach an expected (mean) production rate and the most likely result of any single trial will in fact be less than expected. He also notes that it usually takes at least six trials to get a reasonable idea of a drilling program's expected outcome and despite our advanced attempts to optimize individual outcomes, the results inevitably become log normally distributed.
Abstract Drilling exploration wells in deepwater or other frontier environments is an inherently expensive process. The effects of non-productive time caused by bad or less informed decisions are magnified in such costly and difficult environments. A major operator is using the communications, presentation software, and other real-time technologies to build a more effective collaborative team to support its deepwater exploration program in the Gulf of Mexico. The technology to remotely monitor drilling operations has long existed. From its inception, the goal of this Real-Time Operations Center (RTOC) has been to move beyond mere monitoring to participation in the drilling operation. A team of drilling experts, with an average experience level of 20+ years, was assembled. They were given the tools and facility to have 24/7 contact and visibility with all drilling operations. Additionally, the prospect teams associated with each project began holding their meetings in the Real-Time Operations Center, involving both the rig (via video conferencing) and the expert team in ongoing planning and operational decisions. The shift from the old paradigm of a reactive team gathering to sort out existing problems, to a proactive team focusing on preventing problems has had a major impact on drilling operations. This paper will describe the technology, people, and processes employed to build this Real-Time Operations Center. The layout of the control room and the integration of the data collection and control/decision making processes will be discussed. The skills required and work processes designed to avoid a feared โbig brotherโ syndrome are described. These steps were taken to overcome people and process issues that can defeat such an initiative. Communication and decision making procedures were outlined, designed, and implemented to facilitate success. Success and the documented value of this project are described. Introduction Highly experienced and knowledgeable people have always been a key ingredient of successful drilling operations. With the advent of widespread real-time technologies and the drastic cost reductions seen in deploying these technologies, Shell Exploration and Production Company (SEPCo) initiated this project with the goal of further leveraging the available expertise. Some basic infrastructure required was already in place. The remote offshore locations are connected to the operator network via available microwave or satellite links. The drilling and other relevant data is being collected, transmitted, replicated, and managed using Halliburton Sperry-Sun's dynamic data management service. The major new steps required involved 1) setting up a facility in the operator's office, 2) assembling the proper team to staff it, and 3) designing and implementing work processes that allowed this to be a constructive and valuable effort. The implementation team determined that the best location for the Real-Time Operations Center would be at SEPCo's main office in New Orleans, on the same floor as the drilling operations and planning team. Although this created space constraints for building the facility it was felt that the advantages of having immediate access to the proper people required whenever collaborative decision making needed to take place far outweighed any other considerations. The team members, whose input to the processes are only required on an as needed basis could comfortably work on their usual duties and rapidly assemble to the RTOC when required.
Abstract Foinaven is the first field to be developed in the West of Shetland province. The paper describes how deep set plugs were successfully deployed, tested and retrieved from extended reach wells using coiled tubing techniques. A sub-sea development, in 500 metres of water, Foinaven will have 14 production wells. Most, if not all of these wells will have extended reach horizontal sections, with tangent angles of over 80 degrees. The wells are completed, in some cases tested, and left suspected with hydrocarbons to surface and plugged accordingly. The sub-sea Christmas trees are installed when the weather conditions are favourable. Results, Observations and Conclusions. The first 4 well completions are described in the paper. Severe weather conditions combined with the challenges of working from a semi-submersible drilling rig in high angle wells caused several problems. These included:extreme coiled tubing weight indicator fluctuations. control of impact hammer during jarring operations. lack of confidence in shear values of setting pins while in the horizontal sections, and resulting effects on deep set plug integrity. impact and consequences of debris accumulation within the completion tubing and the effect on plug setting and retrieval. The paper describes how these difficulties have been resolved or minimised. Applications. The paper will be applicable to any coiled tubing operations that involve either sub-sea completions or extended reach wells. Technical Contributions.The Foinaven producer completion is described with suspension philosophy. The plug design and applications are described, including the onshore testing requirements. Accelerated age testing of elastomeric barriers is described. The coiled tubing equipment rig up and operational procedures are described. Background The Foinaven oilfield is located 180 km West of Shetland in the Atlantic Ocean. Discovered in 1992 by BP Exploration the field is located across Block Nos 204/19 and 204/24a in 500 metres water depth with a shallow reservoir of Palaeocene sands separated by shales at 2,000-3,000 metres TVD. A phased sub-sea development was sanctioned in late 1994 and is the first of BP's Atlantic Frontier projects to be developed on a "fast track" basis. There is no present infrastructure in the area to support oilfield developments and the area is exposed to challenging weather conditions and unpredictable current regimes. The sub-sea architecture is designed around 2 drill centres with a manifold on each feeding to a floating production, storage and off-loading vessel (FPSO) designed for 85,000 barrels per day annual average oil production, with full water injection, gas compression and produced water handling facilities. A total of 22 reservoir penetrations are planned for the development of which 14 are oil producers, 7 water injectors and 1 gas injector disposal well. Many of these wells are at deviations greater than 80 degrees, which require coiled tubing for deep well plugging operations. Foinaven represents a very high cost operating environment during the well installation phase, owing to the requirement for fourth generation semi-submersible drilling units for drilling and completion operations. P. 345
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/24a > Foinaven Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/19 > Foinaven Field (0.99)