Abstract Newfoundland and Labrador is a proven petroleum province with discovered offshore resources of 1.6 billion barrels of oil, 8.2 trillion cubic feel of gas and 360 million barrels of natural gas liquids. Discoveries to dale include sixteen oil and gas fields on the Grand Banks and five gas fields on the Labrador Shelf The majority of the oil resources are contained in four fields, Hibernia, Terra Nova, Whiterose and Hebron.. The Hibernia field is nearing its production phase and the Terra Nova field is moving towards development. The results of recent offshore land sales and exploratory drilling in western Newfoundland point towards increasing exploration activities over the next several years both on the Grand Banks and off the west coast of the Province. This paper discusses the prospects for development of Newfoundland's large hydrocarbon base and examines the new areas being explored offshore Newfoundland. It is not unreasonable to predict production of over 200,000 barrels of oil per day toward the end of the decade from the Newfoundland offshore area. Furthermore, these developments will contribute substantially to Canada's security of supply objectives, while at the same time providing a much needed boost to the Province in terms of employment and industrial development. Exploration History The offshore region of Newfoundland and Labrador covers an area of approximately 185 million hectares. Geological and geophysical surveys conducted by research institutes and government in the 1950's indicated that the region has potential to be a major petroleum province. As a result, the petroleum industry started exploration in the region. The first well was drilled by Amoco and Imperial Oil in 1966. Since that time, companies drilling off the coast of Newfoundland and Labrador have made twenty One significant oil and gas discoveries. Sixteen discoveries on the northeast Grand Banks contain an estimated 1.6 billion barrels of oil. Recoverable resources off the Labrador coast are estimated at 4.2 trillion cubic feet of gas and 123 million barrels of natural gas liquids. To date, 142 wells have been spudded, with companies spending approximately ﹩4 billion on drilling, seismic, and other work. The peak year for exploration off Newfoundland was 1985 when approximately ﹩600 million was spent drilling 12 wells. A large part of the positive projections in Newfoundland's petroleum sector is based on these overall estimates of potential reserves. In February 1995 the Atlantic Accord, a memorandum of agreement between the Government of Canada and the Government of Newfoundland and Labrador on offshore oil and gas management and revenue sharing, was signed. This agreement ended years of dispute between the two governments on the subject of control of offshore petroleum resources. The two governments now equally share the responsibility for the management of the resource which is undertaken through a joint agency, the Canada Newfoundland Offshore Petroleum Board (C-NOPB). The Board's responsibilities include: issuance and administration of petroleum exploration and development rights and administration of statutory requirements regulating offshore exploration, development and production activities. The Board is mandated to operate independently and is required to keep both governments informed of developments (Figure 1).

Abstract The phenomenon of wettability shift to an oil-wet behavior and reduced relativepermeability to oil at high temperatures due to steam injection in the cyclicsteam (CS) process was identified as one of the factors responsible for theless than expected performance at the Elk Point Cummings formation. This paperreports on the results of a laboratory investigation and on the discovery of amethod as well as its field implementation to prevent wettability shifts atelevated temperatures. The contact angle experiments revealed that awettability transition to an oil-wet state occurred at elevated temperatures inthe rock-fluids system consisting of a quartz crystal surface, Lindbergh crudeoil and synthetic brine that represented a mixture of steam and formationwater. A mechanism is proposed to explain temperature dependence of reservoirwettability by applying a Zisman-type correlation and thin wetting filmstability considerations. It was discovered during this experimental investigation, that the wettabilityreversal at elevated temperatures could be prevented. As the temperature in thecontact angle cell was increased. calcium carbonate ( 3 ), due to itsdecreasing solubility at higher temperatures, precipitated onto the quartzcrystal surface. This deposition of calcite particles on the crystal surfaceimparted an oil resisting nature and a strongly water-wet behavior to thesurface even at elevated temperatures. The effectiveness of this discovery onimproved oil recovery was further confirmed through core floods with andwithout 3 precipitation. The discovery was then field tested in anElk Point cyclic steam pilot well. This paper reports for the first time, boththe laboratory and field results of the wettability control technology forproductivity enhancement in thermal enhanced oil recovery. Introduction Considering the enormous resource base of 425 × 10 9 m 3 ofheavy oil and bitumen in western Canada, Millet (1994) concludes that the oilproduction business will eventually be working mainly with heavy oils andbitumens. Lloydminster heavy oil belt alone is estimated to contain 3.1 ×10 9 m 3 of oil-in-place with API gravity ranging from 16to 24 ° and viscosity in the range of 100 to 400 mPa.s at reservoir conditions(Polikar et al., 1993). Cummings is one of tbe extensive formations in the Lloydminster heavy oil belt and contains a 13 ° API heavy oil with a stock-tankoil viscosity of about 10,000 mPa.s at reservoir temperature of 24 °C. Theimmense magnitude of the original oil-in-place makes the Cummings reservoirsprime candidates for improved oil recovery processes with potential forsignificant economic benefit through incremental oil recovery over primaryproduction. PanCanadian's experience with good primary production as well as the reservoirresponse to cyclic steam (CS) pilot tests at the Elk Point Cummings formationhave been recently presented (Karyampudi, 1995). Some of the productionperformance characteristics observed during these CS pilot tests at Elk Pointwere the absence of a peak in oil production rates (that is normally expectedearly in the production phase) and the unexpectedly high water cuts during thefirst and subsequent cycles. The main reason for these trends was initiallysuspected to be a shift in wettability of the near-wellbore region to anoil-wet behavior at elevated temperatures encountered during the steaminjection phase.

Abstract An immiscible CO 2 slug and carbonated chase water enhanced oilrecovery process is being investigated at the shallow, light oil Salt Creek Field in Natrona County, Wyoming. This 100-year-old giant has had variousimproved recovery techniques, whose residual effects impact future tertiarypotential. Salt Creek currently produces over 10 HBOPD (1590 m 3 /d)with a cumulative recovery of about 630 MMBO (1.00 × 10 8 m 3 ). In an immiscible CO 2 process, part of the injected CO 2 isabsorbed into the reservoir fluids while some of the CO 2 forms afree gas phase in the reservoir. Tertiary recovery of the light crude underthis process is sensitive to the reservoir crude composition, temperature andpressure. Gravity drainage, gas cycling, and localized excess NGL product injection havecaused significant areal variations in the intermediate hydrocarbon compositionin Salt Creek's major producing zone, the Second Wall Creek (WC2). Structuralrelief of 1,500 feet (457 m) and 33 years of variable temperature waterfloodinghave likewise caused reservoir temperature variations. Finally, althoughwaterflooding has restored the pressure depleted reservoir to near originalconditions, it has caused local pressures to vary, not only with structure, butalso with nearby injection and production bottom hole pressures. In general, light oil recovery improves under an immiscible CO 2 process as reservoir pressure increases, reservoir temperature decreases, orthe percentage of intermediates in the oil increases. Thus cooler injectedwater increased reservoir pressure, and high grading of process areas based oncrude composition should improve tertiary performance in the Second WallCreek. A 17.8-acre (7.20 ha) immiscible CO 2 pilot has been designed and isexpected to be initiated in the 1990s. If the: pilot is successful, implementing this tertiary process should improve field recovery and extendfield life. General History Salt Creek Field is located in northeastern Natrona County, Wyoming, about 40miles (64 km) north of the city of Casper. Oil at Salt Creek is produced fromtwo distinct domes on a 20 mile (32 km) long anticline. The smaller, southernstructure is best known as Teapot Dome while the larger, northern dome is SaltCreek Field. 1 Figure 1 shows the location of the field, a type logand the structural contours of the Second Wall Creek sandstone. Eleven horizonshave been productive at various times in the field's history (see Table 1).Figure 2 summarizes 100 years of all production history for the entire SaltCreek Field. In 1884 Aughey reported 2 oil in the Salt Creek area when he found anoil spring in the bed of Salt Creek - an intermittent stream running throughthe Salt Creek Dome. 3 The Salt Creek Field discovery well wasdrilled in late 1889 by P. M. Shannon of the Pennsylvanian Oil and Gas Company, and completed at a rate of 4 BOPD (0.6 m 3 /d) in the Shannonsandstone. 4 This well was located about 1 ¼ miles (2.0 km) north ofthe present day boundary of the Salt Creek Unit (see figure 1).

Abstract The cost of finding hydrocarbons to replace depleting reserves is one of the major concerns of the Canadian petroleum industry. Its importance to the profitability of the industry is self-evident. However, despite this importance, the difficulties incumbent in determining it precisely have either deterred extensive analysis or minimized the value of the analysis that has been done. The purpose of this paper is to outline a methodology estimate Alberta erode oil, natural gas, and crude-oil-equivalent finding costs, to present the results of the analysis, and to identify key implications of these results for both industry and governments. Inherent Problems The determination of finding cost should be a simple calculation: the total exploration costs incurred in discovering reserves divided by the total reserves discovered. However, this simplicity is immediately lost when one tries to match the appropriate expenditures to given discoveries. Moreover, since the initial reserves estimate typically increases as the find is developed, the true size of the discovery is often not known with any degree of certainty until several years afterward. These factors make an initially simple calculation very complex. Nevertheless, finding costs may be estimated by careful analysis of both the reserves and the expenditures data to determine how they should be employed in the calculation. Reserves Data Data on reserves by year of discovery are published annually by the Canadian Petroleum Association (CPA). Using a methodology suggested by Arrington and Megill, it is possible to estimate the rate of growth of the initial reserves estimates. Application of this technique using the CPA data for the 1970 to 1983 period indicates that reserves of oil and gas appreciate from the initial estimate by factors slightly greater than 3 (CERI, 1985). Finding cost calculations can be based on the CPA reserves data. However, the data present some difficulties in that as of year-end 1984, the CPA adopted the reserves estimates of the Alberta Energy Resources Conservation Board (ERCB) for small oil and gas pools, including some small pool discoveries that had previously been excluded from the CPA data. Preliminary analysis indicates that the variations in the initial reserves estimates of the two data sources are now very small given the change in the CPA methodology. Some differences in initial estimates will continue but these could be attributed co the different reporting procedures of the two agencies (e.g., the possible discretionary time lag in reporting discoveries by CPA member companies). RESERVES APPRECIATION As previously mentioned, the initial reserves booking underestimates the true size of the reserves discovered in that reserves do appreciate as development occurs. One way to account for this is to apply an appreciation rate to the initial booking to estimate the "true size" of the discovery. An appreciation rate is a measure of the amount by which an initial reserves discovery increases over time and, as such, is a critical factor in the calculation of finding costs.

SUMMARY AND CONCLUSION Canada's east coast play is worthy of the investor's consideration, as it still affords him the opportunity of participating at a relatively early stage in the area's exploration history. All multi-billion dollar world energy projects contain many inherent uncertainties which cloud the investment picture. Canada' s east coast is no exception. We have attempted to summarize these points for consideration: Negative Features the potential Canadian jurisdictional problem on ownership; the potential international ownership through the Law of the Sea Conference; the tax features which will replace the super depletion allowance, and the date they will become effective; stringent Newfoundland and Nova Scotia regulations; the technical problems associated with discoveries on the Labrador Coast and Davis Strait; and the National Energy Program. In comparison, we believe that the positive considerations to this play dwarf the present negative uncertainties. Positive Features the size of Canada's east coast offshore area, in relation to the drilling activity and results that have taken place to date; the relatively short period of time before production could commence from the Grand Banks and the Scotian Shelf areas; the development costs in relation to the estimated daily production volumes; the ready natural markets for both oil and gas; future drilling results (which can be both positive and negative); the estimated rate of return; and the potential rewards. FOREWORD Fish and lumber, the two principal staples which have played such a significant role in the economy of Atlantic Canada are about to be joined by a newcomer: petroleum, which will permit the region finally to obtain its long desired goal of a fully supportive economy. Many authorities believe that the Hibernia discovery well could become as famous as the 1947 Leduc wildcat which placed Alberta on the world oil map. The Canadian Government has termed Hibernia "the most significant discovery ever made in the Canadian offshore". Merrill Lynch Royal Securities Limited believes that the Hibernia discovery has made the east coast of Canada the number one offshore play in the world, and that it will remain so in the near future. With continued unrest in the Middle East, the importance of oil and gas reserves on Canada's east coast will obtain increased investor recognition. Although it is the government's intention to increase crude oil imports from Venezuela and Mexico, the Persian Gulf countries will continue to be the dominant supplier. Investor interest in the east coast play will primarily focus on oil; a field offshore Newfoundland with recoverable reserves of one half to one billion barrels will have immediate possibilities. Production could be on stream in four to five years, as natural markets are at hand. A natural gas discovery of sufficient size on either the Scotian Shelf at offshore Prince Edward Island would also be favourably considered. Production could commence within a reasonable time due to the fact that markets are at hand.

Abstract Exploration in the Beaufort required technological development and has resulted in commercial discover1es. The physical environment of the Beaufort has shaped the exploration systems and will influence the design of development systems. Development will follow from the successful exploration methods, and will be dependent on the establishment of a transportation system. Feasible transportation modes are the pipeline and icebreaking tanker. both of which may find applications. Technical challenges exist in the establishment of both modes. The paper describes some of the systems considered for development scenarios and discusses associated problem areas. AREA OF INTEREST One of Canada's most prospective frontier areas is 100,000 square kilometers in the northwest extremity of the land consisting of the Mackenzie Delta and the Beaufort Sea. It is convenient to view this as a single area not only because it is a single sedimentary basin but al so because its remoteness from markets and its unique environment pose common problems. Its hydrocarbon potential is great, with an estimated 1.5 billion cubic meters of oil and 2 trillion cubic meters of natural gas. ENVIRONMENT The physical environment has shaped the exploration systems. The lattice towers, jackups and submersibles used for exploration elsewhere in the world lack the strength required to resist the loads of the sea ice. The remoteness of the location precludes mobilizing far the summer season and relocating during the Winter, as has been the practice off the east coast. The production and transportation systems will be similarly influenced. The low temperature prevailing for 9 months of the year affects the overall efficiency of men and machinery, as well as causing the direct problems of ice, permafrost and brittleness in steel. A high value is placed on preservation of wildlife. The interest of the native peoples is obvious, as they derive a significant part of their livelihood from hunting. There is also a worldwide concern for the continued existence of endangered species. The preservation of habitat, as a necessary condition for survival is the root of much opposition to development projects. Real and perceived dangers to the earth and water result in exclusion areas, controlled access, challenges to right of passage and generally restrictive operating conditions. Some of these considerations will impact on oilfield development and associated transportation projects to a degree comparable to that of the physical environmental constraints. Before any significant project can proceed it must undergo rigorous scrutiny by government bodies. Early in the clearance and approval procedure is a study of environmental impact. At the request of the Federal Government, Esso, with Gulf and Dome, is now engaged in the preparation of an environmental impact statement for Beaufort-Delta production. The intent is to provide sufficient information so that the government may give general environmental clearance far development in the region. Any site specific development would then be required to meet the general conditions of the clearance hut would avoid the long delays inherent in the hearing process.

Abstract In the Lloydminster – North Battleford area the Cretaceous Mannville Group essentially comprises interbedded sands, shales and mudstones. These sediments exhibit a gentle overall dip toward the southwest and a thinning toward the south. The Lloydminster – North Battleford area is the southeasterly portion of a belt in which Mannville sands contain huge quantities of bitumen and heavy crude. The first discovery of crude oil in Saskatchewan occurred in this area near Lloydminster, but progress here has been retarded due to the low demand for heavy oil. However, declining petroleum reserves, together with increased prices, has improved prospects for the exploitation of heavy oil accumulations generally. Mannville oil-bearing strata lying outside administrative pool boundaries in the Lloydminster – North Battleford area are herein estimated to contain approximately 7.4 billion barrels of oil. The derivation of this volume is based upon the examination of electric logs. The reliability of this estimate of oil in place depends upon certain factors and assumptions inherent in its calculation. Introduction The primary intent of this report is a general estimate of heavy oil in place in the most prospective sands of the Cretaceous Mannville Group of the Lloydminster – North Battleford area, Saskatchewan. A brief description of Mannville Group geology is also presented. The study area encompasses Townships 44 to 54, Ranges 15 to 28 west of the Third Meridian plus Townships 38 to 43, Ranges 22 to 29 west of the Third Meridian (Fig. 1). However, areas lying within administrative pool boundaries are excluded from reserve estimates. For this study the method employed involved mainly the examination of electrical logs of wells outside pool boundaries. Due to the paucity of cores and the poor quality of drill samples, along with the need to limit the time requirement, neither cores nor drill samples were examined. The accompanying description of geology is based upon log examination and the writers' previous experience with Mannville sediments. History Of Development Mannville sands near the city of Lloydminster yielded the first hydrocarbons produced in Saskatchewan. A commercial supply of gas was obtained from a well in Tp. 50, R. 28 W3 in 1934, and oil was discovered in 1935. This oil discovery occurred twenty-two years after drilling began in the first major Canadian oil field, namely Turner Valley (Sproule, 1968). Early attempts to commercially produce the heavy crude from Mannville sands in the vicinity of Lloydminster failed. However, an increased price for fuel oil due to the Second World War revived interest in the recovery of this heavy oil. In 1944, the first commercial all production in Saskatchewan was obtained from a well in the Lloydminster area. Since 1944, exploitation of the heavy oil sands in the west central part of Saskatchewan's sedimentary belt has proceeded gradually. The rate of development has been governed largely by market conditions and the price for heavy oil. By the end of 1975, a total of 1332 wells were producing oil in that portion of the province north of Township 37.

Abstract Canada bas been an early participant in the petroleum industry but significant entry into the world oil scene occurred with the Leduc discovery of 1947. Development of the industry since Leduc has resulted in net self sufficiency. To-day there are forces which would wish to push Canada into the role of a net world scale exporter of both oil and gas, primarily to satisfy U.S. needs. This could cause severe economic dislocation for Canada and possibly its disappearance as a separate political entity. The chief agents behind this push are the seven largest oil corporations in the world, Exxon, Shell, Mobil, Texaco, Gulf, B.P. and California Standard, whose incomes individually exceed those of most of the governments in the world. In recent months, particularly after the October 1974 Arab-Israeli conflict, government intervention into the industry on an unprecedented scale took place. This has been resented by the industry. Although governments of all parties have made some mistakes in this intervention, continued overnment involvement in the development of the industry is necessary to protect the Canadian public interest. A new Canadian oil and gas policy must be developed which will not coincide with the wishes of the predominantly foreign owned private corporations. There is a place for private corporations in an accelerated development of conventional sources of oil and gas in western Canada and the east coast. It would not be in the Canadian public interest to permit construction of the Mackenzie Valley gas pipeline at this time. Private interests in the far north should be taken over by the newly legislated National Petroleum Corporation. All developments in the Alberta oil sands should also be taken over by the National Petroleum Corporation, preferably in partnership with an Alberta crown corporation. Provincial crown corporations could be useful flexible tools in stimulating development in the conventional sector. Such a policy would not be welcomed by the industry but that is what Canada needs. Introduction The petroleum industry is the largest wealthiest and most powerful industry in the World. Petroleum is the most important energy source to-day and will continue to be for some time to come. It has been a major factor in politics for a hundred years and has never been more prominent than to-day. Canada has been an early but a minor participant on the world petroleum scene up to now, but this could change drastically in the near future. Pressure is building up to expand the Canadian industry as quickly as possible in order to solve the energy crisis in the U.S. Growth of the industry to fulfill Canadian needs is desirable but explosive growth would cause severe economic dislocation and might even endanger Canada's continued existence s a separate political entity. The chief advocates of' excessive growth within Canada. are the seven largest oil corporations which dominate the world petroleum industry and which individually have greater economic strength than most of the nations of the world. The politics of petroleum will be the dominant politics of the forseeable future for Canada and for the world.

Abstract Discovery of oil and gas in the Arctic may pose the greatest transportation challenge of our time. Airlifting the oil out of the Arctic might be preferable to fighting the environment every foot of the way along the surface. There are several conditions for competitive costs. The airplane should be large to take advantage of economies of scale, a very high utilization of expensive elements of the system must be achieved, and perhaps the cargo should be transferred to a surface mode once it reaches a more temperate climate. Conceptual design studies and preliminary economic analyses indicate an airlift system may provide competitive transportation for oil, natural gas or other resources in some Arctic situations. The Challenge The transportation challenge posed by the discovery of oil and gas in the Arctic is almost unique in history. The challenge comes from a combination of factors: the large quantities of valuable oil and. gas the ready and eager markets, of oil and gas in the Arctic is almost unique in history. The challenge comes from a combination of factors: the large quantities of valuable oil and gas, the ready and eager markets, the hostile nature of the weather and terrain between newly discovered fields and the markets, and increased emphasis by conservationists and world governments on environment. The difficulties anticipated for traditional modes of transportation in the Arctic may be offset to a large degree by application of the pool of technology accumulated by the aerospace industry in meeting other challenges including successfully dealing with the much harsher environment of space. These factors suggest an opportunity for a novel, or at least an unconventional solution. However, the suggestion that airlift may be the most attractive and economical solution requires some explanation. Several simple principles must be combined to understand the logic of the concept. Perhaps a review of the history of the concept is the best way to introduce these underlying principles. BEGINNINGS OF THE CONCEPT The history of Boeing interest in the transportation challenge posed by discovery of Arctic oil and gas goes back to late in the summer of 1969. An old friend stopped in Seattle on his way back to Houston from Prudhoe Bay. He had looked over the North Slope first hand in preparation for making his company's bid in the Alaskan lease auction. He was convinced that getting the oil out would be a major problem and half-seriously asked about the possibilities of airlift. It took only a few minutes minutes and a couple of old envelope backs to convert from current air freight rates to costs per barrel delivered by air to a refinery gate at a major market. The answer was many times the posted price. This was only the first time that I found how easy it is to "prove" that moving oil by air isn't practical Since then, I've seen it done hundreds of times. By the end of 1969, my friend ' s company held Iease rights on part of the slope.

Abstract The Canadian petroleum industry has made impressive gains since the discovery at Leduc in 1947. Rapid growth prior to the Suez crisis of1956 was followed by a period of adjustment culminating in a Royal Commission and the introduction of the National Oil Policy in 1961. During the ‘sixties’, a rapidly expanding domestic economy and this penetration of United States markets resulted in further strong gains in allsectors of the industry. The next five years will witness further impressive gains but also some important changes. While demand for Canadian crude in Canada will rise to over one million barrels a day by 1975, export demand will outstrip domestic demand to reach a level of about 1.3 million barrels a day. Consequently, crudeproduction in Canada will rise by over fifty per cent in the next five years. Explicit in the forecast will be the free access of Canadian crude to United States markets to meet the deteriorating energy position in the United States. To meet future demands, both in Canada and in the United States, considerable investment in theexploration and development of new reserves and additional distribution and refining facilities, will be required. The implications of the forecast include increasing Canadian self-sufficiency in petroleum and a tripling of last year's Canadian foreign trade surplus in crude andrefined products. Beyond 1975 lie such dramatic developments as the exploitation of potential Arctic and East Coast offshore supplies, a pipeline through the Mackenzie Valley, and the tapping of the tar sands. A large proportion of the capital requirements will continue to be imported. The issue of control, however, should not be permitted to inhibit the realization of potential development for Canadians can exercise ultimate control of development through their elected representatives. Introduction The Canadian petroleum industry is about to embark upon one of the most interesting phases since the discovery at Leduc. The large number of issues that face the industry, most of which will be difficult to resolve, makes the exactdestination unsure, but the basic direction will be for Canada's oil to playa much larger role in North America's energy needs than ever before. In the medium term, however, the implications of trends already in progress enable us to project with a rather high degree of certainty the overall prospectsof the industry both within the Canadian market and within its adjacent United States markets. This medium term outlook for the industry was the subject of the Toronto Dominion Bank's sixth biennial study of the industry which was published late last year. As the author of that study, I propose to summerize it; findings, taking into consideration where necessary those events which have since cast more light on the industry's prospective development in the first half of the 1970's. To set the stage for my views as to the industry's prospects to 1975 I would like to review with you its three post-Leduc developmental phases.

Abstract Significant changes in the Worldwide development of the oil industry over the past few years have created the necessity to completely reconsider the overall pattern. Completely new areas of activity have developed as well as renewed interest in existing oil provinces. Among the areas whichfall into these categories are Alaska, The North Sea. West Africa, South East Asia and South America. We will consider here the recent history and likely future development of Indonesia, where a significant proportion of South East Asianactivity is occurring, and South America where a number of recent developments will no doubt lead to changes in the Western hemisphere petroleum energy pattern. With more than five years required to effectively exploit any new development. it is realistic to assume that programs now underwaywill reflect the overall picture over the next few years. With this in mind, progress over the past few years in these two areas is discussed toreflect the expected developments to the immediate future. INDONESIA Prior to World War II, Indonesia was the main oil producing country in South East Asia. After the war, the independent Indonesian Governmentgradually appropriated all of the Shell Holdings, for which they paid compensation. Until the ousting of President Sukarno in 1966, foreign companies were not encouraged to invest in Indonesia; however, the new Government under President Suharto rapidly reversed this policy. Table 1. shows the recent leasing history in Indonesia and illustrates the dramatic changes since 1966. All current oil company contracts in Indonesia are based on a production sharing basis rather than profit sharing. The oil companiesare allowed to recover their capital expenditure, investment and operating costs from the oil produced, but on an annual basis this investment recovery cannot exceed between 35–40% of thetotal value of the oil. The remaining production is split 65–35% in favour of the Indonesia Government oil company P.N. Pertamina. Terms have become increasingly tougher for companies entering the Indonesian play, and latecomers such as Shell, White Shield and Pexa Oil have accepted a profit split as high as 70–30 and agreed to offer 5% of their share capital to the Indonesianinvestment market if production is established. Indonesia's production has increased from approximately 150,000 BOPD in 1951 to 1,000,000BOPD in 1970. This large increase essentially reflects the success of the Caltex operation in Central Sumatra and their prolific Minas field. Caltex currently accounts for 70% of Indonesia's total production. Oil is produced almost exclusively from Tertiary sediments which are situated in six major basins in Sumatra, Java and Kalimantan(Borneo). The probable offshore extensions to these basins motivated the rush to acquire offshore 3creage when leasing recommenced. Drilling began in 1968 and at present there is a very active drilling program in Indonesian waters. A number of commercial oil fields have been discovered in the Java Sea. Atlantic Richfield have three economically productive structures, one of which is already being developed by platform drilling.