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The Petroleum Resources Management System (PRMS) is a system developed for consistent and reliable definition, classification, and estimation of hydrocarbon resources. The Oil and Gas Reserves Committee has completed the revision of the Petroleum Resources Management System (PRMS) and the SPE Board approved it in June 2018. The updated PRMS is a consensus of input collected from consulting and financial firms, government agencies, and E&P companies. The process included a 90-day public comment period, and required input and approval by six sponsoring societies: the World Petroleum Council, the American Association of Petroleum Geologists, the Society of Petroleum Evaluation Engineers, the Society of Exploration Geophysicists, the European Association of Geoscientists and Engineers, and the Society of Petrophysicists and Well Log Analysts. The 2018 PRMS update maintains the foundation principles contained in the PRMS 2007 and addresses many of the points in need of clarification that have been collected over the years.
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (1.00)
The Petroleum Resources Management System, or PRMS, has long been recognized as the global standard reference for resources and reserves classification and definition. The PRMS, although first designated as such in 2007, had been in existence in various forms since SPE assumed responsibility for codifying reserves definitions in 1965. As the industry evolved, the SPE-sponsored guidelines have been contemporized in an ongoing fashion ever since. The PRMS was updated most recently in 2018, spearheaded by the SPE Oil & Gas Reserves Committee (OGRC) through a collaborative endeavor with the Society of Petroleum Evaluation Engineers (SPEE), the American Association of Petroleum Geologists (AAPG), the Society of Exploration Geophysicists (SEG), the European Association of Geoscientists and Engineers (EAGE), the Society of Petrophysicists and Well Log Analysts (SPWLA), and the World Petroleum Council (WPC). In response to the 2000 edition of the document, a companion volume entitled Guidelines for the Evaluation of Petroleum Reserves and Resources was published in 2001 through the efforts of SPE, AAPG, and WPC.
- Asia > Middle East > Saudi Arabia (0.35)
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- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (0.92)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (0.56)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (0.56)
Equal to P1. Glossary of Petroleum Resources Management System - June 2018 (revised version) The sum of Proved plus Probable plus Possible Reserves.Glossary of Petroleum Resources Management System - June 2018 (revised version) The process (and associated costs) of returning part or all of a project to a safe and environmentally compliant condition when operations cease. Examples include, but are not limited to, the removal of surface facilities, wellbore plugging procedures, and environmental remediation. In some instances, there may be salvage value associated with the equipment removed from the project. ADR costs are presumed to be without consideration of any salvage value, unless presented as "ADR net of salvage."Glossary of Petroleum Resources Management System - June 2018 (revised version) Arithmetic summation of incremental categories may yield different results from probabilistic aggregation of distributions.Glossary of Petroleum Resources Management System - June 2018 ...
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- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
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Equal to P1. Glossary of Petroleum Resources Management System - June 2018 (revised version) The process (and associated costs) of returning part or all of a project to a safe and environmentally compliant condition when operations cease. Examples include, but are not limited to, the removal of surface facilities, wellbore plugging procedures, and environmental remediation. In some instances, there may be salvage value associated with the equipment removed from the project. ADR costs are presumed to be without consideration of any salvage value, unless presented as "ADR net of salvage." Arithmetic summation of incremental categories may yield different results from probabilistic aggregation of distributions. Method used in resources estimation in the exploration and early development stages (including improved recovery projects) when direct measurement is limited. Based on evaluator's assessment of similarities of the analogous reservoir(s) together with the development plan.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
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- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
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Although reserves estimates for known accumulations historically have used deterministic calculation procedures, the 1997 SPE/WPC definitions allow either deterministic or probabilistic procedures. Each of these is discussed briefly in the next two sections. Thereafter--except for another section on probabilistic procedures near the end--the chapter will focus on deterministic procedures because they still are more widely used. Both procedures need the same basic data and equations. Deterministic calculations of oil and/or gas initially in place (O/GIP) and reserves are based on best estimates of the true values of pertinent parameters, although it is recognized that there may be considerable uncertainty in such values.
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India is putting its aggressive program to sharply reduce oil and gas imports over the next 5 years to the test with an upcoming bidding round aimed at winning back international oil companies with the skills and money to make major discoveries. Last yearโs discovered small fields auction by state oil firm ONGC attracted strong bidding from smaller Indian players, many new to the business. But โthis is much more ambitious,โ said Atanu Chakraborty, director general of Indiaโs Directorate General of Hydrocarbons (DGH). The country is trying to reach the goal set by Indiaโs Prime Minister Narendra Modi to reduce oil and gas imports by 10% by 2022. To increase the odds of getting bids, operators have been asked to choose the blocks they want included in the bid-ding round to be held later this year. The contracts are based on revamped energy policies designed to eliminate the regulation that limited international interest in the past. โThe government is not in the business of trying to micromanage production,โ said Dharmendra Pradhan, the minister in charge of the Ministry of Petroleum and Natural Gas, India, during a presentation at the recent IHS Markit CERAWeek conference in Houston. At the conference, the government announced the bidding round at a meeting drawing top executives from international companies. Indian energy officials need the exploration help as domestic production falls further behind the exploding level of demand. The percentage of imported oil has risen from nearly 77% about 3 years ago to 82% in the current fiscal year, Pradhan said, according to a recent report. Given the time needed for large exploration and production (E&P) projects, a 10% reduction in 5 years is a stretch. Adding to the difficultly is rapid demand growth due to the 7%-plus annual increase in Indiaโs gross domestic product. โThere is skyrocketing demand in almost every energy sector,โ said Charles Ebinger, senior fellow at the global energy center of the Atlantic Council, during a panel session at the conference. There is oil and gas potential there. DGH estimates it has produced only 3% of its proven natural gas reserves and around 5% of its proven oil reserves. While it is not a big oil and gas producer, the 115 drilling rigs working there in mid-February were just behind the 120 rigs drilling in Saudi Arabia, according to the Baker Hughes rig count. E&P is dominated by the national oil company ONGC, with other government-owned companies and some local independents working as well. But in a country with more than 3 million km of sedimentary basins, where gas discoveries have been more common, it imports 50% ofย its gas.
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- Reservoir Description and Dynamics > Reservoir Characterization (0.71)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (0.55)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (0.35)
Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. All reserves estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further subclassified as probable and possible reserves to denote progressively increasing uncertainty regarding their recoverability.
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Abstract This paper presents a study of how the oil and gas industry has approached the demonstration of a "Reliable Technology" since the emergence of this as a formal reserves term in the US Securities and Exchange Commission's (SEC) modernized reserves regulations in late 2008. The paper summarizes the different technologies and the approach to reliability demonstration described in recent technical literature. It also investigates the target element of the reserves estimation procedure, such as expanding the Proved Area. Through a review of published technical papers and other documents, this paper examines the industry's different views of demonstrating a "reliable technology." Sidle and Lee (2010a) proposed the scientific method as an approach to demonstrating the criteria were satisfied. Industry literature examples of seismic technology (to determine Proved Area) and numerical reservoir simulation (to determine recovery factor) are analyzed. Additionally, we examine the SPEE Monograph 3 (2010) procedure to understand the logic used to support reliability and compare it to the scientific method approach. This examination includes how the demonstration of analogy is important to estimate the resulting PUD reserves when technologies to define Proved Area are being considered. This is then compared to other examples of predictable commercial productivity of undrilled areas that do not meet the SPEE Monograph 3 (2010) requirements. As industry seeks new technologies and approaches to demonstrating reliability, the status of how others have addressed these issues is valuable guidance. In providing both recent demonstration approaches and proposed technology, this paper provides a good reference on both what is currently being done to establish a proposed reliable technology and how this technology can be validated.
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- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Dampier Basin > Rankin Platform > Greater Gorgon Development Area > Block WA-268-P > Greater Gorgon Field > Gorgon Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Carnarvon Basin > Rankin Platform > Greater Gorgon Development Area > Block WA-268-P > Greater Gorgon Field > Gorgon Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Alpha Arch > Dampier Basin > Rankin Platform > Greater Gorgon Development Area > Block WA-268-P > Greater Gorgon Field > Gorgon Field (0.99)
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- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (1.00)
Abstract This paper proposes an approach for assessing a reservoir simulation model for use in estimating reserves. A simulation model can integrate complex static data, the physical description of displacement processes, production constraints and schedules. Hence it can provide important input to business decisions and to reserves estimation. Confidence in simulation predictions depends on the strength of evidence for the input data, quality control of the model, robustness of the history match, and whether there is independent evidence supporting predictions. We explain the principles for evaluating a simulation model and propose requirements for simulation predictions to be considered as proved reserves. This involves evaluation against different strands of evidence e.g. static and dynamic characterisation, wells and facilities description, reservoir performance and analogues. Simulation models are often built to support business decisions using best technical estimates for inputs. There can be instances where a simulation model may be reasonable and reliable but it only represents aโbest technicalโ outcome. There may not be sufficient evidence to count the whole predicted recovery as proved reserves. We propose how such a model may be modified to also provide proved reserves estimates. The approach is illustrated through a case study which shows how the principles may be applied with different available data and at different stages of field life.
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
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Copyright 2013, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Beijing, China, 26-28 March 2013. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Abstract Hydrocarbons exploration and bidding is a high risk venture in every project that is taken by any corporation. There is always a chance of failure with the total investment made versus chance of success. If the calculated pay back amount less than the expenditure, then a company may reject the project or take less than 100% working interest in operation to tolerate risk. Low total resource volume, minor prospects, very low probability of success (POS) and low or very low level of knowledge (LOK) are some of the characteristics study play major role. Royal Dutch shell won the license for the Mangala block RJ-ON-90-1 of Rajasthan (India) in the year 1992 from Indian Government with a production sharing contract (PSC). In 1998, Royal Dutch shell sunk a well in area and used logging probe (to detect the hydrocarbons) which gave negative reading, Cairn had 10% of stake in the leasehold at that time. It then purchased the complete leasehold from shell in 2002 and now producing from one of the highest oil reserve region in India. Shell lost the golden opportunity of huge production because of a wrong reserve estimate. Another case describes the world's biggest natural gas reserve discovery of D-6 block in Krishna Godavari basin in Southern India during 2002 by Reliance Industries.
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- Government > Regional Government > Asia Government > India Government (0.34)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
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- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Reserves classification (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (1.00)