Condensate Reserves Research Articles

Geochemical variations among eastern Saudi Arabian paleozoic condensates related to different source kitchen areas

Large reserves of gas and condensate are found in Paleozoic reservoirs (Khuff, Unayzah and Jauf) in the Ghawar area of eastern Saudi Arabia. The source rock for these hydrocarbons is the basal organic-rich “hot shale” of the Qusaiba member of the Silurian Qalibah Formation. This is the same prolific source rock that generated the sweet light crude oil and condensate found in the Unayzah reservoirs in central Saudi Arabia. Thermal maturity modeling of the source rock identifies two kitchen areas: to the east and west of the Ghawar structure. The west kitchen was well into the oil window by 210 Ma, while the east kitchen was just entering the oil window. Large areas of both kitchens were in the wet gas window by 125 Ma and by 90 Ma most of the area north of Ghawar was generating dry gas. In eastern Saudi Arabia, Paleozoic oil and condensate are found in early-formed structures (Carboniferous and early Triassic growth), whereas late Cretaceous and Tertiary structures contain only dry gas. The geochemistry of the oils and condensates indicates two groups, each generated from a different hydrocarbon kitchen, suggesting that the two kitchens differ slightly in organic facies. Within each group, variations among hydrocarbons are related to the thermal maturity of the source rock during generation. Within the Khuff reservoir, gas souring is caused by thermochemical sulfate reduction.

THE PERSEUS FIELD, NORTH WEST SHELF, AUSTRALIA: A GIANT GAS ACCUMULATION IN A COMPLEX STRUCTURAL/STRATIGRAPHIC TRAP

The Perseus Field contains reported expectation (proven plus probable) dry gas and condensate reserves of 6.48 TCF (183 × 109 m3) and 165.7 MMBBL (26.3 × 106 m3), respectively, in a complex structural/stratigraphic trap. Gas is predominantly reservoired in Bathonian shallow marine sandstones of the Legendre Formation which subcrop the Upper Jurassic-Lower Cretaceous 'Main Unconformity' in a graben separating the Goodwyn and North Rankin horsts. The Lower Cretaceous Muderong Shale forms the main regional top seal. The Lower-Middle Jurassic Athol Formation forms the seat seal for the Perseus trap and subcrops the Main Unconformity northwest of North Rankin. The maximum gross gas column for the field is approximately 360 m. The Athol Formation and underlying Murat Siltstone also form the topseal for the small Searipple Field, which underlies Perseus.The Perseus trap is dip-closed to the northwest. A steep fault scarp forms the southern margin of the trap. Trap integrity is dependent upon fault seal along the western flank of the field, where the reservoir section is juxtaposed against Athol Formation claystones in a long narrow fault block downthrown from the Goodwyn block. At the southwestern corner of the field this fault block is absent and the Perseus reservoir is juxtaposed against Triassic reservoir section in the Goodwyn block.The NRA22 well, drilled from the North Rankin A platform, has been producing gas from the Perseus Field since mid-1991. Reservoir pressure measurements and production history data have been of immense value in the exploration and appraisal of this field, both in driving further drilling and in understanding the results. Integration of geoscientific and engineering data and expertise within a multi-disciplinary team was essential for the efficient appraisal and evaluation of the field.

Iran's Huge Condensate Reserves

Iran's Huge Condensate Reserves

Silurian Shale Origin for Light Oil, Condensate, and Gas in Algeria and the Middle East: ABSTRACT

Two of the largest gas fields in the world, Hasi R`Mel, Algeria and North Dome, Qatar, also contain substantial condensate and light oil reserves. Gas to source rock geochemical correlation is difficult due to the paucity of molecular parameters in the former although stable isotope composition is invaluable. However, by correlating source rocks with light oils and condensates associated with gas production using traditional geochemical parameters such as biomarkers and isotopes, a better understanding of the origin of the gas is achieved. Much of the crude oil in the Ghadames/Illizi Basins of Algeria has long been thought to have been generated from Silurian shales. New light oil discoveries in Saudi Arabia have also been shown to originate in basal euxinic Silurian shales. Key sterane and terpane biomarkers as well as the stable carbon isotopic compositions of the C15+ saturate and aromatic hydrocarbon fractions allow for the typing of Silurian-sourced, thermally mature light oils in Algeria and the Middle East. Even though biomarkers are often absent due to advanced thermal maturity, condensates can be correlated to the light oils using (1) carbon isotopes of the residual heavy hydrocarbon fractions, (2) light hydrocarbon distributions (e.g., C7 composition), and (3) compound specific carbonmore » isotopic composition of the light hydrocarbons. The carbon isotopes of the C2-C4 gas components ran then be compared to the associated condensate and light oil isotopic composition.« less

Oil and Gas Reserves and Resources of the Mediterranean Countries

The littoral States of the Mediterranean belong to very different geographic and geological units, giving rise to a wide variety of landscapes and petroleum potentials. The provinces of the European margin, deeply marked by the Alpine orogeny, exhibit a wide variety of Secondary and Tertiary basins, often richer in gas than in oil, especially in Italy. Those of the African margin, which advanced to varying degrees into this continent, display stages from the Primary to the Tertiary, with rich basins in the Sahara, Algerian Tunisia, Libya and Egypt. On the eastern margin, Syria has several petroleum zones at the periphery of the large Mid-East Basin. These basins, and particularly those of the northern margin, have been the subject of intensive prospecting. This has allowed the discovery of some 11.4 Gt of oil and 8400 G.m3 of gas, with the share of the countries of the African margin accounting for 86% and 82% of the total respectively. The future discoveries that can be reasonably anticipated can be expected mainly in the African margin, and the Syrian basins. On the whole, oil and condensate reserves of about 3 Gt and gas reserves of some 4000 G.m3 appear probable. The deep offshore Mediterranean does not appear likely to contribute a significant share of these future discoveries at least in the medium term, given the extreme water depths. These prospects of future discoveries, slightly less than present proved reserves, would help to raise the number of years of production at the present rate from 26 to about 40 for oil and condensate, and to double the years of production of gas, which would be increased to slightly over a century. Although these figures appear fairly significant, they are still far below those of the Middle East.

Petroleum Basins of Sakhalin and Adjacent Shelf

Sixty-seven oil and gas fields have been discovered on Sakhalin and the adjacent shelf but the distribution of fields is uneven in north Sakhalin, south Sakhalin, and the Tatar basins. The sedimentary cover is composed of sandy, clayey, and siliceous rocks, with volcanogenic and coal-bearing deposits of Upper Cretaceous, Paleogene, and Neogene 8-12 km thick. Marine clayey and siliceous oil source rocks are regionally developed in the section at different stratigraphic levels; the organic matter is of mixed type and the content varies from 0.5 to 1.5%. The upper Oligocene and middle-upper Miocene source rocks in the north Sakhalin basin are typical, and the organic carbon content ranges from 1 to 5%. The level of organic matter catagenesis and conversion into hydrocarbons is high because of the high differential geothermal gradient in the basins, 30-50[degrees]C per km. Porous sandstones in the Miocene form the reservoirs in all fields with the exception of Okruzhnoye, where the pay zone is a siliceous claystone. Growth-fault rollovers and anticlines form the main traps ranging in area from 5 to 300 km[sup 2], with amplitudes between 100 and 600 m. both stratigraphic and structural traps have been identified. Considerable volumes of reserves are associated withmore » the Miocene deposits of north Sakhalin, which are characterized by an optimum combination of oil source rocks, focused migration paths, and thick sequences of reservoirs and cap rocks. Six large fields have been discovered in the past 15 yr. Oil and condensate reserves stand at over 300 million MT, and gas reserves are about 900 billion m[sup 3].« less

THE SUDANESE RED SEA: 2. NEW DEVELOPMENTS IN PETROLEUM GEOCHEMISTRY

From the limited analytical data which is available from the study area, it appears that the Mukawar and Hamait Formations, sandy facies of Upper Cretaceous and Cenozoic age, have little or no hydrocarbon source potential. However, of the twelve Sudanese Red Sea wells, only one penetrated the Mukawar Formation. and the Hamamit is only known in four wells.On the other hand, the lower to middle Miocene Rudeis. Kareem and Belayim Formations were penetrated in several wells. and may have actually generated black oil in attaining their current levels of thermal maturity. The middle to upper? Miocene Dungunab Formation, which is equivalent to thesouth Gharib Formation of the Gulf of Suez. contains thin. regionallyextensive, intra‐evaporite shales. These are early‐mature in coastal areas but, if developed in the deeper offshore. are likely to be post‐mature and are likely to have generated hydrocarbons. The zeit Formation is of variable thickness. the maxima coniciding with areas of deltaic influence. Although information is limited, it appears that occasional thin shales units may have significam source potential. The areas of more concentrated deltaic sedimentation with in the Zeit Formation are more likely to provide gas‐prone source rocks. The Plio‐pleistocene Abu Shagara Group has no oil source‐potential in the nearshore areas. Potential may improve further offshore. where it is possible that these marine sediments may be richer in organic matter and have been subject to higher heat flow.Hydrocarbon generation in the Sudanese Red Sea had been influenced by many factors in addition to rift‐controlled subsidence. These include the high thermal conductivity of evaporites, tectonic overpressuring and, in deeper waters, significantly higher levels of heat flow. Lower to middle Miocene source rocks are likely to have generated hydrocarbons at the end of Miocene times, whereas younger source rocks could be generating hydrcarbons at the present.The source of gas in the Suakin‐1 gas‐condenstae and Bashayer‐1 dry gas discoveries is probably in the lower part of the Zeit Formation, an organically‐rich deltaic facies. The condensate at Suakin‐1 is likely to have been sourced from the inter‐evaporitic shales of the underlying Dungunab Formation. Black‐oil shows have been recorded at several Sudanese Red Sea wells and a significant gas‐condensate discovery was made at Barrqan‐1 in the northern part of he Saqdi sector. It has been suggested that reserves of condensate may be as high as half a billion barrels. Oil seeps on the Dahlac and Farasan Islands in the Ethiopin and Saudi sectors provide further grounds for an optimistic view that generation of commercial volumes of oil in the Sudanese Red Sea cannot be ruled our

North Pecan Island Field: a Mature Trend Discovery in Miocene of Southern Louisiana: ABSTRACT

The Exxon 1 M. J. Epley discovery well for North Pecan Island field was completed in early 1982 as a discovery of significant new gas and condensate reserves in the mature Miocene trend of south Louisiana. The field is located in Vermilion Parish within a large megablock between 2 major down-to-the basin growth-fault systems and is on the southern end of a south-plunging structural nose. Traps in 2 fault segments are formed in southeasterly dipping beds upthrown to 2 north-dipping, sealing faults. Six separate Robulus chambersi sandstones contain gas and condensate reserves. Major gas and condensate reserves from sandstone reservoirs in the R. chambersi section were discovered in the mid-1960s 3.3 mi. west in the Pecan Island field and in the North Freshwater Bayou field, 5 mi northeast of the North Pecan Island field discovery. Several earlier dry holes just north of the discovery were drilled seeking to extend production from the upstructure Fire Island field (3 mi north), which produced a limited amount of gas and condensate from R. chambersi sandstones. Extensive structural and isopach mapping, aided by new high-resolution seismic data, revealed the North Pecan Island prospect to be structurally high to production at Pecan Island and that the prospective section was deposited over a growing paleostructure. Four wells have been completed to date in the field, with flow rates as high as 30 MMCFGD. Current estimates place the new field recoverable at approximately 250 bcf of gas and 6 million bbl condensate. End_of_Article - Last_Page 236------------

The Secondary Recovery Project at Ogharefe Field, Nigeria

A secondary recovery project involving water injection and gas-lift facilities was installed in the Ogharefe field in 1979 following detailed reservoir simulation studies. Two years' operation provides the opportunity to discuss the progress of the project so far.

You Ain't Seen Nothing Till You've Seen the Tuscaloosa!: ABSTRACT

The Baton Rouge megastructure, a giant structural complex at least 20 mi (36 km) long and 15 mi (24 km) wide, is emerging as the dominant one of several exceptionally large structural features in the Tuscaloosa gas trend. False River reservoir A and reservoir B, Profit Island, Irene, and Port Hudson fields, all large fields in themselves, are merely separate structural closures and fault blocks on the partially explored megastructure. Other fields will surely be found within the 300-sq-mi (780 sq km) area presently indicated to be productive. The Judge Digby megastructure, a slightly lesser feature just west of the Baton Rouge megastructure, also contains major gas reserves. These two represent the largest structural features currently known in the trend. Indicated reserves on these two megastructures total approximately 17.5 Tcf of gas and 1 billion bbl of condensate, representing 1/12 of the United States gas reserves and 1/30 of the United States crude oil or condensate reserves. Across south Louisiana the trend has the potential of producing at least 50 Tcf of gas and 2 billion bbl of condensate. End_of_Article - Last_Page 1598------------

PETROLEUM RESOURCES OF QUEENSLAND

Queensland produces oil mainly from the small Moonie and Alton fields in the Surat Basin. Proven reserves of these two fields were 3262 m3 × 103 initial recoverable. Production began in 1964, after completion of a pipeline, 300 km long, from Moonie to Brisbane. The rate peaked at about 1600 m3 per day, but has since declined to about 200 m3 per day. With the exception of the fields presently supplying the pipeline, virtually no other appreciable reserves of oil or condensate are known in the State.Gas is produced from a group of small fields near Roma in the Surat Basin and underlying southern Bowen Basin. Proven reserves were 4573 m3 × 106 initial recoverable. Production for other than local use in town lighting (1906), condensation for motor fuel (1928–1931) and electricity generation (1961 –) did not begin until 1969, when a pipeline 450 km long was completed to Brisbane. The rate is currently about 0.83 m3 × 106 per day. In addition to those at Roma, reserves of gas are also known in small fields: in the Surat and southern Bowen Basin near Surat (about 80 km south of Roma); in the Bowen Basin near Injune and Springsure (respectively about 80 km and 280 km north-northwest of Roma); in the Adavale Basin; in the Queensland portion of the Cooper Basin. Exploration has been intensive only in parts of the Surat and southern Bowen Basins. Accordingly, persistent efforts in selected areas are likely to lead to success. The more prospective basins in Queensland are considered to be the Adavale, Bowen, Cooper, Galilee, Georgina, and Surat.

Petroleum Developments in Australia and Oceania in 1971

Exploration activity decreased overall in Australia during 1971 relative to 1970. Drilling was considerably reduced, there being 67 wildcats in 1971 versus 112 in 1970. However, significant exploration advances were made in the onshore Cooper basin in South Australia and in the offshore northwest shelf of Western Australia. Five new gas fields and 1 oil field were discovered in the Cooper basin. Preliminary data and several successful tests indicate gas and gas condensate reserves of possibly giant magnitude in the offshore Rankin area of Western Australia. Elsewhere in Australia, exploration activity was at a low ebb, including the prolific offshore part of the Gippsland basin in Victoria. In the Gippsland basin, however, very significant development activities occurred ith continued drilling of development wells on the giant Kingfish field. Gippsland basin offshore production was approaching 300,000 BOPD at the end of 1971. New exploration frontiers were opened in the Southwest Pacific (Oceania) area east of Australia with the drilling of 2 deep stratigraphic tests (Kumifonua 1 and 2) in the Tonga Islands.

Estimation of Primary Oil Reserves

Published in Petroleum Transactions, AIME, Volume 207, 1956, pages 182–191. Abstract This paper reviews the methods currently in use for estimating primary oil reserves and discusses the principles on which these methods are based. Particular emphasis is placed on how these methods change with the type of information available during the life cycle of an oil property. This paper contains various novel estimating methods and shortcuts heretofore unpublished. Introduction Estimating oil reserves is one of the most important phases of the work of a petroleum engineer since the solutions to the problems he deals with usually depend on a comparison of the estimated cost in terms of dollars, with the anticipated result in terms of barrels of oil. His recommendations to management regarding the best course of action are therefore normally based on the most favorable balance between these two. Specific engineering problems which require such a knowledge of recoverable oil reserves and a projection of future rates are:the exploitation and development of an oil reservoir;the construction of gasoline plants, pipelines and refineries;the division of ownership in unitized projects;the price to be paid in case of a sale or purchase of an oil property, and the magnitude of the loan which it will support;the proper depreciation rate for the investment in oil properties; andevaluation of the results of an exploration program. This discussion will be confined to the various methods and tools which are currently in use for estimating oil reserves to be obtained during the primary phase of an oil-producing reservoir and for a projection of the future production rates. Reserves which may be obtained by secondary recovery methods or fluid injection programs and gas and gas condensate reserves will not be discussed in this paper.