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Offshore exploration and industry change: The case of the Gulf of Mexico

This paper considers industry structure and the exploration performance (by size class of operator) of firms searching for oil and gas in the U.S. Gulf of Mexico. It also tracks the changes in industry structure that have occurred in response to a decline in the quality of remaining prospects in the area. Data presented indicate that because vertically integrated majors dominated in exploration in the early years of the Gulf of Mexico exploration history, they were able to discover 86% of the total hydrocarbons discovered through 1975. However, the data also show a dynamic relationship between the structure of the industry operating in an area and the quality of remaining prospects. The relative share of both credited discoveries and wildcat wells of nonmajor operators has increased as exploration in the gulf proceeded. For example, in state-owned waters from 1951 to 1955, major inns accounted for 85% of all wildcat wells drilled, whereas from 1971 to 1975 these firms accounted for only 30% of the wildcat wells. During these same two periods in the federal Gulf of Mexico, the majors' share of wildcats fell from 98% to 70%.

Journal of Petroleum Technology

Economics and appraisal of conventional oil and gas resources in the western Gulf of Mexico

The oil and gas industry frequently appraises undiscovered oil and gas resources on a regional basis to decide whether to start or continue exploration programs. The appraisals are of little value unless conditioned by estimates of the costs of finding and producing the resources. This paper presents an economic appraisal of undiscovered oil and presents an economic appraisal of undiscovered oil and gas resources in the western Gulf of Mexico. Also presented are a description of the model used to make the presented are a description of the model used to make the assessment, results of a sensitivity analysis, and a discussion of the implications of the results to the industry. The appraisal is shown to be relatively robust to changes in physical and engineering assumptions. At $30/bbl [$4.76/m ] oil equivalent (OE) and a 15 % required rate of return (ROR), commercial oil and gas discoveries are expected to amount to about 15 % of the 25.19 × 10 bbl [4 × 10 m ] OE contained in fields discovered before 1977 in the studied area. Hydrocarbons in future discoveries are expected to be 71 % nonassociated gas, 17 % crude oil, and 12 % other forms. Moreover, it will continue to be economically optimal to drill about three wildcat wells in the Miocene-Pliocene trend for every wildcat well drilled in the Pleistocene trend. Because the number of commercial discoveries was found to be quite sensitive to economic conditions, the analysis has important implications in terms of forecasting future industry drilling and other associated activities in the western Gulf of Mexico.

Journal of Petroleum Technology

Economics and petroleum resource appraisal: The case of the Permian basin:

Estimates of oil and gas resources typically are presented in terms of proved and undiscovered resources. This paper presents a methodology for incorporating economic considerations into resource appraisals for petroleum basins. A cost algorithm is used to calculate estimates of the costs of finding and developing undiscovered oil and gas fields in the Permian basin. The sensitivity of the resource estimates to variations in values of the variables in the costing model was investigated, and the results of this analysis are presented. The model indicates that at prices up to $40/bbl, the total reserves of oil and gas in barrels-of-oil equivalent (BOE's) from future discoveries will be less than 15% of the estimated ultimate recovery from fields discovered before Jan. 1 1975. Only discoveries to a depth of 20,000 ft were included.

Journal of Petroleum Technology

GEOLOGIC ASPECTS OF TIGHT GAS RESERVOIRS IN THE ROCKY MOUNTAIN REGION.

The authors describe some geologic characteristics of tight gas reservoirs in the Rocky Mountain region. These reservoirs usually have an in-situ permeability to gas of 0. 1 md or less and can be classified into four general geologic and engineering categories: (1) marginal marine blanket, (2) lenticular, (3) chalk, and (4) marine blanket shallow. Microscopic study of pore/permeability relationships indicates the existence of two varieties of tight reservoirs. One variety is tight because of the fine grain size of the rock. The second variety is tight because the rock is relatively tightly cemented and the pores are poorly connected by small pore throats and capillaries.

JPT, Journal of Petroleum Technology

FUTURE APPLICATIONS OF EXPERT SYSTEMS FOR THE EVALUATION OF ENERGY RESOURCES.

The loss of professional experience and expertise in the domain of the earth sciences may prove to be one of the most serious outcomes of the boom-and-bust cyclic nature of the volatile energy and mining industries. Promising new applications of powerful computer systems, known as 'expert systems' or 'knowledge-based systems', are predicted for use in the earth science. These systems have the potential capability to capture and preserve the invaluable knowledge bases essential to the evaluation of US energy and mineral resources.

JPT, Journal of Petroleum Technology

Problems of underground storage of wastes

Problems of underground storage of waste involve geology in its broadest sense, including hydrology, geochemistry, and geophysics. Wastes may be solid, liquid, or gaseous, and they may be chemically toxic or noxious, esthetically offensive, or radioactive. Some wastes require only temporary containment, whereas others must be isolated for indefinitely long periods. The means and locale for emplacement underground depend upon many governing geological factors, including the physical, chemical, hydrological, and hydraulic properties of the host formation. These must be studied relative to the physical, chemical, and thermal properties of the waste and of potential interactions between the waste and the host formation. Thorough knowledge is essential because lack of it may lead to undesirable or disastrous environmental consequences. Escape of waste may contaminate the surface or near-surface environment; it may destroy the usefulness or accessibility of resources such as ground water, petroleum, and minerals. Effective management of underground waste requires adaptation of current technology and development of new technology.

Journal of Research of the U.S. Geological Survey

Lognormal field size distributions as a consequence of economic truncation

The assumption of lognormal (parent) field size distributions has for a long time been applied to resource appraisal and evaluation of exploration strategy by the petroleum industry. However, frequency distributions estimated with observed data and used to justify this hypotheses are conditional. Examination of various observed field size distributions across basins and over time shows that such distributions should be regarded as the end result of an economic filtering process. Commercial discoveries depend on oil and gas prices and field development costs. Some new fields are eliminated due to location, depths, or water depths. This filtering process is called economic truncation. Economic truncation may occur when predictions of a discovery process are passed through an economic appraisal model. We demonstrate that (1) economic resource appraisals, (2) forecasts of levels of petroleum industry activity, and (3) expected benefits of developing and implementing cost reducing technology are sensitive to assumptions made about the nature of that portion of (parent) field size distribution subject to economic truncation. ?? 1985 Plenum Publishing Corporation.

Journal of the International Association for Mathe

India National Gas Hydrate Program Expedition-02: Operational and technical summary

The India National Gas Hydrate Program is being steered by the government of India's Ministry of Petroleum and Natural Gas (MoPNG) with participation of Directorate General of Hydrocarbons (DGH), Oil and Natural Gas Corporation Limited (ONGC), and the National Oil Companies and Research Institutes of India. The India National Gas Hydrate Program Expedition 01 (NGHP-01) established the presence of gas hydrate in the Krishna Godavari (KG) and Mahanadi Basins and in the offshore area of the Andaman Sea Basin. However, the gas hydrates discovered during NGHP-01 were mainly distributed as fracture-filling material in fine-grained clay-rich sediments. The India National Gas Hydrate Program Expedition 02 (NGHP-02) was carried out with an objective to discover gas hydrate in sand-rich sediment along the eastern offshore margin of India. ONGC planned and executed NGHP-02 on the behalf of the MoPNG. NGHP-02 started on March 3, 2015 and was completed on July 28, 2015 (total 147 days) using the Japanese scientific Drilling Vessel Chikyu (D/V Chikyu). During NGHP-02, 42 holes at 25 sites were drilled, cored, and/or surveyed with downhole logging tools. These sites were located in four areas along the eastern margin of India and formally named Area A (Mahanadi Basin, three sites), Area B (northern part of the KG-Basin, twelve sites), Area C (central part of the KG-Basin, six sites), and Area E (southern part to the KG-Basin, four sites). All 25 sites established during NGHP-02 were first drilled and logged with logging-while-drilling (LWD) tools and an additional 17 holes were then drilled and/or cored with conventional coring tools (HPCS/ESCS) or pressure coring tools (PCTB). Wireline logging was conducted in 10 holes and formation tests using a dual packer Modular Formation Dynamics Tester (MDT) tool were carried out in two holes. The onboard science team used the laboratory facilities on the D/V Chikyu to examine and analyse the physical properties, geochemistry, and sedimentology of all the cores collected during the expedition. Core samples were also analysed in additional post-expedition shore-based studies conducted in numerous domestic and international gas hydrate research laboratories. The NGHP-02 sediment cores were archived at the National Gas Hydrate Core Repository in Mumbai (India), which is associated with the ONGC Gas Hydrate Research and Technology Centre (GHRTC). The necessary data for characterizing the occurrence of gas hydrate, such as interstitial water chlorinities, core-derived gas chemistry, physical and sedimentological properties, thermal images of the recovered cores, pressure core and downhole measured logging data (LWD and/or conventional wireline log data), were obtained from most of the drill sites established during NGHP-02. Almost all the drill sites yielded evidence for the occurrence of gas hydrate; however, the inferred in situ concentration of gas hydrate varied substantially from site to site. For the most part, the interpretation of downhole logging data, core thermal images, interstitial water analyses, and pressure core images from the sites established during NGHP-02 indicate that the occurrence of concentrated gas hydrate is mostly associated with coarser grained (sand-rich) sediments. This paper presents the operational and technical summary of NGHP-02. NGHP-02 started on March 3, 2015 and was completed on July 28, 2015 (total 147 days) using the Japanese scientific Drilling Vessel Chikyu (D/V Chikyu). During NGHP-02, 42 holes at 25 sites were drilled, cored, and/or surveyed with downhole logging tools. These sites were located in four areas along the eastern margin of India and formally named Area A (Mahanadi Basin, three sites), Area B (northern part of the KG-Basin, twelve sites), Area C (central part of the KG-Basin, six sites), and Area E (southern part to the KG-Basin, four sites). All 25 sites established during NGHP-02 were first drilled and logged with logging-while-drilling (LWD) to

Journal of Marine and Petroleum Geology

An international code comparison study on coupled thermal, hydrologic and geomechanical processes of natural gas hydrate-bearing sediments

Geologic reservoirs containing gas hydrate occur beneath permafrost environments and within marine continental slope sediments, representing a potentially vast natural gas source. Numerical simulators provide scientists and engineers with tools for understanding how production efficiency depends on the numerous, interdependent (coupled) processes associated with potential production strategies for these gas hydrate reservoirs. Confidence in the modeling and forecasting abilities of these gas hydrate reservoir simulators (GHRSs) grows with successful comparisons against laboratory and field test results, but such results are rare, particularly in natural settings. The hydrate community recognized another approach to building confidence in the GHRS: comparing simulation results between independently developed and executed computer codes on structured problems specifically tailored to the interdependent processes relevant for gas hydrate-bearing systems. The United States Department of Energy, National Energy Technology Laboratory (DOE/NETL), sponsored the first international gas hydrate code comparison study, IGHCCS1, in the early 2000s. IGHCCS1 focused on coupled thermal and hydrologic processes associated with producing gas hydrates from geologic reservoirs via depressurization and thermal stimulation. Subsequently, GHRSs have advanced to model more complex production technologies and incorporate geomechanical processes into the existing framework of coupled thermal and hydrologic modeling. This paper contributes to the validation of these recent GHRS developments by providing results from a second GHRS code comparison study, IGHCCS2, also sponsored by DOE/NETL. IGHCCS2 includes participants from an international collection of universities, research institutes, industry, national laboratories, and national geologic surveys. Study participants developed a series of five benchmark problems principally involving gas hydrate processes with geomechanical components. The five problems range from simple geometries with analytical solutions to a representation of the world’s first offshore production test of methane hydrates, which was conducted with the depressurization method off the coast of Japan. To identify strengths and limitations in the various GHRSs, study participants submitted solutions for the benchmark problems and discussed differing results via teleconferences. The GHRSs evolved over the course of IGHCCS2 as researchers modified their simulators to reflect new insights, lessons learned, and suggested performance enhancements. The five benchmark problems, final sample solutions, and lessons learned that are presented here document the study outcomes and serve as a reference guide for developing and testing gas hydrate reservoir simulators.

Journal of Marine and Petroleum Geology