Probable Reserves Research Articles

The Reality of the Oil Sector in Iraq and Future Prospects (An Analytical Study) (in Arabic)

Iraq owns large wealth of crude oil and natural gas, that coming in the international third rank, and it may will be at the first rank in the coming days because of the large quantities of probable reserves that Iraqi crude oil reserves will reach about 500 b.b. But we find the production is in the low level relative to the large proven reserves because of many reasons.This research deal with oil sector analysis recently and expose future vision to reform that sector through economic market philosophy, and starting from the hypothesis that the oil sector is the main source of necessary investments funds for oil sector reform and it’s infrastructure development, and also for the other economic sectors to achieve the growth and economic balance which requires optimization use of the natural resources, that the crude oil and natural gas are in the forefront.To fulfill the research the researcher was deal with the subject through the following sections:First: few economic theory options to achieve oil and gas production optimization.Second: the realty of Iraqi oil sector. Third: production optimization achievement of oil and gas in Iraq.Finally was reached a number of conclusions and notes.

A mine planning model to satisfy long-term grade targets

This paper describes a technique to predict the head grades and likely variances from target grade that can be achieved from mining an iron ore deposit. The method develops a production schedule from a block model. The example used was created from a wide-spaced drilling program and was classified as an Inferred Resource, but the method can be applied to any block model based on the available combination of Proved and Probable reserves. Marketing contracts require examination whether the target grade, i.e. Fe, P, SiO2, Al2O3, can be kept constant, or must be revised during the life of the mine. A model (written in Excel using Visual Basic macros, details available from the first author) develops a feasible, close to optimal, mine plan from block model data. Cut-off grades for minable ore are chosen. The model evaluates ore tonnage, grade and stripping ratio against depth. Outputs at this stage include plots of slices through the ore body, at nominated x, y and z coordinates, showing ore grade, waste, drill-hole locations and topography. The model then searches for a feasible satisfactory mine plan. The initial grade target is the average for the identified ore blocks. The available block list (ABL) at any time is the set of ore blocks, any one of which can be mined without removing any other ore block. The entire initial ABL has an unacceptably large total stress, defined as [(Grade–Target)/Tolerance]2, summed over the four relevant minerals. The model trims the ABL, removing the block most harming the total stress. Trimming is repeated until the Total Stress reduces to an acceptable level. The trimmed ABL defines the first mine campaign. Removing the trimmed block set, a second ABL is exposed, which is again trimmed and mined. The process is automatic: a few seconds computation provides a complete mine plan. Re-running the model with adjusted grade limits quickly shows whether a uniform target can be achieved or whether the target must be modified during the mine life.

PRISE Validates Resource Triangle Concept

Summary As conventional gas (CG) resources are depleted, unconventional gas (UG) resources (gas from tight sands, coalbeds, and shale) are becoming increasingly important to US and world energy supply. The volume of UG resources is generally unknown in most basins outside North America. However, in many mature North American basins, UG resources have been produced for decades, and resources and reserves are well characterized. The objective of this work was to determine the quantitative relations between known conventional and unconventional hydrocarbon resources in mature North American basins, with the ultimate goal of using these relations to estimate UG resources in frontier basins outside North America. We used assessments by the US Geological Survey (USGS), Potential Gas Committee (PGC), Energy Information Administration (EIA), National Petroleum Council (NPC), and Gas Technology Institute (GTI) to evaluate relations among hydrocarbon-resource types in the Appalachian, Black Warrior, Greater Green River, Illinois, San Juan, Uinta-Piceance, and Wind River basins. We chose these seven basins for initial analysis of relations between CG and UG resources because they are mature basins for both conventional and unconventional oil and gas production. To conduct this analysis, we wrote a computer program that we call Petroleum Resources Investigation Summary and Evaluation (PRISE). Input data for PRISE, obtained from published data sources and resource assessments, were values of technically recoverable resources, consisting of the following resource categories: (1) cumulative production, (2) proved reserves, (3) probable and possible reserves and contingent resources (PPC), and (4) prospective resources. We then analyzed these data in each of the seven basins to assess the relationship between conventional- and unconventional-resource volumes. For the seven basins studied, we found that approximately 10-20% of the total recoverable hydrocarbon resources are conventional oil (CO) and CG, whereas 80-90% of the recoverable hydrocarbons are UG resources. We suggest that the results of this study may be used to estimate recoverable resources from UG reservoirs in frontier basins worldwide, where CO and CG resources are known but UG resources have not been evaluated.

Naturally Fractured Carbonate Oil Reservoir: Reserve Estimation Study

A naturally fractured carbonate reservoir is chosen for implementing uncertainty assessment on estimation of original oil in place. The probability distribution of uncertain variables is defined in reserve estimation and evaluating probable reserve by using Monte Carlo simulation. The reserves are estimated for Karabogaz, Kbb-C member of Karababa and Derdere formations. The reserve estimation in fracture is based on available logs and tests about fracture parameters like density and width. The production data is used for verifying the calculated fracture porosity distributions. The mean of reserve distributions are close to deterministic ones. The sensitivity analysis on input parameters showed that matrix porosity, net thickness, and fracture porosity are significant in Karabogaz and Kbb-C formation reserve estimation while water saturation and fracture porosity are most significant in estimation of Derdere formation reserves.

India's First Deepwater Offshore Field Showcases Ingenuity

India’s first deepwater oil and gas field, located in the KG-D6 block 60 km off the east coast of India in the Bay of Bengal, is a success story of government initiative, private enterprise, and global engineering ingenuity. Operated by Reliance Industries, a multinational corporation based in Mumbai, KG-D6 is a world-class discovery at 1200-m depth with proved plus probable reserves of 11.3 Tcf. The fast-track construction of the oil and gas production facilities involved the mobilization of engineering talent, manufacturing capabilities, and construction skills in the US, Europe, the Middle East, and Asia (Fig. 1). In the process, the KG-D6 field has set numerous world records and milestones for India’s emerging oil and gas industry. First Success of Licensing Round The KG-D6 block was awarded in 2000 to a partnership of Reliance Industries (90%) and Niko Resources of Calgary (10%) in the first licensing round initiated by the government of India through its New Economic Licensing Program (NELP). Before NELP, India carried out E&P activities through public-sector companies such as the Oil and Natural Gas Corporation (ONGC). ONGC remains the leading operator in India, but eight rounds of NELP have opened the country’s oil and gas sector to a variety of other public-sector companies (Indian Oil, Hindustan Petroleum, Gujarat State Petroleum Corporation), international oil companies (Cairn Energy, British Gas, Eni), and Indian private companies in addition to Reliance (Essar, Jubilant). Reliance Industries is an Indian conglomerate with extensive operations in the textile, petrochemical, and retail sectors with annual revenues of USD 28 billion. The company was launched in 1962 as yarn trading company by Dhirubhai Ambani. The growth of the company is a study in vertical integration. From yarn, Reliance built textile mills, petrochemical complexes, and entered the upstream oil and gas industry in 1999. Deepwater Discoveries The Krishna-Godavari (KG) Basin covers an area of more than 20 000 km2 on land and extends into the bay more than 24 000 km2 down a steep slope to 2000-m depth (Fig. 2). The Krishna and western part of the Godavari troughs are filled with mainly Paleozoic and Mesozoic sediments, while the eastern part of the Godavari trough contains a predominantly Upper Mesozoic and Tertiary section. The discovery of biogenic gas has been made primarily in the Upper Pliocene plays.

Integrating Reserves Management: Providing Regulatory Compliance and Improving Decision Making

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124168, "Methodology for Integrated Reserves Management: Providing Regulatory Compliance and Im proving Decision Making," by Lev Virine, SPE, Project Decisions, and Doug MacDonald, SPE, Schlumberger Information Solutions, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed. Effective corporate reserves-management systems enable tracking reserves to provide input for reporting to regulators and to serve as a decision-support system. Implementation of such reserves-management systems has challenges. Regulatory bodies, including the US Securities and Exchange Commission (SEC), require proper categorization of reserves on the basis of evaluating whether the volumes can be recovered economically in a timely manner. The reserves-management system should provide technical and economic volumes on the basis of up-to-date prices, capture and analyze uncertainties in the reserves volumes, provide secure data access and data archiving, and implement an approval and audit process. Introduction A method to integrate reserves management was developed that comprises three processes—data management, which ensures fast and secure access to reservoir data; economic and technical volume calculation; and a flexible reporting process. Reservoirs, as well as prospects, are organized within a corporate hierarchy. In accordance with SEC regulations and SPE/World Petroleum Council/American Association of Petroleum Geologists/Society of Petroleum Evaluation Engineers Petroleum Resources Management System (SPE-PRMS) guidelines, the data-management process captures proven, probable, and possible reserves, as well as discovered and undiscovered resources, for different petroleum products and companies with different working interests. Each category of each reservoir is associated with an economic case that contains information about costs, prices, and the fiscal regime. Economic volumes can be calculated on the basis of the results of economic evaluations of the reserves. Uncertainties in reservoir data are captured by use of multiple scenarios for each reservoir and category. A regional-pricing mechanism allows updating prices for all economic cases at a particular level of the corporate hierarchy. All changes to the economic-results data would be recorded and require approval. Challenges. Disclosure of oil and gas reserves is different from disclosure of company financial performance or production. While the financial performance of the company, at least in theory, can be calculated precisely, oil and gas reserves are uncertain by definition. Different proven methods of estimating reserves may yield different results. Moreover, different estimators that use similar methods may determine different numbers. New SEC regulations aim to improve transparency by providing investors with more information about the reserves. In particular, the new regulations permit disclosure of probable and possible reserves. It should be noted that information about probable and possible reserves also includes more uncertainties, compared with proven reserves.

Modernization of the SEC Oil and Gas Reserves Reporting Requirements

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 123793, "Modernization of the SEC Oil and Gas Reserves Reporting Requirements," by W. John Lee, SPE, Texas A&M University, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed. Modernized US Securities and Exchange Commission (SEC) rules for reporting oil/gas reserves are now broadly consistent with SPE definitions and generally reflect public requests for specific changes in the previous rules. Disclosure requirements based on the revised definitions use annual average prices and allow wider use of reliable technologies. They also allow broader recognition of nontraditional resources, including those from oil sands, shales, and coal; optional disclosure of probable and possible reserves; and replacement of the "certainty" criterion for some reserves with a "reasonably certain" criterion. Official clarification of some of the new terms may be forthcoming. Here, the author provides his opinion of their intent. Introduction The SEC oil/gas reserves-reporting requirements in effect until the end of 2009 were adopted in 1978, with some associated requirements adopted through 1982. In the three decades since adoption of these requirements, the petroleum industry has experienced many changes. As examples, technology associated with recovery and characterization of petroleum accumulations has advanced dramatically; spot markets and transportation of sales products to market have grown and improved substantially; and economic production of nontraditional resources, such as bitumen from oil sands, has been established. These developments, and others, caused the SEC's reporting requirements to lag increasingly behind the capabilities of the petroleum industry. In 2007, the SEC created the position of "Academic Engineering Fellow" to help the commission's staff examine the need for modernizing its rules and to help the staff coordinate a project to propose modifications. In October 2007, the author was retained to fill this position. After review of public comments, the SEC approved and released final rules in December 2008. The new rules were published in the Federal Register of the National Archives and Records Administration on 14 January 2009. Official guidance clarifying the intent of unclear phrases that appear in the rules may come, eventually, from the SEC. Below are comments on some possible interpretations of these guidelines, although final interpretations lie only with the SEC. See the full-length paper for references and Web addresses to view them. Major Rules Changes These rules include revised reserves definitions, which are broadly consistent with the SPE/World Petroleum Council/American Association of Petroleum Geologists/Society of Petroleum Evaluation Engineers-Petroleum Resources Management System (SPE-PRMS) definitions (although important differences remain). Disclosure requirements based on the revised definitions include the following.

Coal seam gas—an increasingly significant source of natural gas in eastern Australia

The commercial production of coal seam gas (CSG) in Australia commenced in 1996. Since then its production has grown up significantly, particularly in the last five years, to become an integral part of the upstream gas industry in eastern Australia. The major growth in both CSG reserves and production has been in the Bowen and Surat basins in Queensland. Active exploration and appraisal programs with the first pilot operations were established in the Galilee Basin in 2008; however, an important reserve base has been built up in New South Wales in the Clarence-Moreton, Gloucester, Gunnedah and Sydney basins. There has been modest CSG production from the Sydney Basin for some years with commercial production expected to commence in the other three basins by or during 2010. Exploration for CSG has been undertaken in Victoria and Tasmania while programs are being developed in South Australia focussing on the Arckaringa Basin. Elsewhere in Australia planning is being undertaken for CSG exploration programs for the Pedirka Basin in the Northern Territory and the Perth Basin in Western Australia. CSG was being supplied into the eastern Australian natural gas market at 31 December 2008 at a rate of approximately 458 TJ per day (167 PJ per year). Queensland is currently producing 96.7% of this total. Approximately 88% of the natural gas used in Queensland is CSG. Currently, CSG accounts for nearly 25% of the eastern Australian natural gas market, estimated at 670 PJ per year. The production of CSG is now a mature activity that has achieved commercial acceptability, especially for coal seam derived gas from the Bowen and Surat basins. The recent proposals by a number of local CSG producers—in joint venture arrangements with major international groups—to produce liquefied natural gas (LNG) from CSG along with a number of merger and acquisition proposals, is testimony to the growing economic and commercial significance of the CSG sector. Should all of the proposed CSG based LNG projects eventuate, LNG output would be approximately 40 million tones per year. This will require raw CSG production to increase to approximately 2,600 PJ per year, resulting in a four fold increase from the present natural gas consumption in eastern Australia. The proved and probable (2P) reserves of CSG in eastern Australia at 31 December 2008 were 17,011 PJ or 60.2% of the total independently audited 2P natural gas reserves of 28,252 PJ. The Bowen and Surat basins with 16,120 PJ have the largest onshore gas reserves eastern Australia. In New South Wales, the 2P CSG reserves at the end of 2008 were 892 PJ, though this is expected to increase significantly over the next 12 months. Major upstream natural gas producers such as Origin Energy Limited and Santos Limited both hold over 50% of their Australian 2P gas reserves as CSG. The 1P reserves of CSG in eastern Australia at 31 December were reported as 4,197 PJ while the 3P reserves of CSG at the same date were 40,480 PJ. Most companies in the CSG sector are undertaking development work to upgrade their 3P reserves (and contingent resources) into the 2P category. The CSG resource in eastern Australia is very large. Companies with interests in CSG have reported in excess of 200,000 PJ as gas in place in the Bowen, Clarence-Moreton, Galilee, Gloucester, Gunnedah, Queensland Coastal, Surat and Sydney basins. The 2P reserves of CSG are expected to exceed 20,000 PJ by the end of 2009. A significant part of the expected large increase in 2P reserves of gas initially will be dedicated to the proposed LNG projects being considered for Gladstone. The major issues confronting the CSG industry and its rapid growth are concerned with land access, overlapping tenure (particularly in Queensland with underground coal gasification) the management and beneficial use of co-product formation water and gas production ramp up factors associated with the proposed LNG projects.

Global Infracambrian petroleum systems: a review

Abstract This review covers global uppermost Neoproterozoic–Cambrian petroleum systems using published information and the results of studies undertaken by the Geological Survey of Western Australia (GSWA) on the Neoproterozoic Officer Basin. Both production and hydrocarbon (HC) shows sourced from, and reservoired in, uppermost Neoproterozoic–Cambrian successions occur worldwide, and these provide ample incentive for continuing exploration for these older petroleum systems. However, the risks of charge volume, timing of generation–migration v. trap formation and preservation of accumulation are significantly higher than in conventional Phanerozoic petroleum systems. Therefore, the location and assessment of preserved HC accumulations in such old petroleum systems presents a significant exploration challenge. Organic-rich metamorphosed Proterozoic successions of SE Greenland, the Ukrainian Krivoy Roy Series, the Canadian Upper Huronian Series and the oil shales of the Russian Onega Basin are known as the world's oldest overmature petroleum source rocks. The oldest live oil has been recovered from the McArthur Basin of Australia ( c . 1.4 Ga; Ga is 10 9 years), followed by the Nonesuch oil of Michigan. Numerous other petroleum shows have been reported from Australia, Canada, China, India, Morocco, Mauritania, Mali, Oman, Pakistan, Venezuela and the USA. These demonstrate that generation and migration of Proterozoic petroleum has occurred worldwide. The Siberian Lena–Tunguska province, the Russian Volga–Ural region and the Middle Eastern south Oman petroleum fields exemplify the productive potential of uppermost Neoproterozoic–Cambrian successions, where petroleum generation, migration and trapping were either late in the geological history (Palaeozoic–Mesozoic, Oman) or where accumulations have been preserved beneath highly effective super-seals (Lena–Tunguska). The total resource potential of the Lena–Tunguska petroleum province is estimated to be 2000 Mbbl (million barrels) oil and 83 Tcf (trillion cubic feet) gas. The equivalent proven and probable reserves derived from Neoproterozoic–Early Cambrian source rocks and trapped in Late Neoproterozoic (Ediacaran), Palaeozoic and Mesozoic reservoirs in Oman are at least 12 bbbl (billion barrels) of oil and an undetermined volume of gas. The recovery of 12 Mcf (million cubic feet) of Precambrian gas from the Ooraminna-1 well in the Amadeus Basin in 1963, together with the occurrence of numerous HC shows within the Australian Centralian Superbasin, triggered the initial exploration for Proterozoic hydrocarbons in Australia. This included exploration in the Neoproterozoic Officer Basin, which is reviewed in this paper as a case study. Minor oil shows and numerous bitumen occurrences have been reported from the 24 petroleum exploration wells drilled in the Officer Basin to date, indicating the existence of a Neoproterozoic petroleum system. However, the potential of the Neoproterozoic petroleum system in the vast underexplored Officer Basin, with its sparse well control, remains unverified, but may be significant, as may that of many other ‘Infracambrian’ basins around the world.

The Hermes oil field: a small field takes wings

The Lambert field was discovered in 1973 with oil reservoired in Tithonian turbidites. It was viewed as uneconomic until 1996 when re-evaluation led to discovery of the adjacent Hermes oil accumulation by Lambert–2. The Lambert–3 producer was drilled nearby to Lambert–2 in 1997 and tied back to the Cossack-Pioneer floating production storage offloader (FPSO). Lambert–3 was expected to drain about 25 MMBBLs of oil, coming off plateau after one year and declining substantially thereafter; however, it had produced more than 52 MMBBLs of oil by late 2008 without any water cut and may produce much more in the next 15–20 years. In contrast, several appraisal and production wells drilled since in the adjacent Lambert accumulation have only produced modest recoveries. Why were the original deterministic views of the Lambert-Hermes field so far from present estimates? This paper describes the approach taken to re-assess the Lambert and Hermes oil accumulations. First, the traps were reviewed by framing the main uncertain variables followed by a rigorous scenario analysis of the field. The work was expedited by using a statistical design to substantially reduce the number of scenarios required for modelling and simulation. The results included a statistical analysis and produced a better view of the probable reserves ranges. Remarkably, after 11 years’ production the field potential warranted re-appraisal. The scenario analysis indicated which uncertain variables needed attention and helped to select well locations. The results of appraisal should decide between several re-development options. The main possibilities for new field development include: drilling of additional oil producers; water shut-off in some producers; an additional flow-line to de-bottleneck oil production from Lambert and Hermes; re-instatement of a gas-injection line for gas-lift of wells at high water-cut; and installation of a new manifold further north in the Hermes accumulation to optimise field recovery.

Modeling of ECBM recovery from Amasra coalbed in Zonguldak Basin, Turkey

Zonguldak coal basin is the only productive hard coal basin of Turkey. The eastern part of the basin is called as Bartin–Amasra District, which has deeper coal seams. The depth and difficulty of mining these coal seams make this district an important candidate for coalbed methane (CBM) recovery. However, there is not enough reservoir data for modeling purposes. In this study, the lithologic information collected for coal mining industry was used to determine the correlations and the continuity of the coal seams. The lithologic information was examined and the depths of the coal seams and the locations of the exploration boreholes were used to perform a reliable correlation using a new method. As a result of the correlation study, 63 continuous coal layers were found. A statistical reserve estimation of each coal layer for methane was made by using Monte Carlo simulation method. The initial methane in place found in the coal layers both in free and adsorbed states were estimated using probabilistic simulations resulted in possible reserve (P10) of 2.07 billion m3, probable reserve (P50) of 1.35 billion m3 and proven reserves (P90) of 0.86 billion m3. Among the determined continuous coal layers, coal layer #26 was selected for a preliminary investigation of the applicability of enhanced coalbed methane (ECBM) recovery and CO2 storage. The scarcity of coal seam reservoir data required a sensitivity study for the effects of reservoir parameters on operational performance indicators. The effects of adsorption, coal density, permeability, cleat porosity and permeability anisotropy parameters were examined using the Computer Modeling Group's (CMG) GEM module.

Oil and Gas Securities Regulation and Reporting: National Instrument 51-101

Abstract The prime assets of an oil and gas company are its reserves and resources; they are the most important information about a company, and are the basis on which capital is raised to carry out its activities. A reporting issuer is a company that sells securities on the open market, but not necessarily on an exchange. Canadian National Instrument 51–101 (NI 51–101) governs the disclosure that is required of a reporting issuer. It has been in force since September 2003 and mandates the disclosure of Proved and Probable reserves and allows the disclosure of other categories of resources by reporting issuers. This paper provides a background to the securities regulation and regulatory reporting regime of NI 51–101, including recent amendments. It is not a substitute for the expert advice that should be sought by anyone attempting to fulfill securities regulatory requirements. Some trends and issues on oil and gas reserves and resource estimation and disclosure in Canada and the international arena are also discussed. Introduction The ability to raise money in the public market, to start or continue the activities of a company, carries with it a responsibility to report on these activities to investors. Reporting or "disclosure" requirements are prescribed by securities regulators and apply to all such companies. Because of the importance to the Canadian economy of the extractive industries, oil and gas and mining companies are required to provide additional information beyond that generally required. For the oil and gas industry, new securities legislation, National Instrument 51–101, Standards of Disclosure of Oil and Gas Activities (NI 51–101), was implemented in 2003, replacing the previous legislation, National Policy 2B. Some recent amendments, mainly a reduction in reporting requirements, came into force in December 2007. The Alberta Securities Commission has been administering NI 51–101 since its inception. NI 51–101 reporting is only one of the many reporting requirements that a company is required to fulfill. A brief overview of securities regulation is given here to provide a context for NI 51–101 reporting within the general framework of securities regulation. This is not a substitute for the expert advice that should be sought by anyone attempting to fulfill securities regulatory requirements. The Canadian Oil and Gas Securities Market The Canadian oil and gas securities market is one of the largest of its kind in the world, and about 50% of the world's public oil and gas companies are listed on TSX/TSXV. The number of listed oil and gas companies on the TSX website as of December 31, 2007 was:Canadian TSX/TSXV 424US (NYSE, AMEX, NasDaq) 183LSE-AIM 140A number of reporting issuers trade on other venues than the TSX/TSXV, and an estimated 538 reporting issuers are currently expected to make NI 51–101 annual filings in 2008. Securities Regulation Purpose Securities regulators are responsible for the administration of securities laws in Canada, which includes: Developing, implementing and maintaining securities laws and policies.Regulating primary and secondary market trading through the closed system.Enforcement of securities laws.Educating and communicating with stakeholders and the public.

The Oil 'Price Rise' Factor in the Iraq War: A Macroeconomic Assessment

I start with the premise that the war on Iraq was undoubtedly about oil. The prize was Iraq's spectacular oil wealth estimated at 330 billion barrels of proven, semi-proven and probable oil reserves. At current oil price of $130/barrel, the value of these reserves is estimated at $42.9 trillion, more than three times the United States' gross domestic product (GDP). Even Alan Greenspan, the former chairman of the US Federal Reserve Bank for seventeen years, says the Iraq war is largely about oil.

PKO Resources, Inc.

Pete Carvey, CFO for the PKO Resources of McKinney, TX sat at his desk puzzling over the analysis just presented to him regarding an acquisition his firm was considering. Although this project seemed like hundreds of others that he had analyzed, Pete was bothered by three things: First, the purchase price that had been quoted to PKO seemed very high in light of prices that PKO had observed in recent months. Second, the typical reserve mix for properties that PKO considered was weighted very heavily on proven reserve categories (i.e., proved developed producing, proved developed non-producing, and proved undeveloped). The engineers had told Pete that the Salinas field had substantial prospects for unproved reserves (i.e., typically referred to as probable reserves). In the past PKO had simply ignored the unproved category when evaluating an acquisition but in this instance it appeared the firm would have to place some value on the unproved reserves if it was to have any chance of winning the bid. Finally, Pete worried that his approach to bidding was no longer appropriate as the firm had lost out in all its recent competitive bidding situations. This caused Pete to question the firm's standard approach to arriving at its bid prices. PKO's standard approach to evaluating acquisitions of oil and gas properties is largely static but the firm engages in a number of what if or scenario analyses before arriving at a final number.

Corporate Governance and the Value Relevance of Proved and Probable Oil and Gas Reserve Disclosures: Canadian Evidence

Corporate Governance and the Value Relevance of Proved and Probable Oil and Gas Reserve Disclosures: Canadian Evidence

Bainiuchang super-large silver-polymetallic ore deposit related to granitic magmatism in Mengzi, Yunnan

Bainiuchang silver-polymetallic ore deposit is located in the southeast Yunnan tin-polymetallic metallogenic belt. The probable reserves and inferred resources of the deposit are of 6 470 t Ag and 1.10 Mt Pb and 1.72 Mt Zn and 86 kt Sn. Orebodies of the deposit occur in clastic-carbonate rocks of Tianpeng Formation and Longha Formation of the middle Cambrian System above the Bainiuchang concealed granite of the late Yanshan period. The concealed granite has the characteristics of tin-bearing granites. Abundance of the mineralization elements Sn, Cu, Zn, Pb, Ag and Sb is high in the granitic rocks. Sulphur isotope data of the metal sulphides indicate that most sulphur is derived from the magmas. The ores are similar in rare earth element(REE) patterns to the granitic rocks. The granitic magma activity results in ore-bearing structures. Rocks of the Middle Cambrian System above the concealed intrusion suffer from skarnization, hornfelsing, marbleization, siliconizing and carbonatization. The mineralization elements Sn, Cu, Zn, Pb, Ag and Sb successively appear from the top of the granite to surrounding rocks. These evidences indicate that the granitic magmatism is the principal mineralization factor. The opinion that the south Bainiuchang ore field and the north Awei ore block are tin and copper potential exploration areas was put forward and was verified by drilling tests.

Reserves Estimation: The Challenge for the Industry

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Introduction Reserves estimation is one of the most essential tasks in the petroleum industry. It is the process by which the economically recoverable hydrocarbons in a field, area, or region are evaluated quantitatively. Downward revisions of U.S. Security and Exchange Commission (SEC)-booked reserves by some oil companies in 2004 brought the topic under public scrutiny. Confidence in reserves disclosures became a public issue, and there were calls from investors and lending institutions for more-reliable reserves estimates. Oil companies have responded by revisiting reserves-estimation procedures, and SPE, American Association of Petroleum Geologists (AAPG), World Petroleum Council (WPC), and Society of Petroleum Evaluation Engineers (SPEE) have launched a joint project to train reserves evaluators. A major goal in this initiative is preparation of training modules that represent industry's "recommended practices." Long before the issue caught the public's attention, however, reserves estimation was a challenge for the industry. The challenge stems from many factors, tangible and intangible, that enter the estimation process, and judgment is an integral part of the process. Uncertainty, along with risk, is an endemic problem that must be addressed. Consequently, the industry's record of properly predicting reserves has been mixed. Despite appeals from some quarters, there currently is no standardized reserves-estimation procedure. The purpose of this paper is to discuss various issues related to reserves, review reserves-estimation procedures, and make suggestions for improvements. Emphasis will be placed on reserves evaluation at the preproduction stage in which estimation errors generally have the highest economic effect. The discussed procedures pertain to conventional oil and gas reserves. Specific rules relating to booking reserves for regulatory purposes are outside the scope of this paper. Reserves Definition and Classification Fig. 1 shows how reserves are part of the petroleum resource base. Under the SPE/WPC definitions, "Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward" (Petroleum Reserves Definitions 1997). Commerciality implies commitment or expected commitment to develop reserves within a reasonable time frame. Depending on the degree of uncertainty, three main classes of reserves are recognized: proved, probable, and possible, the last-named two collectively called unproved. Proved reserves are those quantities that have reasonable certainty of being recovered, indicating a high degree of confidence. Proved reserves may be developed or undeveloped. Probable reserves are more likely than not to be recoverable, while possible reserves are less likely to be recoverable than probable reserves. Geological and engineering data form the basis of determination. Proved reserves assume recoverability under current economic conditions, operating methods, and government regulations. For unproved reserves, recoverability may be tied to future economic conditions and technology.

Mineralogical, Petrological, Stable Isotope, and Fluid Inclusion Characteristics of the Tuvatu Gold-Silver Telluride Deposit, Fiji: Comparisons with the Emperor Deposit

The Tuvatu gold-silver telluride deposit with reserves of 13 t Au is the second largest gold deposit in Fiji after the large Emperor gold telluride deposit (production, and proven and probable reserves of 280 t Au). The deposits are 50 km apart and occur along the >250-km east-northeast–trending Viti Levu lineament. They are spatially associated with alkaline rocks of almost identical age (~5.4–4.6 Ma) and having a shoshonitic affinity. The gold mineralization in both deposits is spatially and genetically related to monzonite intrusions and to a low-grade porphyry copper-style system. The Emperor deposit occurs along the margins of the Tavua volcano whereas the Tuvatu deposit may occur adjacent to an eroded shoshonite volcano. At both locations, low-sulfidation, epithermal gold telluride mineralization occurs in flat-lying veins, steep faults, shatter zones, stock-works, and hydrothermal breccias. Mineralization in both deposits formed in multiple stages and is characterized by the presence of quartz-roscoelite telluride veins in which gold-rich tellurides were deposited prior to silver-rich tellurides. Gold tellurides and vanadium minerals were deposited at approximately 250°C from moderately saline fluids. Oxygen and hydrogen isotope compositions of ore fluids at Emperor and Tuvatu are similar to the composition of waters exsolved from arc magmas. Previously published values of δ34S of sulfides (–20.3 to +3.9‰) from Emperor are like those obtained from the Tuvatu deposit (−15.3 to −3.2‰) and indicate, along with mineral assemblages, that the ore fluids were oxidizing and near the hematite-pyrite buffer. The similar igneous lithological units of almost identical age, transition from porphyry- to epithermal-style mineralization, paragenetic relationships, and comparable fluid inclusion and stable isotope data suggest a common origin for sulfide and gold telluride mineralization at the Tuvatu and Emperor deposits. Potential exists for additional epithermal gold telluride mineralization near volcanic centers in shoshonitic rocks (Ba and Koroimavua Volcanic groups) spatially related to the Viti Levu lineament in northern Viti Levu.

Oil and Gas Reserves Estimates

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17714, “Panel: Oil and Gas Reserves Estimates,” by R. Harrell, SPE, Ryder Scott Co.; R. Gajdica, SPE, BHP Billiton; D. Elliott, Alberta Securities Commission; T.S. Ahlbrandt, SPE, U.S. Geological Survey; and S. Khurana, JP Kenny Inc., prepared for the 2005 Offshore Technology Conference, Houston, 2–5 May. Copyright 2005 Offshore Technology Conference. Reproduced by permission. This article is a summary of a panel session at the 2005 Offshore Technology Conference. Oil and gas reserves estimates are further complicated with the expanding importance of the worldwide deepwater arena. These deepwater reserves can be analyzed, interpreted, and conveyed in a consistent, reliable way to investors and other stakeholders. Continually improving technologies can lead to improved estimates of production and reserves, but the estimates are not necessarily recognized by regulatory authorities as an indicator of “reasonable certainty,” a term used since 1964 to describe proved reserves in several venues. Solutions are being debated in the industry to arrive at a reporting mechanism that generates consistency and at the same time leads to useful parameters in assessing a company’s value without compromising confidentiality. Current Issues Reserves estimation has been under way for more than 100 years and has been discussed within the industry for more than 70 years. So why was this topic discussed? The reasons include several proved-reserves write-downs in 2003, evolving technology, new regulations (particularly in Canada), and the U.S. Sarbanes-Oxley Act of 2002. Reserves Write-Downs. Annual changes in estimates of proved reserves, both positive and negative, are a matter of fact in the industry. In many instances, they may be the result of reclassifications from proved to probable reserves solely related to economic factors and may not necessarily be a loss of reserves. However, 2003 write-downs were large and were outside generally accepted ranges. There are many reasons for these write-downs, but an overriding and common cause is the increasing industry awareness and understanding of the U.S. Security and Exchange Commission (SEC) reserves definitions and how the current SEC engineer-ing staff interprets them. New Technologies. Fewer appraisal wells are drilled, and 3D-seismic, core-analysis, wireline-testing, and logging data—all integrated into a detailed computer-generated reservoir model—are used for assessing reserves. The SEC issued a “will not object” opinion on 15 April 2004 for the reporting of reserves only from the deepwater Gulf of Mexico (GOM) without benefit of a traditional formation-to-surface flow test if there is overwhelming evidence of economically productive rates corroborated through analysis of seismic, logs, cores, and wireline-test data. Improving oilfield drilling and completion technology and access to markets has reduced the time to drain a reservoir efficiently, but has not necessarily improved the ultimate recovery of a reservoir or field. Improved ultimate economic recovery is being enhanced in many cases by strategically placing wells through use of seismics and by reducing project operating and capital costs. Such improved (or sometimes only accelerated) recovery should reflect positively on the value of booked proved reserves.

Methane Pressure-Cycling Process for Thin Heavy-Oil Reservoirs

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 88500, "Methane Pressure-Cycling Process With Horizontal Wells for Thin Heavy-Oil Reservoirs," by Mingzhe Dong, SPE, PTRC, and Sam Huang, SPE, and Keith Hutchence, SRC, prepared for the 2004 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 18-20 October. The methane pressure-cycling (MPC) process is an enhanced-oil-recovery (EOR) method used in some heavy-oil reservoirs after termination of primary or waterflood production. The object of the process is restoration of the solution-gas-drive mechanism. This restoration is accomplished by reinjecting an amount of solution gas, mainly methane, and then repressuring the gas into solution by injecting water until the original reservoir pressure is reached. This recreates the primary-production conditions. This recovery technique targets the large portion of heavy oil in thin reservoirs. Introduction Heavy oil in reservoirs thicker than 10 m commonly is produced by use of thermal recovery methods. These methods generally are not suitable for thin reservoirs because of heat losses to the overburden, underburden, and bottomwater zones. Saskatchewan accounts for 62% of Canada’s total heavy-oil resource including 1.7×109 m3 of proven and 3.7×109 m3 of probable reserves. Of the province’s proven initial heavy oil in place, 97% is contained in reservoirs with pay zones less than 10 m thick and 55% is in reservoirs with pay zones less than 5 m thick. Primary and secondary methods recover only approximately 7% of the proven initial oil in place (IOIP). The incentive is strong for the development of EOR techniques that will maximize the recovery of these thin heavy-oil reservoirs. The MPC process is an EOR method intended for application after termination of primary or waterflood production in some thin reservoirs. The objective of the pressure-cycling process is restoration of the solution-gas-drive mechanism that provided primary production. Restoration is accomplished by reinjecting an amount of solution gas and then repressuring the gas back into solution by injecting water until original reservoir pressure is reached. This recreates the primary-production conditions. The process uses infill horizontal production wells located between the existing vertical wells that are used for methane and water injection to pressure up the depleted reservoir. This pressure cycling is repeated until additional economic recovery is no longer feasible. The Saskatchewan Research Council/Petroleum-Technology Research Center has been investigating the pressure-cycling process for the past few years. Experimental Pressure/Volume/Temperature (PVT) Studies. PVT studies were conducted for oil samples collected from four Saskatchewan heavy-oil reservoirs (Senlac, Golden Lake, Plover Lake, and Cactus Lake North) in contact with methane. The purpose of these studies was to investigate the PVT properties of heavy-oil/methane mixtures and to provide input data on the PVT behavior of live oils for numerical simulations. Heavy-Oil Coreflood Studies. The heavy-oil coreflood apparatus consists of a 30.5-cm triaxial-stress core holder, a Ruska dual-cylinder positive-displacement pump, an injection system, a production system, and support units. A backpressure regulator installed at the production end maintained the operating pressure. Oil production was determined on a mass basis.