Acreage Acquisition Research Articles

Concurrent 14. Presentation for: The transformation of Australia’s first commercial CSG field into a major gas project: how innovation and subsurface understanding has driven its success

Presented on Wednesday 18 May: Session 14 Mount Isa Mines Limited discovered coal seam gas (CSG) in the ‘Dawson Valley’ in 1991. It was the first commercial coal seam gas field in Australia, with production and sales of gas commencing circa 1994, then operated by Conoco and known as Meridian SeamGas. In 2010, Westside Corporation acquired a 51% operating interest in Meridian SeamGas from Anglo American (Anglo) and Mitsui Moura Investment Pty Ltd (MMI). Over the last 10 years, Westside has increased sales by 466% from 9 terajoules per day (TJ/d) to 42 TJ/d with gas being sold to both domestic and export markets. Further acreage acquisition to the north and south increased the asset area by 264%; now known as the Greater Meridian Fields (GMF). The steep rise in gas demand, complex market dynamics, regulatory environment, and competition from large global oil and gas operators makes it a challenging environment for smaller gas producers in Australia. Remaining agile and employing innovative approaches to optimise field development are key factors for Westside’s growth. In particular, the pad-based drilling of up dip multi-lateral wells has reduced cost and surface footprint, while enabling more efficient gas drainage. To support this field development, a more robust subsurface framework was required. Adequate knowledge of the distribution and variability of coal thickness, gas content/composition, structure, and geohazards forms the basis of the static model. It is used for resource definition and for the optimal planning and execution of multi-lateral wells, reducing drilling risks. To access the presentation click the link on the right. To read the full paper click here

The transformation of Australia’s first commercial CSG field into a major gas project: how innovation and subsurface understanding has driven its success

Mount Isa Mines Limited discovered coal seam gas (CSG) in the ‘Dawson Valley’ in 1991. It was the first commercial coal seam gas field in Australia, with production and sales of gas commencing circa 1994, then operated by Conoco and known as Meridian SeamGas. In 2010, Westside Corporation acquired a 51% operating interest in Meridian SeamGas from Anglo American (Anglo) and Mitsui Moura Investment Pty Ltd (MMI). Over the last 10 years, Westside has increased sales by 466% from 9 terajoules per day (TJ/d) to 42 TJ/d with gas being sold to both domestic and export markets. Further acreage acquisition to the north and south increased the asset area by 264%; now known as the Greater Meridian Fields (GMF). The steep rise in gas demand, complex market dynamics, regulatory environment, and competition from large global oil and gas operators makes it a challenging environment for smaller gas producers in Australia. Remaining agile and employing innovative approaches to optimise field development are key factors for Westside’s growth. In particular, the pad-based drilling of up dip multi-lateral wells has reduced cost and surface footprint, while enabling more efficient gas drainage. To support this field development, a more robust subsurface framework was required. Adequate knowledge of the distribution and variability of coal thickness, gas content/composition, structure, and geohazards forms the basis of the static model. It is used for resource definition and for the optimal planning and execution of multi-lateral wells, reducing drilling risks.

Eagle Ford Shale play economics: U.S. versus Mexico

The decline of domestic natural gas supply and rising demand requires Mexico to import 1/3 of its annual gas consumption of 2.5 trillion cubic feet (Tcf). Yet, Mexico's estimated resource of technically recoverable shale gas (545 Tcf) is the 6th largest such gas resource in the World. Much of Mexico's shale gas resource is in the Eagle Ford Shale, which is a mature shale gas and oil play in the U.S. To aid in determination of whether development of the Eagle Ford Shale in Mexico could reduce the country's dependency on natural gas imports, we evaluated the potential of Mexican shale acreage by comparing the after-tax net present value (NPV) and internal rate of return (IRR) of Eagle Ford shale wells on either side of the U.S.-Mexico border. The initial development of Mexican acreage occurs with a much larger well-spacing (leading to higher acreage acquisition cost per well), which would require 25% higher development cost as compared to Texas acreage. Consequentially, Texas wells have better net present value (NPV) and higher internal rate of return (IRR) than Mexican wells, in general. The principal explanation is that the signing bonus will be much higher in Mexico than in Texas, partly effectuated by the lower well spacing for unrisked acreage. Results of our study provide potential operators and investors with a preliminary indication of Eagle Ford Shale well economics in Mexico. Our study includes sensitivity analyses for both non-escalated and escalated gas prices, for drilling and completion (D&C) costs, and for leasehold cost. The economic appraisal accounts for both single- and multiple-well development scenarios with P10, P50 and P90 production forecasts.

Assessing continuous resources - building the bridge between static and dynamic analyses

Abstract The processes associated with assessing conventional hydrocarbon accumulations are well understood and routinely applied. These assessments can have either a local (prospect) or regional (play) focus, depending on the business need, and rely on risking, sizing, and counting discrete prospects. In contrast, many continuous resource plays are better characterized as a single large hydrocarbon accumulation with highly variable resource density rather than as discrete fields or prospects. Because economic margins may be thin, business success often depends on early identification of favorable areas. Decisions regarding play entry, acreage acquisition, and pilot project design frequently must be made without the benefit of recent well or production data. The assessment methodology for continuous resources must be flexible enough to adapt to situations ranging from little or no well data to thousands of wells. Play assessment provides a powerful mechanism for integrating geologic insights into business decisions. To incorporate the unique aspects of continuous resources, we apply a hybrid grid and polygon based methodology. The play is subdivided into a series of analysis polygons (subplays or segments) that provide the basis for probabilistic calculations. The polygon boundaries can be dynamic (mapped geologic limits), static (leases), arbitrary, or some combination of these. Polygons should be defined for the purpose at hand and at a granularity that captures but does not overwhelm regional trends. Those geologic properties mapped spatially as grids (e.g. gross thickness, net-to-gross, or porosity) are evaluated within each analysis polygon to obtain inputs for the probabilistic assessment. Geologic properties that are not available as spatially varying estimates can be assigned directly with appropriate ranges of uncertainty. Resource uncertainty can be captured both as ranges around most likely parameter estimates and as multiple geologic or operational scenarios. Risk dependency and volumetric correlation must be defined in order to obtain robust probabilistic aggregations of multiple analysis polygons. Fully probabilistic results lead to better informed business decisions by providing information on high side and low side outcomes. Concurrent with the probabilistic assessment, deterministic grid-based calculations of in-place and recoverable hydrocarbon volume per unit area elucidate the resolvable geographic variation of resource density. The parallel grid-based approach ensures that results incorporate and are consistent with local geologic understanding and provides a direct basis for calibrating volumetric calculations with well performance data. Ultimately, assessments based on well performance provide the clearest indication of the recoverable resource and economic viability of a play. Unfortunately, well performance-based approaches are not reliable until a high operational efficiency has been achieved and the number of wells with adequate production histories is sufficient to clarify the primary controls on resource density. To provide early prediction of well performance within the context of volumetric assessment, probabilistic ranges of well EURs are estimated for each assessment polygon based on volumetric inputs coupled with assumptions about likely drainage areas. Well drainage area can be entered as a single value or as a range tied to reservoir properties (permeability and rock mechanics), geologic complexity (faulting), and completion scenarios (well spacing, vertical vs. lateral completions, length of laterals, etc.). As performance-based EUR projections become available for wells, they can be compared to the specific recoverable volume prediction from the resource density grid along with the distribution of well EURs predicted for the polygon. Population-based Bayesian statistical techniques provide robust, probabilistic predictions of EUR for producing wells within a play. Combining analog datasets of initial potential (IP) with well EUR provides a dynamic linkage of the volumetric assessment to well performance. Applying relationships between EUR and IP from analog plays to EUR curves (one per polygon) for the play of interest yields spatially varying families (distributions) of IP’s. By recasting assessed volumes in terms of well productivity, this process supports economic analyses explicitly linked to spatially varying geologic inputs.

MANAGING CONFIDENTIALITY AND CONFLICTS OF INTEREST IN A COMPETITIVE ENERGY MARKET

Producers and other participants in the petroleum industry are in the midst of an increasingly competitive energy market. It is now the case that throughout Australia producers of natural gas are competing not just with substitute sources of energy but with one another. No longer do producers only compete for prospective tenements, rather their competitive activity extends from acreage acquisition through to the burner tip. The emergence of deregulation in the gas industry and the opportunities for competitive activity have been discussed at recent APEA conferences.1The aim of this paper is to examine where conflicts between interest and duty may arise between joint venturers who are now directly, or through affiliated companies, competing for marketing opportunities. We examine how and why such conflicts may arise and whether it is possible to manage them while still participating in traditional forms of joint venture exploration, production and in some cases marketing.For example, are producers able to satisfy their obligations of good faith and preserve confidentiality in joint venture exploration and production activities without compromising their ability to independently pursue the marketing of their share of production?

ECONOMICS OF PETROLEUM EXPLORATION OFFSHORE AUSTRALIA AND SOUTHEAST ASIA

The aim of this paper is to assess the economic attractiveness of exploring for crude oil offshore the North West Shelf of Australia by comparison with selected areas offshore Indonesia, Malaysia, Vietnam and the Philippines. In order to do this, the paper examines the technical, quantifiable factors which affect offshore petroleum exploration acreage acquisition decisions at the country level. These factors are historical prospectivity, costs of field development and fiscal regime. Other factors such as political, macro-economic and business risks are not considered.The paper concludes that there are significant differences between the countries as indicated by these measures. Past exploration in the Barrow/Dampier area of the North West Shelf of Australia has shown high levels of success by comparison with the other countries. This relatively high success rate coupled with comparatively low costs of field development and lenient fiscal regimes makes the economics of exploration on the North West Shelf favourable by comparison with those selected areas in the other countries considered.

Oil and Gas Developments in Central and Southern Africa in 1985

Oil industry activity in central and southern Africa appears to have stabilized in the last few years, but some activities (such as field development and exploration acreage acquisition) are still declining. Several countries have advertised open concessions and invited bids. Only in a very few cases have the offers stimulated the interest of oil companies. An exceptional increase in exploration concession acquisition took place in the East Africa rift area. Land seismic acquisition increased mostly in Nigeria, but 1985 marine seismic activity was half the 1984 activity. Exploration drilling was higher than in 1984, but development drilling was considerably lower. Significant discoveries were made in Gabon and Angola. Production increased 8%, with the largest and most significant increase in Angola, followed by Gabon. The production share of non-OPEC versus OPEC countries remained stable at 33%.

Oil and Gas Developments in Far East in 1983

In 1983, the Far East region was again one of the more active regions of the world for exploration. Exploratory drilling increased 19%, line-kilometers of seismic increased, and development drilling was up 40%. Despite the active exploration pace in 1983, no major oil or gas discoveries were made in the region. Indonesia, India, Japan, and Pakistan recorded multiple discoveries, but reserves in individual finds appear to be modest. As usual, Indonesia was the most active country for which detailed data is available. India followed with the next most active exploration program. Its effort appears to be gaining momentum and showing significant positive results. The remainder of the region, with the exception of onshore Thailand, proceeded slowly at the same pace as previous years and, generally speaking, with the same results. Possible bright spots in this picture are Japan and Pakistan, where encouraging oil discoveries were found during the year. Oil production in the Far East region increased 7% in 1983. The majority of the 300,000 BOPD increase came from India (+81,000 BOPD), Malaysia (+79,860), and People's Republic of China (+100,000). Gas production increased a healthy 8%, mainly due to start-up of the Bintulu LNG facility in Malaysia and inclusion of additional processing trains at Indonesia's LNG facilities. Several new companies began to explore in the Far East during 1983. Although acreage acquisition appears to have declined during the year, continued enthusiasm for exploration projects was evidenced by increases in exploratory drilling and seismic throughout the region.

Oil and Gas Developments in Far East in 1982

In 1982, the Far East region was one of the brighter parts of the world for the petroleum industry. Exploratory acreage acquisition, drilling, and seismic activity maintained the busy pace set in 1981. Most parts of the Far East region showed significant and even increased activity compared with 1981. Although drilling was active in 1982, there were no nationally important oil or gas discoveries in the region. Indonesia, Philippines, Malaysia, and India all recorded multiple discoveries, but these for the most part followed the pattern of previous years. Indonesia was, as usual, the most active country outside of China. A record number of exploratory and delineation wells was drilled in 1982. As in previous years, a plethora of oil and gas discoveries was recorded, but only 1 discovery, a gas discovery in onshore east Kalimantan, is possibly of major significance. Countries which had disappointing exploration programs in 1982 are Bangladesh, Burma, Japan, Philippines, and Taiwan. Exploration in these countries did little to enhance their resource bases. Production in the Far East declined slightly in 1982 to approximately 4.3 million BOPD from 4.4 million BOPD in 1981. This appears to have been mainly due to market conditions. Curtailment of production in Indonesia as a result of the worldwide oil glut offset healthy production gains in India, Malaysia, Philippines, and Thailand. The general attitude of the petroleum industry toward the region was enthusiasm for exploration prospects. Acreage acquisition was brisk in Indonesia, Malyasia, and Thailand. Drilling was on the increase in India, Indonesia, and Thailand. Seismic activity continued strong in most parts of the reporting area. Exploration appears to be alive and well in the Far East.

Oil and Gas Developments in Far East in 1981

Petroleum activity throughout the Far East region was brisk during 1981. Exploration acreage acquisition, drilling, and seismic activity proceeded rapidly in all of the main producing countries. In addition, activity expanded into some hitherto relatively inactive areas such as onshore Thailand, Sri Lanka, North Vietnam, etc. Exploration drilling increased approximately 12% in 1981. For the past few years there has been a dearth of major discoveries in the Far East region. However, during 1981 this trend was reversed. Although commercial significance of the discoveries is not entirely known, there were interesting oil and gas discoveries in onshore Thailand, offshore India, in the Cauvery basin, and onshore Burma. Indonesia was the most active country in the Far East again in 1981. Numerous discoveries were recorded. Exploration in India started in earnest along the east coast. Burma also recorded a busy year along the Irrawaddy River. Sri Lanka experienced exploration drilling in 1981 for the first time since 1976. Onshore Thailand had a flurry of activity and provided the most significant discoveries in the Far East region. The Philippines also had an active year and progressed rapidly with development work on 2 additional producing fields. Countries in the Far East region which recorded no significant change in petroleum related activities during 1981 were Bangladesh, Japan, Pakistan, South Korea, and Taiwan. The outlying islands such as Maldives likewise had minimal petroleum activity. China, in spite of great expectations, did not sign offshore contracts and thus recorded approximately the same level of activity as 1980. Production from the Far East region again declined slightly to an estimated 4.4 million BOPD. With no major discoveries over the last few years, present producing fields are for the most part fully developed and on the decline. Acreage acquisition during 1981 showed a large increase in many parts of the region. Indonesia offered 9 exploration blocks. All were successfully tendered. Onshore Thailand also had intense competition for areas adjacent to oil and gas discoveries by Shell and Esso. Participation by foreign contractors in exploration and production ventures throughout the Far East region increased during 1982. Countries such as Bangladesh, Burma, India, Thailand, and Malaysia all experienced increased interest by foreign companies. On the other hand, relinquishments by contractors in Pakistan and Philippines indicated a decrease in interest in those areas.

Petroleum Developments in Far East, 1979

Petroleum activity in the Far East reporting region evinced a subtle shift during 1979 toward exploration for smaller, lower productivity plays in more mature areas. Examples of this are renewed onshore activity by Brunei Shell and Sarawak Shell in pre-World War II fields, active exploration by Atlantic Richfield and liapco in the Java Sea, Indonesia, and renewed interest in older producing areas of Pakistan and India's Assam basin. Price increases appear to promoted this type of exploration activity. Price increases in both oil and gas put pressure on have countries to accelerate petroleum investment in their areas. Sri Lanka, Pakistan, Burma, China, and even India solicited foreign participation in resource development. Others, such as Bangladesh and Burma, made greater efforts to acquire drilling and seismic equipment necessary to speed up their internal exploration and development programs. The most active new area within the Far East reporting region was China. Atlantic Richfield led the rush of foreign contractors who acquired seismic exploration rights off China's southeast coast. Almost all of the area from the Gulf of Tonkin on the south to Taiwan on the north was surveyed seismically. At year end approximately 12 seismic vessels were surveying in this area. So great was the rush to China that programs in other Far East countries were, in some places, curtailed for lack of equipment. There is no accurate count of exploratory and delineation wells drilled within the reporting area but relative to 1978 there was a 16% increase during 1979. An estimated 394 exploratory and delineation wells were drilled excluding those in countries which do not report these statistics. Of these, 39% were drilled in Indonesia which again was the busiest area within the reporting region. Areas which showed significant increases in activity were Peninsular Malaysia, Pakistan, the Philippines, Indonesia, and China. Only in Peninsular Malaysia and Indonesia did this activity result in multiple discoveries. Even here none of the discoveries appear to large reserves. Production for the Far East region increased only slightly during 1979. Major increases however were recorded in Peninsular Malaysia, offshore India, and China. Peninsular Malaysia's production increased from 19,735 BOPD to an estimated 120,000 BOPD at year end. China probably had an increase of 225,000 BOPD. Indonesia recorded a slight drop in oil production despite active exploration and development programs in both 1978 and 1979. Japan and Taiwan, with moderately active exploration programs during 1979, recorded no major discoveries. Production declined slightly as a result of the lack of success over the last few years. The only bright spot for Japan is that exploration began late in 1979 on the Japan-South Korea joint development area. In early 1979, the Philippines became a producing nation for the first time. Another first was that Burma became an exporting nation for the first time since 1941. Acreage acquisition in the Far East region by foreign contractors followed the same pattern as 1978. Pertamina offerings in Indonesia generated great interest and garnered significant bonuses and work commitments. Similarly in the Philippines and Pakistan there were acreage acquisitions by many of the world's major oil companies. However, countries such as Sri Lanka, South Korea, and Burma again had no luck in attracting foreign investment in their offerings.

Well-Data Files and Computer--Exploration Tools for the Seventies: ABSTRACT

Since the development of computer-processable well-data files began in 1961, more than 600,000 wells have been included in systems covering most of the United States and Canada. These systems contain information on ownership, location, well classification and status, drilling and completion activities, tests, depths to formation tops, core descriptions, shows, and other data. Data are obtained from the most reliable and complete source for each area and are upgraded by computer editing and the feedback of missing data and corrections from file users. Well-data files are used at various stages of the exploration process for basin evaluation, for selection of prospective stratigraphic intervals and areas for further study delineating prospects for acreage acquisition or drilling, and for building peripheral files containing proprietary, technical, and economic data. A study of the Muddy Sandstone in the Powder River basin illustrates an exploration application of computer processing a large well-data file. Prior to the discovery of Bell Creek, data from the file revealed areas in Wyoming and southeasternmost Montana with abundant hydrocarbon shows in the Muddy Sandstone. North and South Dakota and the rest of Montana had oil shows in the Muddy Sandstone. In the area of abundant shows geologic maps based on formation tops obtained from the file indicated trends on which subsequent drilling has discovered more than 525 million bbl of reserves. Two types of depositional areas favorable for hydrocarbon occurrence were indicated. One was related to deposition around a pre-Muddy positive feature defined by Skull Creek structure and isopach residual maps of the Muddy Sandstone. The other was a channel system defined on an isopach residual map. Approximately 750 wells have been drilled in the no show area without discovering commercial oil. At the time of discovery of Recluse and Bell Creek, information was available within the Rocky Mountain Well History Control System to suggest areas favorable for similar types of production from the Muddy. With addition of new well control and proprietary information, the well-data file can aid in the planning of development drilling, analysis of completion practices, and reservoir evaluation. Large well-data files and proper application of the computer to these data will become increasingly important in the discovery of oil and gas during the 70's. End_of_Article - Last_Page 1784------------

Geophysical Evidence of Untapped or Insufficiently Explored Parts of Stratigraphic Sections: ABSTRACT

Beginning with the development of the seismic-reflection method of geophysical profiling about 1930, blanket-type surveys were begun in which a crew (or crews) was placed in a prospective area with the assignment to map the subsurface. The survey progressed section by section, township by township, and county by county, mapping regional features as well as local detail. The objective was to be there first and to acquire acreage on interesting structures. Those organizations without the financial ability to carry on such programs, or who were late in arriving in the area, learned early that acreage acquisition in an active area even without geophysical or geological information was good protective strategy. Those organizations which acquired strong land positions so ofte obtained positions of power that land acquisition and the land departments who created this position became dominant factors in the industry. About 1950, so much of the acreage in recognized oil provinces are leased that little incentive remained for conducting blanket or regional-type surveys. Because of the lack of available acreage and other economic factors, geophysical has prospecting degenerated into individual prospect analysis. This forced change in exploration philosophy has been a large contributing factor to the decrease in geophysical activity. Unfortunately, the instrumentation and techniques used in the blanket-survey era were inadequate for some areas and some exploration problems. Many of the improvements in seismic-instrumentation and seismic-prospecting techniques have been made possible by developments in government-sponsored research and these improvements were developed too late to be applied to the blanket survey. The quality of analyses of the untested producing potential of some of the important basins of the Mid-Continent area depends on the quality of regional studies and regional information. The cost of obtaining this type of data is great and beyond the financial resources of the average company. Recognition of this problem has led to the formation of exploration combines of one type or another for the express purpose of acquiring quality data of regional type. Even though surveys of this nature are scarce, and data available to a limited number of people and organizations, the impact of these studies on new discoveries is considerable and will become much more of a factor in the immediate future. Geophysical evidence is rapidly being accumulated which eventually will lead to the disco ery of new producing trends and to the redrawing of regional maps. End_of_Article - Last_Page 1690------------

Developments in Arkansas, North Louisiana, and East Texas in 1965

During 1965 there were 359 wells drilled in Arkansas, a decline of 7.9% from 1964. Of the successful completions, 113 were oil productive and 46 were gas productive. From these successes, 8 new oil fields, 2 new gas fields, and major extensions to 3 gas fields were established. All of the gas discoveries and extensions were in the Arkoma basin of northern Arkansas. The overall drilling program in Arkansas was 44.3% successful; wildcat wells were 12.0% successful. Total footage drilled was 1,530,240, a decline of 4.5% from 1964. Increased geophysical activity and strong leasing activity indicate an increase in exploratory drilling in 1966. In North Louisiana, 2,640 wells were drilled, 299 less than in 1964. There were 1,220 oil wells completed, 300 gas wells, and 1,120 dry holes. Wildcatting accounted for 348 completions. Total footage drilled was 9,854,958, an increase of 1,171,028 ft. from 1964. The number of fields discovered was much less than the number for 1964. A total of 13 new oil fields and 2 new gas fields was discovered, compared with 22 oil fields and 6 gas fields for 1964. There were 8 oil fields discovered in Concordia Parish, 2 in LaSalle, 1 in Caddo, 1 in Catahoula, and 1 in DeSoto. Gas discoveries were made in DeSoto and Sabine Parishes. Eleven of the oil discoveries were in the Wilcox Group reservoirs, and 1 each was in the Paluxy Sand and Pettet Formation. Two gas fields were discovered in reservoirs of the Tuscaloosa and Tokio Formations. Increased geophysical work and much stronger leasing activity indicate an increase in exploratory drilling in 1966. In East Texas, 229 wildcats and 824 field wells were drilled, an increase of 49 wells above 1964. However, new-field discoveries totaled only 15, a decrease of 6. New-pool discoveries made a substantial gain, but geophysical activity and acreage acquisition decreased. The major interest continues to be in the Smackover trend and in field development in the Sabine uplift area.