Onshore Gas Research Articles

Strategic Direction for Reducing Fatal Oil and Gas Industry Incidents

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 94416, "Upstream Onshore Oil and Gas Fatalities: A Review of OSHA's Database and Strategic Direction for Reducing Fatal Incidents," by C.K. Curlee, SPE, Marathon Oil Co.; S.J. Broulliard, ConocoPhillips; M.L. Marshall, U.S. Dept. of Labor - Occupational Safety and Health Admin.; T.L. Knode, SPE, Halliburton; and S.L. Smith, Chevron Corp., prepared for the 2005 SPE/EPA/DOE Exploration and Production Environmental Conference, Galveston, Texas, 7-9 March. According to the U.S. Dept. of Labor—Occupational Safety and Health Admin.(OSHA) database for the period 1997 through 2003, one fatality occurred every 10 days in the U.S. upstream oil and gas industry. These data were studied to determine trends and provide insights into the safety failures and to study potential interventions to eliminate the high frequency of fatal incidents. This review provides oil and gas industry operating managers, safety professionals, trade associations, and others a way to improve programs and set priorities for reducing onshore oilfield-related fatalities. Introduction Each year, the U.S. Bureau of Labor Statistics (BLS) releases a Census of Fatal Occupational Injuries (CFOI) report. These reports indicate that the mining sector, which includes the oil and gas extraction subsector (i.e., all upstream E&P activities), typically experiences one of the highest fatality rates of all major industries. In the BLS report of 2003 data, 34.5 fatalities occurred for every 100,000 workers in the oil and gas extraction subsector, or one fatality every 4.3 days. This fatality rate is more than 8.5 times the average for all U.S. industries. An industry-review team (IRT) was formed, consisting of professionals representing operating companies, drilling and well-servicing companies, and industry trade associations, as well as OSHA. The IRT examined the OSHA fatality information, with emphasis on validating the OSHA database. Once the database information was understood, the IRT determined trends to provide insights into the safety failures associated with E&P-industry fatal incidents.

Borehole seismic: what does it bring to the understanding of the reservoir?

When thinking about what we need for a more comprehensive approach to reservoir description and management, the range of information is large and various. The objective is always to improve our ‘vision’ of the geological setting, including a precise rock-type characterization and a good understanding of hydrocarbon flow paths. Each of these elements of the reservoir is determined with a varying level of uncertainty. Today, there is general agreement that integration of competences in business units is the optimal way to take the full benefit of technology breakthroughs in each individual discipline. Borehole seismic is identified as being critical to increasing the quality and the reliability of processing and interpretation of surface seismic data. If until recently, borehole seismic applications were focused on seismic calibration using vertical seismic profiles (VSP) and sometimes on imaging when surface seismic defaulted, today the link to well data is growing stronger. Since not all disciplines involved in reservoir management can work at the same scale, this raises the problem of scale and model compatibility between the respective disciplines. Here again borehole seismic can play a key role. This is becoming possible because advances have been made in a variety of techniques and methods leading to applications such as multi-walkaway and 3D-VSP, 4C and 4D-VSP, single-well and crosswell acquisitions, amplitude variation with offset (AVO) calibration, and scale change. Moreover, improvements in technology make the acquisition and processing cost-effective. Multilevel, three- or four-component receiver strings and permanent seismic sensors are examples of a continued development of operationally efficient hardware. New borehole seismic techniques such as 4D-VSP or the improvement in more mature ones such as crosswell seismic, offer new images of the reservoir. Although these images may be spatially limited, they are usually of a higher resolution than surface seismic and can offer significant benefit for reservoir management and monitoring. This paper illustrates the benefits of borehole seismic with three case studies, illustrating (1) how we can include uncertainties in the VSP imaging process and its impact on structural interpretation of a North Sea reservoir, (2) why AVO calibration using a walkaway technique is mandatory for a better prediction and interpretation of seismic attributes in terms of lithology and fluid content and (3) 4D walkaway and passive seismic surveys using fibre-optic seismic permanent sensors for monitoring an onshore gas storage.

Freedom and loss in a human landscape: multinational oil exploitation and the survival of reindeer herding in north-eastern Sakhalin, the Russian Far East

Sakhalin’s multinational offshore oil and gas projects signify hope for the region’s economic regeneration. They also pose an environmental threat to the livelihoods of local natural resource-users, including Sakhalin’s few remaining reindeer herders. For the herders over the past century, industrial development, particularly in relation to the domestic onshore oil and gas industry, has been associated with environmental degradation and loss of pastures, family cohesion, language and culture. The herders contrast the physical and mental freedom they enjoy living on the land to the constraint of village life. Their survival strategies are based on a certain freedom from authority and the formal law. Their desire for freedom is also manifested in a reluctance to engage with outsiders who could have a significant influence on their future. This paper explores the survival strategies of reindeer herding households and enterprises and the ways that they engage with outsiders such as state officials, NGOs and o...

Improved Productivity Justifies World Record Underbalanced Perforating Operation

Abstract A Dutch onshore gas well was drilled to a total depth of 5,136 m along hole (3,700 m true vertical depth) with a maximum deviation of 89 degrees. The well was completed with 193.7 mm (7 5/8 in.) 13 ﹪ chrome (Cr13) tubing with a 177.8 mm (7 in.) cemented liner across the reservoir providing fullore access to the pay zone. Due to the very stratified nature of the reservoir, the long-term sustained production depended on achieving vertical connectivity with all the layers. In order to achieve this and maximize productivity, a single run underbalanced perforating operation was required. Due to coiled tubing limitations in this deep, high pressure well, a hydraulic workover unit was selected to deploy and retrieve the guns. A total gross interval of 1,026 m was perforated in one run utilizing 85.725 mm (33/8 in.) deep penetrating guns and thereafter snubbed from the well under live conditions (46 MPa at surface). To date, it is understood that this is the longest section of guns conveyed, fired underbalanced, and deployed out of a live well. This paper addresses the perforating technique selection, the planning and execution process, the major operational learning points, and discusses final productivity results which demonstrate the validity of this technique. Introduction The Anjum reservoir is a Rotliegendes sandstone at a true vertical depth of 3,700 m. Reservoir pressure and temperature are high for onshore Netherlands at 56 MPa and 137 °CDATA[C, respectively. Following discovery of the prospect in 1992 with the Anjum 1 exploration well, Anjum 4 was drilled as the second well in the field. It was designed as a combined appraisal/development well with the objective of providing capacity in the region of six to seven million m3/day. The reservoir is of a highly stratified nature with a number of high permeability features, some of which are on a centimetre scale. The Upper-Slochteren gas-bearing interval is split up into six discrete units, which are correlatable across the whole of the North Netherlands area. The upper three sands dominate in terms of reservoir quality and productivity. There exist two significant and continuous high permeability streaks (HPS) which, if targeted, would provide initial high productivity. However, the longterm sustained production depends on achieving vertical connectivity with all reservoir zones. Therefore, in order to maximize exposure across all intervals, and to provide the maximum connectivity with the individual layers, a sub-horizontal well was designed. A cemented and perforated liner was selected, since it provided the opportunity to effectively bypass near wellbore drilling induced damage. Secondary benefits of this design are that it provides maximum selectivity (water shut off, stimulation etc.) and through the utilization of deep penetrating perforating guns reduces non-Darcy turbulent effects. The well was completed with a 177.8 mm (7 in.) Cr13 liner across the pay zone and a 193.7 mm (7 5/8 in.) Cr 13 monobore completion with a tubing retrievable safety valve to provide maximum wellbore access (Figure 1).

ONSHORE ACREAGE RELEASE 2001

It is my privilege to present the onshore acreage release for the year 2001 on behalf of the States and Territories.I will be presenting the information as supplied to me by each department of the States and Territories.Before doing so, I would like to make a few remarks. Many of these will be familiar to you, but I believe bear repeating to remind ourselves.While there appears to be a resurgence of onshore interest and activity, last year saw the lowest level of onshore exploration activity in many years.At the risk of being emotive, Australia does not deserve this poor level of exploration activity.Australia has vast sedimentary basins, and these are under-explored by any world standards. Targets range from Palaeogoics (even neo-Proterozoic) to Tertiary.Australia needs:To have innovative concepts.The drive to carry out these concepts.Support of the governments and community.Financial backing of good ideas and good people.Land access.While this list is not exhaustive, it does encapsulate the key issues.The opportunities for onshore oil and gas successes are vast so I urge all in the industry to pursue these opportunities.And now, I turn to each state, starting with Queensland.

Chemical injection to on-shore gas field

Bran + Luebbe process pumps have been selected for the chemical injection duties at Saltfleetby near the Theddlethorpe Terminal,which is located on the UK's largest on-shore gas field in Linclnshire.Gas from the field is being fed into Conoco's Theddlethorpe Terminal which also has four feeds coming in from the North sea.This terminal handles approximately 25% of the UK's gas production.

Some practical applications of recent core analysis advances

The Eromanga Basin is Australia's main onshore oil province, consisting of a large number of thin good permeability reservoirs. This basin overlies the Cooper Basin, Australia's main onshore gas province, consisting of many thicker but low permeability gas reservoirs. Both basins often contain stacked reservoirs. In order to identify improvements in core analysis which can be applied to the basins the Operator has conducted a series of experiments using newly or recently developed procedures. Following are some highlights. (1) Reservoirs which may have leaked: Some Eromanga basin reservoirs are believed to have leaked into overlying reservoirs. For the reservoir which has leaked it is not really valid to compare the log analysis to a drainage capillary pressure curve. Neither does a traditional laboratory imbibition capillary curve exactly describe the process. A new laboratory imbibition procedure was developed which appears to match the log analysis better than drainage data. (2) Low invasion coring: This has become an established procedure in Australia. Many of our reservoirs are well suited to it. In one case we obtained saturations by four different laboratory procedures and compared them to the log analysis, obtaining a somewhat large spread in the various laboratory results. (3) Transitional reservoirs: For waterflood and some relative permeability experiments the traditional laboratory procedure of using high capillary pressure ( P c) to achieve s wc then a high flood velocity (or capillary number N) to achieve s or has been shown to produce incorrect results across the Eromanga Basin and has been replaced by a low P c/low N method, yielding better agreement with log analysis. (4) Mud testing on cores for formation damage: Comparison of a particle size distribution from the mud with a pore size distribution from the reservoir has a lot of pitfalls. It does not follow that particles much smaller than a pore automatically have the opportunity to enter the pore. (5) Spreading experiments: Two suites of experiments were conducted involving waterflooding a core followed by gasflooding it. One suite was run with a positive spreading coefficient, and the other with a negative spreading coefficient. Oil recovery was the same in both cases.

NEW CONTROL BUILDING ENVELOPE FOR BRITISH GAS.

In April 1994, Babtie Group was commissioned by British Gas Exploration and Production to project manage and design an enclosure to provide blast protection to an existing control building at the North Morecambe On-Shore Gas Terminal at Rampside, near Barrow-in-Furness. The construction of the terminal was virtually complete and the control building, located at the southern end of the facility, was the operational centre for the on-going system commissioning activities. It was an essential project requirement that the enclosure was designed and constructued without causing disruption to the commissioning effort and constructed without compromising the integrity of the existing structure. In order to satisfy health and safety considerations associated with importing full gas inventory for final plant commissioning, the protective envelope was to be structurally intact by 14 August 1994 and fully fitted out, available for opreation's staff occupation by 30 September 1994.

Seepage in Vietnam — onshore and offshore examples

Hydrocarbon seepages in Vietnam are generally linked to migration from Tertiary source rocks, and seeps are present both onshore and offshore. Residual oil can be observed at outcrop in breached traps within Tertiary sections and in exhumed ‘buried hill’ traps in pre-Tertiary rocks in the onshore Hanoi Basin. There is active oil seepage on the western margin of the offshore Phu Khanh Basin through fractured granites that outcrop at the basin margin. There are examples of onshore gas seepages in southern Vietnam. These are predominantly non-hydrocarbon, mantle-derived gases, sometimes mixed with biogenic methane, and are seeping via hot springs from fractured Mezosoic igneous rocks in active fault zones. Offshore, in the Nam Con Son Basin, sonar, seismic data and sea bed cores show a variety of seepage features, including shallow gas anomalies, mounds and pockmarks on the sea bed, and gas effects in the water column sometimes visible on sonar records. However, sea bed seepage features are not particularly common, and have a low preservation potential in the area due to powerful sea bed currents. Aircraft surveys of the sea surface have revealed several oil slicks that could be related to active oil seepages in the Nam Con Son Basin. Seepage appears to be occurring in Vietnam at two fundamentally different rates. ‘Background’ seepages flow at low rates, typically tens to thousands of cubic feet per day of gas, and up to tens of barrels per day of oil. These seeps flow episodically for extended periods of months or years, and leading to the formation of sea bed mounds. Higher flow rate eruptive seepages may have formed some of the pockmarks, and have a far shorter duration, probably only a few hours or days, with flow rates of millions of cubic feet per day of gas and any associated liquids.

Abstract: Western Newfoundland Onshore Oil and Gas Potential with Emphasis on the Carboniferous Basins 

Abstract: Western Newfoundland Onshore Oil and Gas Potential with Emphasis on the Carboniferous Basins 

PREPARATION AND IMPLEMENTATION OF A SAFETY MANAGEMENT SYSTEM IN BHPP

BHP is a leading global resources company which comprises four main business groups: BHP Copper, BHP Minerals, BHP Steel and BHP Petroleum. BHP Petroleum (BHPP) global operations are divided into four Regions and Australia/Asia Region is responsible for exploration, production, field development and joint ventures in the Asia-Pacific region. In Australia, the Company's largest producing assets are its shares of the Gippsland oil and gas fields in Bass Strait and the North West Shelf project in Western Australia.BHPP operates three Floating Production, Storage and Offloading (FPSO) vessels-Jabiru Venture, Challis Venture and Skua Venture-in the Timor Sea and one FPSO, the Griffin Venture, in the Southern Carnarvon Basin. Stabilised oil is offloaded from all four FPSOs by means of a floating hose to a shuttle tanker. Gas from the Griffin Venture is compressed and transferred through a submarine pipeline to an onshore gas treatment plant.BHPP's Asian production comes from the Dai Hung oil field offshore Vietnam where BHPP is the operator and from Kutubu in Papua New Guinea.In Melbourne, BHPP operates a Methanol Research Plant and produced Australia's first commercial quantities of methanol in October 1994.BHPP is an extremely active offshore oil and gas explorer and has interests in a number of permits and blocks in the Australian-Indonesian Zone of Co-operation.This paper discusses BHPP's approach to safety management, both for its worldwide operations and specifically in Australia/Asia Region. It explains how BHPP's worldwide safety management model takes regional regulatory variations into account. It shows, specifically, how this has been done in Australia/Asia Region using what BHPP considers to be a best practice approach.The paper describes how BHPP Australia/Asia Region benchmarked its performance against other operators in Australia and the North Sea. It explains how the findings of the benchmarking study were used to plan the preparation of a safety management system (SMS). The structure of the SMS is described along with the legal requirements in Australia.The paper concludes that implementation of the SMS is progressing according to plan and points out that safety cases for the FPSOs have been submitted to the Regulators. Implementation of the SMS and the drive for world class safety standards is having a substantial effect and safety performance is improving. One measure of safety performance, the Lost Time Injury Frequency Rate (LTIFR) is down from around 15 at the end of 1994 to under 3 in December 1996.

Workforce Participation in Safety Case Preparation

Abstract The requirement in the United Kingdom for Safety Cases to be prepared and submitted stemmed from the Cullen Inquiry into the Piper Alpha disaster. The Safety Case is the means for an operator or owner of an installation to demonstrate how safe design and operation is achieved. An important part of the preparation process is to consult relevant members of the workforce. This paper discusses how the workforce have been involved in the preparation of Safety Cases. The experience gained in submitting Safety Cases for 9 onshore and offshore installations over the last 2 years is covered with particular emphasis on the role played by the safety committee system, plant and field personnel (staff and contract) and line management. The installations range from large manned oil and gas platforms and an associated onshore gas processing plant, to small single well normally unmanned gas platforms. The main benefits of workforce involvement have been found to be in the participation process itself. This leads to a higher level of workforce "ownership" of the Safety Case. It is concluded that this process has helped to achieve even better workforce communication, understanding and co-operation on safety issues than in the past.

New Separator Internals Cut Revamping Costs

This article describes the debottlenecking operation of the production separators on the Shell Leman AK platform in the southern North Sea. The original, compactly built separators became overloaded through decreasing well pressures. Gradually, they were forming a serious restriction in the production flow sheet. Two alternatives were considered to overcome this problem: (1) extending the platform and installing new separators or (2) retrofitting the old separator vessels with state-of-the-art internals. The second alternative was chosen because of considerable lower costs (totaling only 10% of first alternative) and considerably shorter downtime. This separator upgrade was a joint project between the operator of the field and their central research and engineering facilities and Burgess Manning, Technical U. of Delft, and CDS Engineering BV.

THE LA BELLA AND MINERVA GAS DISCOVERIES, OFFSHORE OTWAY BASIN

In the past 100 years of hydrocarbon exploration in the Otway Basin more than 170 exploration wells have been drilled. Prior to 1993, success was limited to small onshore gas fields. In early 1993, the La Bella-1 and Minerva-1 wells discovered significant volumes of gas in Late Cretaceous sandstones within permits VIC/P30 and VIC/P31 in the offshore Otway Basin. They are the largest discoveries to date in the basin and have enabled new markets to be considered for Otway Basin gas. These discoveries were the culmination of a regional evaluation of the Otway Basin by BHP Petroleum which highlighted the prospectivity of VIC/P30 and VIC/P31. Key factors in this evaluation were:geochemical studies that indicated the presence of source rocks with the potential to generate both oil and gas;the development of a new reservoir/seal model; andimproved seismic data quality through reprocessing and new acquisition.La Bella-1 tested the southern fault block of a faulted anticlinal structure in the southeast corner of VIC/P30. Gas was discovered in two Late Cretaceous sandstone intervals of the Shipwreck Group (informal BHP Petroleum nomenclature). Reservoirs are of moderate to good quality and are sealed vertically, and by cross-fault seal, by Late Cretaceous claystones of the Sherbrook Group. The gas is believed to have been sourced from coals and shales of the Early Cretaceous Eumeralla Formation and the structure appears to be filled to spill as currently mapped. RFT samples recovered dry gas with 13 moI-% CO2 and minor amounts of condensate.Minerva-1 tested the northern fault block of a faulted anticline in the northwest corner of VIC/ P31. Gas was discovered in three excellent quality reservoir horizons within the Shipwreck Group. Late Cretaceous Shipwreck Group silty claystones provide vertical and cross-fault seal. The hydrocarbon source is similar to that for the La Bella accumulation and the structure appears to be filled to spill. A production test was carried out in the lower sand unit and flowed at a rig limited rate of 28.8 MMCFGD (0.81 Mm3/D) through a one-inch choke. The gas is composed mainly of methane, with minor amounts of condensate and 1.9 mol-% C02. Minerva-2A was drilled later in 1993 as an appraisal well to test the southern fault block of the structure to prove up sufficient reserves to pursue entry into developing gas markets. It encountered a similar reservoir unit of excellent quality, with a gas-water contact common with that of the northern block of the structure.The La Bella and Minerva gas discoveries have greatly enhanced the prospectivity of the offshore portion of the Otway Basin. The extension of known hydrocarbon accumulations from the onshore Port Campbell embayment to the La Bella-1 well location, 55 km offshore, demonstrates the potential of this portion of the basin.

Horizontal drilling for onshore gas faces many challenges : Salehi, I A Oil Gas JV90, N40, Oct 1992, P61–69

This paper reports that even though cost-effective in oil fields and some prolific offshore gas fields, horizontal well technology has not yet been successfully transferred to onshore gas fields. The major technical challenges are accurate reservoir characterization, proper well design and placement, and stimulation. The first two of these challenges can be met with the state-of-the-art technologies but the third requires emerging knowledge, tools, and techniques. To determine the application of horizontal wells to typical gas reservoirs in the continental U.S., the Gas Research Institute (GRI) initiated an applied research and development project in late 1990.

THE ENVIRONMENTAL MONITORING OF NATURAL EVENTS AND INDUSTRY ACTIVITY IN MERMAID SOUND, DAMPIER ARCHIPELAGO

Various events, both natural and man-induced, have been identified as potential sources of disturbance to corals adjacent to the North West Shelf Project's Onshore Gas Treatment Plant on the Burrup Peninsula in the Dampier Archipelago. These events include cyclones, dredging and dredge spoil dumping operations, shipping activities, effluent discharge and oil spills.Environmental monitoring has indicated that the coral assemblages near the Onshore Gas Treatment Plant have been adversely affected by Project-related operations and tropical cyclones. The effects on corals due to dredging and spoil dumping activities have been shown to be localised and limited to a distance of 1.5 km from the nearest point of operation.Cyclone Ilona (1988) and Cyclone Orson (1989) were amongst the strongest recorded in the Dampier Archipelago. These cyclones caused extensive coral damage throughout the Archipelago, especially on the eastern side of Mermaid Sound. By 1990, recruitment of corals was observed at many of the sites indicating that corals were beginning to recover.

Methane-derived carbonate cementation of marine sediments from the Kattegat, Denmark: Geochemical and geological evidence

Methane-derived carbonate cementation of Holocene marine sediment occurs at several locations in the Kattegat, Denmark. Generally, the carbonate-cemented sandstones occur at the seafloor as individual slabs or widely distributed, thinly lithified pavements. In some areas, the lithified sandstones take the form of large and spectacular, vertical pillar and mushroom-like bodies standing up from the seafloor. The carbonate cement consists of aragonite, high-Mg calcite, and dolomite. The high-Mg calcite is the most widespread carbonate solid phase found. Aragonite is primarily associated with shell accumulations in the sediments. So far, dolomite has only been recorded as cement in the large, vertical lithified sandstone bodies. The carbonates are remarkably depleted in 13C, i.e. generally in the range of −55% to −45% PDB and are therefore interpreted as being the result of methane oxidation by sulphate-reducing bacteria in the anaerobic diagenetic zone of the sediments. However, the oxygen isotopic composition and the concentrations of minor elements indicate that carbonate precipitation took place under relatively constant temperature and salinity conditions in normal marine pore fluids. The habit and mineralogy of the carbonate-cemented sandstone observed most likely are controlled by the effect of bacterial activity and upward gas migration on the interstitial geochemical microenvironment. The lithified sediments were subsequently exposed as spectacular sandstone formations on the seafloor by submarine erosion. Data from onshore exploration wells reveal that methane is encountered in Eemian-Early Weichselian (Late Quaternary) marine deposits. The chemical composition and the isotopic signatures of the methane suggest a gas of microbial origin, and it is thought that the gas is generated within the host marine Quaternary sediment. The locations of submarine gas seeps, along with those of the carbonate-cemented sandstone formations and the onshore gas seeps, show a linear distribution which largely coincides with the extension of the Fennoscandian border zone. Thus the seeps may be controlled by the structural framework in the northeastern part of the Danish Subbasin.

THE DEVELOPMENT OF A TOTAL HAZARD CONTROL PLAN FOR AN LNG SITE

Australia's North West Shelf Project is based on the development of major gas reserves discovered in the early 1970s in deep water some 130 km off the coast from Dampier, Western Australia.The project was developed in two phases. The Domestic Gas Phase, completed in 1984, supplies pipeline gas to the State Energy Commission of Western Australia for distribution in the south-west of the State. The Liquefied Natural Gas (LNG) Phase involves the export of LNG to eight Japanese power and gas utilities under 20-year Sale and Purchase Agreements. The production and export of LNG commenced in 1989.A Total Hazard Control Plan (THCP) has been developed for the project's onshore and offshore facilities to ensure that all hazards which could affect public safety outside the plant boundary are identified and controlled for the life of the site.The THCP applies to all sites, including the trunkline, onshore gas treatment plant, King Bay supply base and North Rankin A offshore platform. The objectives of the THCP are: to identify the hazards that exist together with their potential consequences; to list the policies and procedures which control the hazards and assign responsibility within the organisation to ensure that those policies and procedures are implemented; to provide verifiable assurance to Government that the Project Operator, Woodside, comprehensively and systematically controls all foreseen hazards to public safety, at the level of 'reasonably practicable'.Compliance with the THCP is verified using a structured auditing programme involving both internal and external audits.

Environmental Liability and the Onshore Oil and Gas Prospector: ABSTRACT

Environmental Liability and the Onshore Oil and Gas Prospector: ABSTRACT

Landbase of Acreage Available for Oil and Gas Leasing, Exploration, and Development in Shawnee, Hoosier, Wayne, and Monongahela National Forests, Illinois, Indiana, Ohio, and West Virginia: ABSTRACT

Federal oil and gas leases are being issued again since the passage of the Federal Onshore Oil and Gas Leasing Reform Act of 1987. Several National Forests in the Illinois-Indiana-Ohio-West Virginia area have potential for substantial new petroleum and gas discoveries. These forests are located in the Illinois and Appalachian basins. In this paper, the authors try to clarify federal leasing procedures, availability of leasable lands, and operating restrictions on certain areas of the forests.