Offshore field development includes not only planning for appropriate well completion designs but also implementation in such a manner that production and economic goals for all stakeholders are realized. Consideration must also be given to operational support functions so that their administration will meet the project needs without compromising environmental, regulatory or safety standards. Often, a multidiscipline team approach offers the best method for developing the solutions needed to accomplish all the objectives. In this paper, Hibernia Management's approach to well development, completion and servicing strategies are discussed. Initial completion strategies were required to meet the designated design criteria of maximum well deliverability, minimal well maintenance, well servicing costs, and finally, minimal overall field-life-cycle costs. To comply with these stringent requirements as well as future needs, the downhole configuration would have to facilitate future non-rig workovers, recompletions or redrills, and have the flexibility to allow incorporation of future technological advances or changes in reservoir management. In reviewing all options, minimizing overall field-lifecycle costs and the number of potential workovers were to be given primary consideration. Also of significant importance was the need to provide a zonal recompletion method as it was felt that the need for selective isolation of different zones would be needed to maximize recovery throughout the life of the wells. Completion strategies, the completion configuration, pre-installation shop tests, personnel training, completion servicing considerations and other challenges such as a "green field site" and rig requirements were reviewed; from these analyses, operational strategies were developed. The initial completion installations were successful. The first two wells flowed approximately 40,000 BOPD and are Canada's highest producing wells recorded to date! Introduction The Hibernia Field is located in the North Atlantic Ocean, approximately 315 km east/southeast of St. John's Newfoundland in approximately 80 meters of water. It is estimated to contain 3 billion barrels of crude oil, of which 615 million barrels are expected to be recovered. Average daily production from the gravity-based platform is expected to plateau at 135,000 BOPD, and field life is anticipated to exceed 20 years from the initial production start up date- November 17, 1997. Fig. 1 is a map of the Hibernia field location and Fig. 2 is a photograph of the Hibernia Platform.. The majority of reserves within the Hibernia field are found in two principal formations: the Hibernia sandstone at approximately 3700 meters subsea, and the Avalon sandstone at approximately 2400 meters subsea. The Hibernia sands will be developed first since they are of higher reservoir quality. Fifty five completions are planned. Twenty five are scheduled for the Avalon over field life. The majority of the wells will be drilled and completed during the initial years of field development with 64 wells targeted for completion by 2003. Due to the project scope, this paper will focus its discussion on the hardware for the completion configurations and how completion equipment was selected by the multidisciplined team1.2.3 to address project strategies. While the authors realize that drilling and completion fluids and perforating are integral parts of the completion and provide major contributions to its success, these topics are outside the scope of this paper.
In the past, serial drilling operations have been employed for the conventional well-architecture construction process. In this paper, new technological advancements from initial design planning to execution processes will be discussed. These advancements produce a "step-change" well architecture with a uniform well diameter and fullbore production delivery conduit called a monowell. From the well-construction processes to the "end" product, efficiency is driven in the technologies and processes described. Technical improvements in mechanical and chemical solutions can help achieve a well architecture with a uniform diameter in reduced serial operations. Technological advancements in the areas of composite technology and real-time downhole monitoring can enhance deployment efficiency compared to conventional methods. The efficiency processes yield a well architecture with more efficient reservoir penetration and oil-production delivery by:Reducing formation/reservoir evaluation time and well placement through better methodsIncreasing penetration rateReducing the volume of drill cuttings and the oil content contained on the cuttingsReducing fluid requirements (i.e. drilling fluids and cements)Reducing casing size and the number of casing strings requiredReducing overall rig timeReducing overall flat timeImproving well productivityReducing required horsepower and rig size The unique design and planning features of the monowell are discussed, including reservoir focus, geomechanics, and design requirements of drilling systems, formation evaluation equipment, fluid systems, and wellbore hardware. Multiple "uniform diameter" well-construction execution methods, including multiple deployment methods, are discussed. Together, the well-architecture change and execution-process changes result in a monowell with improved well construction design, execution, and production efficiencies. The monowell provides a significant industry step change in reducing cost per barrel of oil equivalent through improved efficiencies through a multitude of technologies. Factors to Consider during the Monowell Well-Construction Process A higher level of engineering and technological precision is needed to deliver the monowell compared to traditional well-construction processes. When a monowell is drilled, increased precision is required in the following areas: Upper BoreholeClear understanding of the formations to be drilled and being drilledBorehole stabilityDrilling hydraulicsEffective management of equivalent circulating density (ECD)Borehole qualityMethod of strengthening the borehole (borehole management)Well-life integrityReliability and run life of the bottomhole assembly (BHA) componentsLonger cementing and casing execution intervalsBorehole structural support Reservoir SectionCompletion, beginning with drilling of the reservoir barrierBorehole qualityBorehole stability across the reservoirReservoir evaluationReservoir productivityFormation damage minimization
SPE Members Abstract Nine wells were cored in Alaska's North Slope Point McIntyre field to provide engineering and geological data for oil reserve estimates. The goals for this coring operation were:provide high quality permeability, porosity, and water saturation core data using mineral oil base mud, andachieve 100% core recovery. Low invasion coring methods were used. Coring, core handling procedures, a new core bit, a new mineral oil base coring mud, and a new chemical tracer for the mud filtrate were developed for the Point McIntyre operation. This paper describes the bit development, coring, and handling procedures. The mud and tracer developments are documented in companion paper, SPE 26326. Point McIntyre's reservoir is lithologically complex, consisting of high permeability consolidated quartzose sandstone, low permeability highly cemented lithic sandstone, occasional lithic conglomerate, and occasional poorly consolidated quartzose sandstone. Existing core bits were not optimal for low invasion coring at Point McIntyre. The hard rock low invasion bit developed for the Point McIntyre project has smaller, more numerous cutters to increase bit stability and eliminate the tendency to cut undergage cores. Coring rates using the new bit were increased in the harder rocks. This core bit achieved low mud filtrate invasion in the low as well as the better quality sands. Bits and core barrel lengths were selected to maximize the core recovery and minimize rig time. Cutting of core plugs occurred immediately upon arrival in Anchorage. The goal was to keep elapsed time as short as possible to minimize tracer diffusion in the core. In the first two wells, core plugs were cut and trimmed both at the well site and in Anchorage to evaluate the time dependence of tracer distribution in the core and effectiveness of preservation methods. Time dependent effects of water saturation and mud filtrate distribution were not observed. Core plugging was moved to Anchorage for the remainder of the project. The coring methods used at Point McIntyre provided 99.6% recovery for 3,068 feet cored with less than 2% of the cored interval having significant mud filtrate invasion in 10 md to 2,000 md pay zone intervals. Technology development for this project was accomplished rapidly and was successful. The technology applied here produced high quality data. This enabled the coring program to be reduced with substantial cost savings. Other cost savings were obtained from high quality operational planning. Introduction The field was discovered in 1988. In January 1992, the field Owners decided on a 13 well program featuring mineral oil base coring fluid to determine hydrocarbon reserve ownership (equity) prior to forming a Point McIntyre participating area. Data acquired was porosity, air permeability, water saturation, structural and geological data in the Kuparuk sandstone pay zone lying between the Kalubik/HRZ and Miluveach shales. The well locations were selected on the basis of obtaining data for the entire areal and vertical extent of the reservoir. Due to the critical nature of the data, certain key operational procedures were followed:well bottom hole locations were picked from seismic and offset well correlation's,wells were directionally drilled in a S-shaped pattern for coring,Kuparuk formation picks were made from MWD and mud logging information,drilling of the upper hole was done by water base drilling mud while coring of the Kuparuk formation was done by a mineral oil based coring mud, andlogging confirmed the coring data. P. 393^
Offshore field development includes not only planning for appropriate well completion designs but also implementing in such a manner that production and economic goals for all stakeholders are realized. Consideration must also be given to operational support functions so that their administration will meet the project needs without compromising environmental, regulatory or safety standards. Often, a multidiscipline team approach offers the best method for developing the solutions needed to accomplish all the objectives. In this paper, Hibernia Management's approach to well development, completion and servicing strategies are discussed. Initial completion strategies were required to meet the designated design criteria of maximum well deliverability, minimal well maintenance, well servicing costs, and finally, minimal overall field-life-cycle costs. To comply with these stringent requirements as well as future needs, the downhole configuration would have to facilitate future non-rig workovers, recompletions or redrills, and have the flexibility to allow incorporation of future technological advances or changes in reservoir management. In reviewing all options, minimizing overall field-life-cycle costs and the number of potential workovers were to be given primary consideration. Also of significant importance was the need to provide a zonal recompletion method as it was felt that the need for selective isolation of different zones would be needed to maximize recovery throughout the life of the wells. Completion strategies, the completion configuration, pre-installation shop tests, personnel training, completion servicing considerations and other challenges such as a "green field site" and rig requirements were reviewed; from these analyses, operational strategies were developed. The initial completion installations were successful. The first two wells flowed approximately 40,000 BOPD and are Canada's highest producing wells recorded to date!
World energy demand is increasing. The next trillion barrels will be harder to access, harder to find and will be in ever smaller accumulations. New discoveries will undoubtedly be more difficult to produce and will have to be done with fewer and dwindling experienced resources. The industry has begun to accept change due to their desired demand for improved efficiencies. These efficiencies include integrating the workforce (both service and operating groups), improving quality and efficiency of workflows, and improving the technologies that are feeding into the "Digital Asset™" service. Such technologies are better formation evaluation measurements, better geological models, and faster reservoir simulators, better able to integrate production data for comparison to the geological models. Connecting people and improving technology and workflows allow the right decisions to be made at the right time while spending the least amount of effort. Today, necessity drives new and more dynamic integrated operations; and more efficient working relationships are evolving. This paper will discuss the challenge of doing more with less, exploiting more difficult reserves while lowering costs, increasing profits while reducing risk, and speeding up work processes while cutting non productive time. The answers lie with in a series of steps towards cultural change: utilizing real-time collaborative environments allowing simple workflow methodologies to be applied and feeding improved measurements into improved models while continuous optimization occurs while simultaneously actual operations occur. Introduction While there is currently significant debate as to the future of oil demand, the consensus is that the current crisis will be relatively short-lived and that oil demand will return to moderate growth globally. The demand for energy as a whole will follow this same pattern. Although other forms of energy will be brought on line at varying times and intensities, none are expected to have a significant impact for the next 20–35 years. Studies suggest that currently 70% of the world's oilfields are greater than 30 years old, and the replacement rate is slightly less than 2% per year. Finding, developing, producing and refining of oil will remain a significant part of our lives for the next quarter century. We as an industry are entering a new age characterized by new and innovative ways of finding and developing reserves. Operators and service companies are identifying opportunities to do more with less and to establish the best and right time decisions for finding, planning, drilling and completing wells /fields today. Recently published industry data suggest the median age of geo-scientist, petroleum engineers and geologists is between 48 and 50. New geo-science entrants to the industry peaked in the early 90's and the number has reached a plateau. The industry is not hiring enough individuals to fill the seats of the aging subject matter experts who will be retiring in the next dozen years, although some will continue working in some capacity as contractors in the industry. We are also facing challenges with reduction of bed space for offshore installations while having to deliver expertise to more rigs with fewer expert resources. These remarks assume that the reductions in force and rig count are short-lived. However, if the low energy demand cycle is long-lived, the reduced workforce and reduced rig counts will call for a still greater need for improved efficiencies. The industry will undoubtedly have to adopt better ways to find, drill, complete, and produce hydrocarbon reservoirs. The industry has choices in how prospects are generated, how assets are developed, and how to drill and complete, while evaluating the risk compared to the financial outcome of producing fields to their maximum potential. Note that the choices are not limited to the drilling process but includes formation evaluation, prospect generation, and development of the prospect, monitoring drilling, running and design of bits, fluids, stimulation, completions, and intervention — in other words all aspects of well construction, placement, completion and production processes.
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