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This field produces from a structure that lies above a deep-seated salt dome (salt has been penetrated at 9,000 ft) and has moderate fault density. A large north/south trending fault divides the field into east and west areas. There is hydraulic communication across the fault. Sands were deposited in aeolian, fluvial, and deltaic environments made up primarily of a meandering, distributary flood plain. Reservoirs are moderate to well sorted; grains are fine to very fine with some interbedded shales. There are 21 mapped producing zones separated by shales within the field but in pressure communication outside the productive limits of the field. The original oil column was 400 ft thick and had an associated gas cap one-third the size of the original oil column. Porosity averages 30%, and permeability varies from 10 to 1500 md.
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the 46th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, held in New Orleans, Oct. 3-6, 1971. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
This paper defines a method of increasing gas recovery and reserves by maximizing natural gas well deliverabilities. This method involves prevention of formation damage while drilling, prevention of formation damage while drilling, completing, and working over gas wells.
Included is the definition of the formation damage mechanisms attributable to drilling, completing, and working-over operations. Formation damage, the principle deterrent to maximum-productivity and recovery, involves the physicochemical relationships of fluid-systems with the formation. These relationships are herein defined and then specifically extended to include the effects on gas reservoirs. Of particular importance is a treatise on the effects on the relative permeability to gas from hydrocarbon invasion. permeability to gas from hydrocarbon invasion. This treatise includes a means to evaluate the vaporization-equilibrium constants of the invading complex hydrocarbons. These principles have then been used to develop an oil base fluid system that precludes formation damage and that has a filtrate that will be vaporized by produced gas to preclude any reduction in produced gas to preclude any reduction in relative permeability to gas.
Also presented are computed data, laboratory data, and field data from wells drilled and completed with various fluid systems. These data include core data, return permeability data, back-pressure tests, well productivity histories, and pressure buildup surveys. These data show substantially increased initial and ultimate income from gas wells when non-damaged completions are effected.
The current and forecasted natural gas shortages increase the importance of maximizing the initial productivity and ultimate recovery from gas wells. A frequent impediment to maximum well productivity and hydrocarbon recovery is formation damage that may occur during the drilling or completion operations.
An aggressive hydraulic fracturing campaign, involving over 360 wells, has been conducted at Prudhoe Bay, primarily within the waterflood region of the field. High declines in gross fluid production rates (oil plus water) were observed in the first few months after the fracture stimulations were performed. Work was initiated to determine the cause of these declines and to identify any actions which would mitigate them.
A combination of diagnostic well work, field data analysis and reservoir studies to investigate the decline mechanisms are presented. The paper highlights the use of numerical simulation for investigating the reservoir mechanisms of decline, and the benefits associated with alternative waterflood management schemes.
The Prudhoe Bay oil field is divided into the Western and Eastern Operating areas (WOA and EOA) which are operated jointly, on behalf of the Co-Owners, by BP Exploration (Alaska) Inc and ARCO Alaska Inc., respectively. Despite formation permeabilities averaging 100-200 mD, an extensive hydraulic fracturing campaign was initiated in 1989 mainly within the waterflood regions on both sides of the field. Although the primary purpose of this campaign was to bypass formation damage, the use of aggressive 'Tip screen-out' fracturing techniques has enabled significant additional ('true') stimulation to be achieved.
In the WOA waterflood regions, hydraulic fracturing has led, on average, to a three fold increase in oil production rates. However, declining gross fluid rates observed in the initial months of production following the stimulations raised concerns over their long term effectiveness.
It was unclear whether the declines were caused by a reservoir response to the stimulations or the degradation of fracture properties. Diagnostic wellwork was performed to investigate potential damage mechanisms that may reduce the fracture conductivity. Overall, this wellwork had a limited impact on the post-fracture production declines and it was concluded that mechanisms, other than those amenable to near wellbore treatments, were causing the wells to decline.
This paper discusses the reservoir study initiated to examine possible decline mechanisms. This study involved a review of field data and the extensive use of high resolution, numerical simulation models to predict the performance of a fractured well, given a detailed reservoir description. Numerical simulation was also used to examine the reservoir processes in a waterflood pattern subjected to hydraulic fracturing .
The principal objective of the reservoir study was to determine what, if any, actions should be taken to mitigate the declines and the benefits associated with mitigation. A secondary objective was to quantify the oil rate and recovery benefits associated with the existing fracture program.
“All models are wrong, but some are useful.”
This famous quote by George E.P. Box illustrates both the challenge and the appreciation of building models. Models are needed to predict future performance of an oil or gas field, but, at the same time, models are often biased and inaccurate.
Most investment decisions rely on our ability to predict and to plan the future, and, in that regard, nothing is more important than accurately modeling future well performance. Consequently, three of the four chosen papers address different aspects of this topic.
The first paper deals with ways to improve the accuracy of our predictions. It offers readers a rigorous checklist of questions to ask when developing reservoir models to guide them toward less-biased forecasts.
The second paper deals with how we develop reservoir-prediction tools for asset management. Active reservoir management addresses the almost impossible task of maximizing short-term production while optimizing ultimate recovery. However, to evaluate the different reservoir-drainage mechanisms, one needs good models, and the more advanced the drainage mechanism is, the more crucial the model is. As an illustration, it is much easier to model a pressure-depletion scheme than to try to predict a secondary- or tertiary-recovery process. Assessing and quantifying uncertainties as part of the modeling are becoming increasingly common, and this practice improves the ability to develop a sound decision basis.
The development of unconventional shale resources has further challenged the ability to predict performance. Prediction of such unconventional resources does not necessarily require new tools but rather new assumptions and new experience-based calibration methods. More than 40% of the papers I reviewed for this issue dealt with prediction of production and ultimate recovery of shale gas, which clearly illustrates the increasing interest in this topic and the current challenges faced by today’s petroleum engineers. The lack of history and of good analogs further adds to the uncertainty. I am sure that more research and the availability of more production data will enable us to develop better models and, hence, increase the accuracy of our predictions. The third paper provides great insight into our understanding of unconventionals.
Recommended additional reading at OnePetro: www.onepetro.org.
OTC 23949 In-Well Distributed Fiber-Optic Solutions for Reservoir Surveillance by Juun van der Horst, Shell, et al.
IPTC 16866 Uncertainty Assessment of Production Performance for Shale-Gas Reservoirs by Jiang Xie, Chevron, et al.
IPTC 16505 Joint Inversion of Time-Lapse Crosswell Seismic and Production Data for Reservoir Monitoring and Characterization by Lin Liang, Schlumberger, et al.
Abstract This paper provides operators with a methodology for selecting and / or validating the leading Process Safety Key Performance Indicators related to the Plant Design for facilities or platforms. The importance of Leading Process Safety KPIs is to provide assurance of barriers, also known as Risk Control Systems (RCSs) under HSG 254, 'Developing process safety indicators' (HSE, 2006) ahead of any incident. The majority of leading KPI indicators rely on Inspections, Tests and Maintenance to check the functionality of these barriers. However, validating that the design of the barrier is still appropriate is not covered by current leading KPI checks. Operational changes can introduce new requirements and creeping modifications can undermine the expected operations of aging safety barriers. This paper provides an overview of the use of operational based hazard reviews as a means to identify where there may be design and/or operational failures in the design of safety barriers. Details are presented for the use of Asset Life reviews to determine potential future failures and replacement requirements of safety barriers. Examples of were safety barriers have been identified as insufficient through minor operational changes and potential future major safety barrier replacement issues are shown. This paper focuses on the Plant Design element of HSG 254 'Developing process safety indicators', (HSE, 2006) which currently applies a leading indicator for the percentage of safety critical items of plant or equipment which comply with current design standards or codes, and where this may be undermined because of age and operational changes. Introduction Leading and lagging Key Performance Indicators (KPIs) have been gaining considerable prominence within the Oil and Gas industry with most, if not all, companies setting up lists of performance indicators and potential metrics. These have been developed in line with the HSE guidance 'Developing process safety indicators' (HSE, 2006) and the CCPS 'Process Safety Leading and Lagging Metrics' (CCPS, 2008). As indicated in the Baker Panel Report (Baker et al, 2007) 'The passing of time without a process accident is not necessarily an indication that all is well and may contribute to a dangerous and growing sense of complacency' the use of leading and lagging indicators should significantly improve the process safety performance of process platforms, if used correctly. This measure of performance is also highlighted in Regulation 5 of PFEER (PFEER, 1997) which states the requirement for 'the establishment of appropriate standards of performance'. Hence, use of KPIs provides a means for assurance that risk Control systems, to prevent or limit major process hazards, are 'fit for purpose'. Lagging indicators are relatively easy to define, being based on direct measurements of system failures. However, defining leading indicators, particularly where related to plant design is more difficult, as these indicators are attempting to provide a metric for the potential for equipment to be in unrevealed failure states. Hence, leading indicators rely on performance against inspection, testing and maintenance requirements in order to demonstrate that systems should be in a 'fit for purpose' state if and when required. These leading indicators are based on the assumption that the current design basis is correct or, where changes have occurred, that the Management Of Change (MOC) procedure has correctly identified and assessed the modified performance requirements. However, the MOC process may not have captured all changes and as a result the original design assumption is possibly now incorrect and that the currently designed measure is no longer 'fit for purpose'.