bluuebunny/crossref_metadata_2025 huggingface dataset:
THE ZUBAIR FORMATION, EAST BAGHDAD OILFIELD, CENTRAL IRAQ
Authors: Ali A. Jawad , Aziz Z. R.
Published: December 2007

A number of depositional cycles have been defined from the Zubair Formation in central Iraq (East Baghdad field). Each cycle represents the growth of a deltaic lobe (construction phase), followed by a hiatus during which the delta margin was subjected to wave and tidal activity (destruction phase), succeeded by a marine transgressive shale by which the cycle was concluded. When the growth of the deltaic lobe is renewed over a shale base, a new cycle begins.

For each depositional cycle, four facies were identified from sections of core samples. These are: low‐sinuosity (distributary) channels (facies A); marsh (facies B); chenier (facies C); and shelf (facies D). Facies A. B and C comprise the lobe, i.e. indicate a marine regression, whereas facies D concludes the cycle and indicates a transgression.

The sandstones of the Zubair Formation are classified as quartz arenites: they are mineralogically and texturally mature, fine‐ to very‐fine grained, well‐ to moderately‐well sorted, fine‐ to nearly‐symmetrical, skewed and mesokurtic.

The rocks of the source area are acidic‐igneous. The source area, located within the Arabian Shield, underwent successive periods of tectonic renewal giving rise to high values of sediment supply, and lower values during intervening periods. The detrital materials supplied were to a large extent recycled.
THE HISTORY OF HYDROCARBONS EXPLORATION AND PRODUCTION IN ARGENTINA
Authors: Yrigoyen M. R.
Published: December 2007

Sedimentary basins in Argentina cover about 1.4 MM sq. km on land, and 400,000 sq. km offshore as far as the 200‐m isobath. Oil and gas has been produced from six mostly onshore pericratonic basins, all of which belong to the Sub‐Andean domain. Their current daily production amounts to 553,800 brls of oil (of which only 26,500 b/d comes from the offshore) and 2,392 million cu. ft of gas. Currently, proved reserves are around 1,354 million brls of oil and 20.3 trillion cu. ft of gas. Cumulative production to end‐1990 was 5.0 billion brls of oil and 13.7 trillion cu. ft of gas, 93% of which was associated gas.

The most important basins from the viewpoint of current oil production are: Neuquén (yielding 44.5% of Argentina's total output); San Jorge (33.2%); Cuyo (9.9%); Magallanes (or Austral) (9.4%) and Tarija/Orán (3%). Yacimientos Petrolíferos Fiscales (the former Argentine State oil agency. YPF) is the largest operator in the country, with about 48% of daily oil and 64% of daily gas production, and the remaining output comes from private companies. However, this balance is expected to change in the near future as a result of deregulation and privatisation policies being implemented by the Government.
DEPOSITIONAL MODELS OF THE LOWER CRETACEOUS QUINTUCO — LOMA MONTOSA FORMATION, NEUQUÉN BASIN, ARGENTINA
Authors: Carozzi A. V. , Orchuela I. A. , Schelotto M. L. Rodriguez
Published: December 2007

The Quintuco — Loma Montosa Formation is the largest and most diversified oil‐producing carbonate depositional system in the Neuquén Basin. It was mainly deposited during the Early Cretaceous, in an intracratonic embayment of the Andean orogenic belt which extended eastwards over the South American Plate.

Microfacies techniques have revealed that this formation consists of a number of juxtaposed, well‐developed depositional environments, which were from west to east: carbonates (basin, slope, and oolitic build‐up, which developed into an oolitic‐bioclastic platform); then evaporites (lagoonal and sabkha, both with frequent meteoric dolomitization).

These environments shifted in time through several transgressive‐regressive cycles controlled by eustatism and synsedimentary differential subsidence, which originated in reactivated cratonic structures. At all times, the carbonate‐evaporitic environments were surrounded by fringing fan‐deltas. During regressive episodes, these extended basinwards as fluvial, and fan‐delta plain and front facies, terminating with unusual mixed carbonate — fan‐delta slope deposits.

This extremely diversified association of carbonate, evaporite and siliciclastic sediments in the Quintuco‐Loma Montosa Formation overlies the mature, black shales of the Vaca Muerta Formation, which acted as source beds. Each depositional sub‐environment has the possibility of producing oil as a result of various types of secondary burial porosity (preceded in places by intercrystalline porosity produced by meteoric dolomitization), when combined with appropriate tectonic conditions.

In this respect, the Quintuco‐Loma Montosa Formation is the largest and most attractive target for oil exploration in the Neuquén Basin.
THERMAL MATURITY AND SOURCE‐ROCK POTENTIAL OF THE SEDIMENTARY SUCCESSION FROM THE DRAKE FIELD, SVERDRUP BASIN, ARCTIC CANADA
Authors: Gentzis T. , Goodarzi F.
Published: December 2007

The thermal maturity and source‐rock potential of the sedimentary succession in the Drake field, Melville Island, Arctic Canada, have been studied using reflected‐light microscopy and Rock‐Eval pyrolysis. The Mesozoic sediments are immature to mature (% Ro = 0.35‐0.80). Vitrinite reflectance in Cretaceous sediments ranges from 0.35 to 0.56%; in Jurassic sediments, it ranges from 0.40 to 0.66%, and in Triassic sediments, from 0.50 to 0.80%. The Triassic Schei Point Group shales and siltstones contain organic matter of marine origin, whereas the predominantly plant‐derived organic matter present in the Jameson Bay, Ringnes and Deer Bay Formations has higher TOC. Among the Schei Point Group sediments, the Eden Bay Member of the Hoyle Bay Formation has high TOC content (approx. 5.0%) and high HI values (in excess of 600 mg HC/g Corg). It is followed by the Cape Richards Member and the Cape Caledonia Member of the Murray Harbour Formation (approx. 5.0% TOC).

Regional variations in the level of thermal maturity of Mesozoic sediments in the Sverdrup Basin are mainly a function of burial depth. Thermal subsidence, uplift, erosion and heat associated with periods of diapiric and igneous intrusions may have been responsible for the thermal maturity pattern in the Drake field. The Jurassic Jameson Bay, Ringnes and Deer Bay Formations are immature to marginally mature, and have limited oil‐generation potential due to their high terrestrial input. The organic matter is these formations has good gas potential.
COAL RANK AND TYPE VARIATION IN ROCK‐EVAL ASSESSMENT OF NEW ZEALAND COALS
Authors: Suggate R. P. , Boudou J. P.
Published: December 2007

Rock‐Eval and coal analytical data are compared for New Zealand coal samples ranging from peat to medium‐volatile bituminous coal. Most are humic coals within the New Zealand coal band, which is representative of the Type III maturation series defined for kerogens. However, four were chosen as particularly high‐hydrogen coal types. Relations between individual parameters — principally H/C, O/C, Tmax, HI and OI — are generally similar to those of Espitalié et al. (1985, 1986), but important differences include a broader range of HI values in the peats and lignites, and a differentiation between maturation and coal‐type effects in the relationship of HI to H/C. Correlations of the effects of maturation on HI, OI, Tmax and vitrinite reflectance are made by the use of the independent Rank(S) scale of Suggate (1959).

Rank(S)/reflectance relations vary between well sequences. The Rank(S) scale is used to integrate biomarker data on hydrocarbon generation and expulsion. The oil zone (“oil window”) corresponds to the range of bituminous coals, beginning at Rank(S) 10 (Tmax425°C) and ending at Rank(S) 17 (Tmax estimated at 550°C). Release of oil begins at or soon after Rank(S) 12.5 (Tmax 435°C), and culminates in the range Rank(S) 14.5‐ 15.5 (Tmax 460–480°C). For the Taranaki Basin, New Zealand, the results imply that a substantially greater volume of coal measures has been subject to oil generation and migration processes than previously thought.
THE RECOVERABLE OIL AND GAS RESOURCES OF MONGOLIA
Authors: Penttila W. C.
Published: December 2007

The data‐base for this study is mainly unpublished Mongolian and Former Soviet Union reports (1958 to 1989), and studies conducted by or for the Mongol Petroleum Co. (Mongol Gazryn Tos: MGT) (1989 to 1992). A very small amount of data was obtained from published literature. Until 1989, the majority of work on the petroleum geology of Mongolia either condemned the prospects, or suggested that there was only very limited oil and gas potential.

However, the present evaluation, which is based on three years' work by the Author and his associates, supported by Mongol Petroleum Co. explorationists, is that three to six billion brls oil‐equivalent (o.e.) of conventional recoverable oil and gas resources within the territory of Mongolia is a reasonable expectation. The expected “most likely” oilfield size ranges from 100 to 170 million (MM) brls o.e., with the “low” oilfield size ranging from 5 to 10 MM brls o.e. and the “high” oilfield size ranging from 330 to 700 MM brls o.e.

The concepts upon which these estimates are based were derived from Klemme (1980, 1983, 1986); Klemme and Ulmishek (1991); Ulmishek (1986); and Ulmishek and Klemme (1990).
JORDAN REVISITED: HYDROCARBONS HABITAT AND POTENTIAL
Authors: Beydoun Z. R. , Futyan A. R. I. , Jawzi A. H.
Published: December 2007

A thick succession of sedimentary rocks, comprising mainly Paleozoic shallow‐marine and fluvial deposits, and Mesozoic and Paleogene marine carbonates, with subordinate elastics and evaporites, occurs in Jordan. These are preserved in several basins, including: Late Paleozoic inverted basins with thick, Infra‐Cambrian to Silurian successions in the south, east and NE; and younger, Late Cretaceous and/or Tertiary basins in the centre and west, in which Mesozoic marine shelf sediments and/or thick, rift‐related Neogene sediments are well‐developed.

Two regional, organic‐rich source‐rock levels occur. They comprise Upper Ordovician/ Lower Silurian shales in the SE half of the country, and Upper Cretaceous, bituminous chalky marls in the western/central sectors; the former range from immature in the SW to locally over‐mature in the NE, whereas the latter are mainly immature, except where deeply buried, as in the Jordan Valley/Dead Sea rift and part of the Azraq rift. Subordinate source‐rock levels occur in the Triassic and Middle Cretaceous. Numerous hydrocarbon indications, including seeps and floating asphalt blocks, occur in the Dead Sea area and have been correlated with the Upper Cretaceous source rocks.

In spite of these positive indications, only 13 exploration wells have been drilled since drilling first began in the mid‐1950s. The Natural Resources Authority (NRA) has established modest oil and gas production in two fields, mainly through the drilling of well clusters in encouraging areas. Hydrocarbons potential, however, remains good, with play concepts related to the major source levels. Detailed local and regional analytical studies, together with extensive and sophisticated seismic acquisition and processing/reprocessing, are required, however, prior to further drilling, with clear and separate strategies for each of the plays.
THE PETROLEUM GEOLOGY OF CAMBODIA
Authors: Vysotsky V.I. , Rodnikova R.D. , Li Mak Ngion
Published: December 2007

The petroleum geology of Cambodia has been studied less than has that of the neighbouring countries in Indochina. Nevertheless, the results of recent geological, remote‐ sensing and limited seismic investigations (the latter on the Cambodian Shelf area of the Gulf of Thailand) have allowed identification of sedimentary basins favourable for hydrocarbons exploration (both on‐ and offshore), and, consequently, the delineation of prospective areas. Six possibly oil‐ and gas‐bearing basins have been identified, namely: the Siam (northern portion: in the Gulf of Thailand), Tonle Sap, Khorat (southern portion), Preah, Chung and Svairieng Basins.
NIAGARAN REEFS OF NORTHERN MICHIGAN, PART II: RESOURCE APPRAISAL
Authors: Gill D.
Published: December 2007

The ultimate oil and gas resources of the Niagaran pinnacle‐reef belt of northern Michigan, and the likely outcome of future exploration drilling in this play, were estimated using the Arps‐Roberts discovery process model. For each of ten field‐size classes, the parameters of the model are the ultimate number of fields, and a discovery efficiency coefficient (DEC). The parameters are derived from the actual historic exploration record, consisting of a time‐ordered list of exploration drilling and the sizes of the field discoveries. The data‐base consisted of 539 fields that were discovered during 1968–1982 by the drilling of 1,965 new‐field wildcats. The parameters were estimated both by nonlinear least‐squares curve fitting, and by a heuristic “back‐forecasting” calibration procedure. The DECs were found to increase with field size. Within the historic data, the model's emulation was shown to be excellent. The ultimate recoverable oil and gas‐reserves of the belt are estimated at about 1,200 million brls oil‐equivalent (MM brls o.e.), predicted to be distributed in some 920 fields. Of this amount, 1,030 MM brls, reservoired in 539 fields, had already been discovered by the end of 1982. All the fields in the three largest size‐classes were duly discovered by end‐1986. The approximately 200 MM brls undiscovered by that date were believed to reside in about 380 small fields, more than half of which are smaller than 0.25 MM brls. The play is clearly in a very mature stale, and the cost per barrel of finding new reserves will constantly increase.
PROBABLE CRETACEOUS‐TO‐RECENT RIFTING IN THE GULF OF MEXICO BASIN An answer to Callovian salt deformation and distribution problems? Part 1
Authors: Reed J. M.
Published: December 2007

Abundant evidence from the Northern Gulf of Mexico Basin suggests that late Early Cretaceous to Recent sea‐floor spreading is the principal factor in the formation of the structural components of this basin. This would classify the Gulf of Mexico Basin as an active tectonic basin as opposed to the more accepted passive basin status. The following two‐part paper presents a model for this lithospheric plate adjustment together with the geological evidence to support this movement. Part 1 discusses the rift model and supporting evidence. Some of this evidence is: a proposed triple‐junction rift zone radiating from a large dome centered in the DeSoto Canyon area; the division of the Gulf of Mexico Basin Jurassic salt province into three salt basins (the Interior, Exterior, and Challenger Basins); the linearity and structurally‐positive attitude of the Cretaceous Shelf Edge; an excessive Exterior Basin salt mass that thickens towards the Sigsbee escarpment; large areas of non‐diapiric salt found within the Exterior Basin; an extensional fault zone found underlying the Abyssal Plain; and the absence of a Late Mesozoic section from the Exterior Basin, a section that would be needed to cover the salt until it was overlain by younger Tertiary sediments.

Part 2 discusses further evidence for an active Gulf of Mexico Basin, and includes the following observations. The recorded positive gravity response in the Exterior Basin is in conflict with thick Louann salt found there. Possible lithospheric plate boundaries are outlined by linear magnetic signatures, recorded earthquake epicenters and centers of active and dormant volcanism. Magnetic, deep refraction and reflection data record a ridge‐and‐valley basement complex running parallel to these lithospheric plate boundaries. Refraction and reflection data allows the Challenger salt layer to extend northwards under the Abyssal Plain, and to connect to the Exterior Basin Louann salt layer. Eastern Cretaceous Shelf Edge paleostmctural restoration shows doming along this linear structure from the early Late Cretaceous through the Early Tertiary, which corresponds to Albian‐ early Cenomanian through Early Tertiary linear doming in the offshore area of eastern Mexico. Eastern Mexico's Tuxlas volcanic field appears to be part of the Trans‐Mexico neovolcanic belt that has been relocated along a transform fault. Other lines of evidence are also considered.
CLAY‐MINERAL STUDIES OF THE SUBSURFACE NIGER DELTA
Authors: Odigi M. I.
Published: December 2007

Mineralogical studies of Tertiary subsurface sediments in the Niger Delta have shown that smectite, kaolinite, mixed‐layer illite/smectite and illite are the principal clay minerals, with subordinate quantities of chlorite. Clays from the Recent delta have similar mineralogical compositions.

Sediments in the eastern Niger Delta are contributed by rivers which drain the Oban and Bamenda Massifs, and the Tertiary volcanics and Cretaceous sediments of the Benue Trough. Sediments in the central and western delta are derived by weathering of the North, Central and SW Nigerian Basement, and also from Cretaceous sediments which are drained by the Niger/Benue river systems.

The clay‐mineral assemblages of the western, central and eastern Niger Delta sequences differ. These differences are thought to be related to geothermal gradients, environments of deposition, source materials, pore‐waters chemistry and basin tectonics.

Clay‐mineral assemblages from nine wells in the Niger Delta are used in this study as a possible means of correlation. A relationship can be established between clay mineralogy and the occurrence of hydrocarbons in the wells investigated.
EARTHQUAKE RECURRENCE IN KUWAIT INDUCED BY OIL AND GAS EXTRACTION
Authors: Bou‐Rabee F.
Published: December 2007

A magnitude 4.7 earthquake which occurred on June 2, 1993 in the vicinity of the Minagish/Umm Gudair oilfields in Kuwait was a complete surprise. It was felt over an area of about 2,500 sq. km, and the main shock was followed two days later by an aftershock with a magnitude of 3.2. Five earthquakes are known to have occurred between 1975 and 1977 in this area, but there had been no previously reported seismic activity. In Kuwait, seismic hazards could result from excessive fluid withdrawal, fluid injection, intraplate seismicity within the Arabian Plate, or from the effects of large earthquakes along the Zagros Belt. Sinkholes have been reported to form as a consequence of fluid‐withdrawal related subsidence. The spatial correlation between recent, moderate‐sized earthquakes and operating oilfields suggests that the current seismicity may be related to oil production. It is proposed that a permanent seismic network in Kuwait be established, to monitor and evalute seismic hazards, and predict damaging earthquake events
A NEW HYDROCARBON “PLAY” AREA OFFSHORE SOCOTRA ISLAND, REPUBLIC OF YEMEN
Authors: Richardson S. M. , Bott W. F. , Smith B. A. , Hollar W. D. , Bermingham P. M.
Published: December 2007

A new plate reconstruction has enabled the Island of Socotra, currently located in the Gulf of Aden adjacent to the Somalian coast, to be restored confidently to its original spatial position adjacent to the southern Omani coastline. Regional geological and geophysical evaluations integrated with this plate reconstruction have confirmed the presence of an untested Mesozoic graben, which trends across the Socotra Platform. Fieldwork carried out in the region now enables a SE extension of the prolific Lower Cretaceous Qishn “play” (delineated in the Masilah Basin, onshore Yemen) to be postulated offshore into the Gulf of Aden.

Following the award to British Gas E&P Ltd of a tract of offshore acreage adjacent to the Island of Socotra, exploration studies have confirmed the presence of the Qishn “play” both on the Island of Socotra, and offshore in the one available control well. This work has also identified two additional “plays”: the Shuaiba‐equivalent carbonates, which are prolific producing reservoirs in Central Oman; and the Permo‐Triassic clastics, which may provide a new reservoir target for the region.

Ongoing multidisciplinary studies, integrating the results of a detailed geophysical interpretation with high‐resolution structural‐stratigraphic studies, have confirmed the presence of large structures within an undrilled Mesozoic rift‐basin, which will be tested during 1995.
RESERVOIR POTENTIAL OF THE MAASTRICHTIAN PAB SANDSTONE IN THE EASTERN SULAIMAN FOLD‐BELT, PAKISTAN
Authors: Sultan M. , Gipson M.
Published: December 2007

The hard, resistant, generally cliff‐forming Pab Sandstone Formation of Maastrichtian age is well exposed in parts of the eastern Sulaiman Fold‐Belt. Thin‐section, XRD and SEM studies of 66 samples from seven outcrops extending 200 km along strike were made in order to assess the reservoir quality of this formation. Petrographic studies indicated that the sandstones, classified as quartz arenites (locally subarkose), are texturally and mineralogically mature. The proportion of potassium feldspar varied from trace to 16%, and this mineral was confined to certain stratigraphic zones. Alteration of feldspars to clay minerals was common, particularly in the south of the study area. Plagioclase, heavy minerals, and lithic fragments were present in minor amounts.

Diagenetic kaolinite, illite and chlorite were common, with kaolinite being the most abundant. Quartz overgrowths constitute the dominant cement. The reservoir quality of the formation largely depends on the composition of the sandstone, and its susceptibility to chemical alteration. Most of the porosity (up to 16%) results from the dissolution of feldspar grains; dissolution was restricted to the south of the study area, and the feldspars in the north show little alteration and no dissolution.

Reservoir potential has also been influenced by the substantial input of silica‐rich solutions that completely destroyed the primary porosity of the sandstone. The observed porosity is mostly secondary, commonly formed by dissolution of feldspar grains, and occasionally cement/matrix.

The sequence of diagenetic events is, from oldest to youngest: formation of pyrite; formation of early‐stage calcite; formation of dolomite; silica cementation; formation of clays; precipitation of late‐stage calcite; feldspar dissolution; and formation of iron oxides. The textural and mineralogical maturity, coupled with local well‐developed secondary porosity, may make the Pab Sandstone Formation a good reservoir rock.
POROSITY EVALUATION OF SEISMICALLY‐RESOLVED ZECHSTEIN CARBONATE LAYERS, LøGUMKLOSTER‐1 WELL, DENMARK
Authors: Maver K. G.
Published: December 2007

Seismic modelling has been applied to define the porous carbonate intervals and lithologic boundaries resolved in the seismic section at the Løgumkloster‐ 1 Well, southern Jylland, Denmark, This well encountered a 14‐m thick, porous Zechstein carbonate interval (Ca‐2) with an oil show, but the well was plugged and abandoned.

Band‐pass filtering and blocking of the acoustic‐impedance log in the time domain have been used to define a number of successive acoustic‐impedance models. The simplest of these, from which a synthetic seismogram correlates with the synthetic seismogram derived from the original acoustic‐impedance log, is assumed to define the maximum number of intervals resolved in the seismic section at the well location. As the well data was acquired in an area represented by a variable seismic reflection pattern, a new optimal seismic section CMP location was found, to optimise the correlation between the synthetic seismogram and the seismic section.

Fifteen acoustic‐impedance intervals could be resolved in the seismic section at the Løgumkloster‐1 Well location, including the porous Ca‐2 carbonate interval. A close relationship was found between the Ca‐lb, Ca‐2 and Ca‐3 carbonate layers and lateral variations in the seismic reflection pattern, which indicates significant porosity variations.
PETROLEUM POTENTIAL OF THE FALKLAND ISLANDS OFFSHORE AREA
Authors: Richards P.C. , Gatliff R.W. , Quinn M.F. , Fannin N.G.T.
Published: December 2007

Rocks of Precambrian, Palaeozoic and Early Mesozoic ages are present on the Falkland Islands. The islands are surrounded by extensive Mesozoic‐Cenozoic basins that developed as failed rift systems during the initial stages of Gondwana separation. Large tracts of acreage in three of these basins (the Falkland Plateau Basin, South Falkland Basin and North Falkland Basin) were opened for licensing for the first time in October, 1995.

The area has undergone little exploration other than the acquisition of regional seismic data, and interpretations of stratigraphy and basin history are therefore somewhat conjectural. The basins are believed to contain Jurassic to earliest Cretaceous syn‐rift sediments. Probable marine and lacustrine source rocks, and reservoir rocks eroded from clean Palaeozoic quartzites, are predicted to occur within this syn‐rift succession. Thick argillaceous intervals probably accumulated during a post‐Valanginian thermal sag phase. This sag phase was interrupted by regional uplift, particularly during the Early Cenozoic.

A variety of “play” concepts can be established within each basin, and potentially large structural targets can be defined on the reconnaissance seismic data available from the area.

The region is considered to be one of the World's last true “frontier” exploration areas, where large, deep, Mesozoic failed‐rift basins remain to be drilled and explored.
THE TECTONIC AND DEPOSITIONAL HISTORY OF KUWAIT FROM SEISMIC RELECTION DATA
Authors: Bou‐Rabee F.
Published: December 2007

A series of structural and isopach maps have been constructed to model the tectonic history of Kuwait. These indicate that the geological history of the country has been one of general subsidence, interrupted on a number of occasions by periods of uplift. A major unconformity in the mid‐Cretaceous is observed above the Burgan High, which is a structure of great importance for hydrocarbon accumulation. The thinning of sediments, as seen on the isopach maps, suggests that the development of this structure began as early as the Jurassic.
RELATIONSHIPS BETWEEN SHALE CONTENT AND GRAIN‐SIZE PARAMETERS IN THE SAFANIYA SANDSTONE RESERVOIR, NE SAUDI ARABIA
Authors: Saner S. , Cagatay M. N. , Sanounah A. M. Al
Published: December 2007

The grain‐size distribution of a sediment is controlled by the hydrodynamics of the depositional environment. There is a relationship between the petrophysical properties of a reservoir rock, such as porosity and permeability, and the grain‐size distribution. Therefore, the grain‐size distribution is important in interpreting both the depositional environment and the petrophysical properties of a sedimentary rock. Determination of the grain‐size parameters from gamma‐ray and/or other shale‐indicator well logs may be possible if the necessary correlations are established.

Relationships between the shale content and the grain‐size parameters of samples from the Lower Cretaceous Safaniya Sandstone Member in NE Saudi Arabia were investigated by grain‐size analyses of 47 samples using sieving and a Microscan II particle‐size analyzer. Analysed samples were “clean” and “shaly” fine‐ to very fine‐grained sandstones. Grain‐size distribution curves revealed a finer mean, poorer sorting, finer skewness, and a leptokurtic distribution with increasing shale content. The shale content associated with the finer grain sizes promoted a reduction in porosity and permeability, which is a common occurrence in sandstones.

In the studied well, a reasonable correlation between the grain‐size parameters and the shaliness log was observed. Vertical variations in the parameters for the sequence indicated two coarsening‐upwards and one fining‐upwards depositional cycles.
REVISION OF THE MAHAKAM COAL SERIES: ROCK‐EVAL AND RANK(S) RELATIONS
Authors: Suggate R. P. , Boudou J. P.
Published: December 2007

Neogene sequences in the Mahakam delta, Indonesia, contain many coals for which abundant analytical and Rock‐Eval data exist. It is essential that raw analytical data are adjusted for the effects of mineral matter, including pyrite, before they are used to calculate atomic H/C and O/C ratios; these ratios are required in order to present the coal series on a van Krevelen diagram.

In this paper, a method of adjustment is proposed which allows the definition of a well‐constrained Mahakam coal band; this is comparable to the Late Cretaceous and Tertiary New Zealand coal band and the Japanese Palaeogene coal band. The relationships between: (i) coal rank (using the Rank(S) scale) and Rock‐Eval parameters; and (ii) coal rank and vitrinite reflectance for the Mahakam coals are generally similar to those for the New Zealand coals.
A PRELIMINARY EVALUATION OF LOWER AND MIDDLE CRETACEOUS SOURCE ROCKS IN KUWAIT
Authors: Abdullah F.H.A. , Kinghorn R.R.F.
Published: December 2007

Large volumes of oil and gas are present in the Arabian‐Iranian Basin; however, most petroleum‐geological investigations here have concentrated on reservoirs and traps, and there have been few efforts to study potential source rocks. This paper evaluates possible source rocks within the Lower to Middle Cretaceous interval in Kuwait, which is one of the main oil‐ and gas‐producing countries in this region.

Samples of carbonates and shales from formations within the Thamama and Wasia Groups (Lower and Middle Cretaceous) were collected from five locations in Kuwait. These samples were studied using standard organic‐geochemical methods (TOC and pyrolysis analysis, elemental analyses of kerogens, density separation, and petrographic analyses using transmitted and reflected light microscopy).

Most of the kerogens in the studied samples fell between Types II and III. The TOC, kerogen type and maturity of the Sulaiy Formation and parts of the Minagish Formation (Lower Cretaceous) indicate that they supplied hydrocarbons to the reservoirs in Kuwait.
POTENTIAL FOR COAL‐DERIVED GASEOUS HYDROCARBONS IN THE MIDDLE BENUE TROUGH OF NIGERIA
Authors: Obaje N. G. , Abaa S. I.
Published: December 2007

About 6,000m of alternating marine, paralic, and continental sediments of Cretaceous to Tertiary ages are present in the Benue Trough. Conspicuous amongst these are coal‐bearing strata, of which those in the Middle Benue Trough have attained a high‐ to medium‐volatile bituminous rank.

Coal beds are now known to be major sources of associated and non‐associated gases, and increasingly are becoming exploration targets in many parts of the World. In the Middle Benue Trough, the Turonian Awgu Formation, about 400‐m thick, is the main coal‐bearing unit.

Maceral analysis of samples from coal seams and from organic matter‐rich interseam sediments obtained from four boreholes and two outcrop sections allowed three petrographic facies to be identified, namely:

Vitrinite reflectance values measured on these samples generally increase with depth from 0.74 ‐ 1.25Rm%. At these values, large amounts of volatile matter are yielded in the form of methane, carbon dioxide and water during progressive devolatization of humic organic matter.

Organic matter in the underlying dark‐black, carbonaceous marine shales of the Cenomanian Ezeaku and Albian Arufu/Uomba/Gboko Formations may also be at the rank of medium‐volatile bituminous coal, and probably reaches the low‐volatile bituminous stage. These would correspond with the interval of maximum gas generation and the generation of methane, accompanied by strong aromatisation and ring condensation.

A vitrinite‐fusinite coal facies, which is vitrinite‐dominated with minor amounts of liptinite and variable amounts of inertinite; the content of mineral matter is low.

A trimaceritic coal facies, which is vitrinite‐dominated with moderate amounts of liptinite and inertinite; the content of mineral matter is low.

A shaley coal facies, which is dominated by mineral matter, with variable amounts of vitrinite, liptinite and inertinite.
A NEURAL‐NETWORK APPROACH TO KNOWLEDGE‐BASED WELL INTERPOLATION: A CASE STUDY OF A FLUVIAL SANDSTONE RESERVOIR
Authors: Wong P. M. , Tamhane D. , Wang L.
Published: December 2007

This paper presents a new approach to well interpolation using interpolation neural networks (INETs). Traditional methods such as geostatistics have been applied to the spatial mapping of reservoirs. However, these methods are not able to make use of qualitative information, such as previously‐constructed “expert knowledge ” in the form of iso‐porosity contours or structural maps of sand body geometry, in a simple manner.

This paper demonstrates the usefulness of INET via a case study of a fluvial sandstone reservoir at an oilfield in the Asia Pacific region. The proposed method is applied to porosity interpolation based on data from spatially‐dispersed wells and regional geological knowledge. The results from this study show that an INET is not only able to incorporate expert advice, but also that it is easy to implement in a desktop computer or workstation. This allows an effective transfer of geological knowledge to reservoir modelling.
THE NATURE AND PRESERVATION OF ORGANIC MATTER IN HOLOCENE LACUSTRINE/DELTAIC SEDIMENTS OF LOWER MESOPOTAMIA, SE IRAQ
Authors: Aqrawi A. A. M.
Published: December 2007

Organic‐geochemical studies of sediments at the surface and in shallow boreholes in the Tigris‐Euphrates Delta of SE Iraq are integrated in this paper with sedimentological and stratigraphic studies. Limited organic preservation was found to have occurred in surface sediments from marshland areas (“Ahwar”), although organic‐rich sediments were observed within older Holocene borehole sequences.

Reeds of Phragmites and Typha sp. are the main source of organic material in both the surface and the underlying sediments in this area. Petrographic studies indicated that this material consists mainly of “immature” components such as woody structures, algal amorphous and herbaceous matter, with some marine structures and pollen.

The principal factor controlling organic‐matter preservation in this arid deltaic setting seems to have been the comparatively high rate of sedimentation, particularly in the early‐middle Holocene. Most of these organic‐rich sediments (5–15% TOC) are overlain by middle Holocene brackish/marine sediments of the transgressive Hammar Formation. The organic‐rich sediments are generally older than these transgressive sediments (i.e. 6,000–9,000 years BP, according to their location within the study area).
ANALOGUE MODELLING: FROM A QUALITATIVE TO A QUANTITATIVE TECHNIQUE — A HISTORICAL OUTLINE
Authors: Koyi H.
Published: December 2007

Analogue modelling is a simplification of Nature; using this method, structures formed due to the deformation of rocks, whose in situ properties may be poorly known, can be modelled and investigated. Our lack of knowledge about “real” rocks is one of the major limitations to any kind of modelling of deformation. However, unlike their counterparts in Nature, the initial (undeformed) stages of analogue models can be documented, and can easily be compared with their later, deformed stages. This comparison is essential to gain an understanding of the evolution of the resulting structures. Analogue modelling is a relatively simple and inexpensive technique which can be very valuable as long as its limitations are well understood.

In rock mechanics, real rocks are strained over human time scales. As many of the properties of rocks are time‐dependent, the results of this type of experiment cannot directly be extrapolated to geologic time scales. Instead, modellers diminish the temporal and spatial dimensions by substituting carefully‐chosen analogue materials for real rocks. Unlike field geologists, analogue modellers are able to follow the development of their models in a fixed reference frame.

Cloos (1955) noted that: “Many interpretations would never have been published if the author had only once tried his suggested mechanism of folding or faulting in an experiment….”; he also concluded that “[analogue] experimenting is a good deal of fun”!
MULTIPLE PETROLEUM SYSTEMS IN TERTIARY EXTENSIONAL BASINS, EAST CHINA: A CASE STUDY OF THE GUNAN‐FULIN BASIN
Authors: Jianyu Chen , Shuifu Li , Ying Xiong , Yanpong Bi
Published: December 2007

The Gunan‐Fulin Basin, a small, extensional basin of Tertiary age, is located within the Shenglipetroleum “province” which structurally corresponds to the Jiyan megabasin in East China. The Lower Tertiary succession in the Gunan‐Fulin Basin is dominated by the Eocene‐lower Oligocene Shahejie Formation, which is divided into four members. Major source rocks are present in the Es3 Member (Eocene), and the Es 1 Member (Oligocene). Both units were deposited during lacustrine transgressions in the Early Tertiary. They are composed of dark, organic‐rich mudstones and oil shales of lacustrine origin, and contain good quality Type I‐II kerogen. The Es 1 source rock was deposited in a saline lake occasionally invaded by the sea, while the Es3 unit was laid down in a fresh‐water lake.

The maturity and characteristics of these source rocks and the related crude oils can be distinguished on the basis of their biomarker contents. Es 1 source rocks and related oils are of relatively low maturity, while those of Es3 derivation are mature to highly‐mature. There are therefore two separate petroleum systems in the Gunan‐Fulin Basin — Eocene and Oligocene.

These petroleum systems are isolated hydraulically, and have independent migration pathways in which fault planes and unconformity surfaces play important roles. The distribution of oil accumulations in the two systems is different as a result of faulting. Oil from the Eocene source rocks is trapped in reservoirs which are distributed stratigraphically from the basement to the Tertiary, while oil from the Oligocene source rock is confined to Oligocene and Miocene reservoir rocks.

The existence of multiple petroleum systems is an important feature of Tertiary extensional basins in East China, and results from multiple phases of block faulting and a high geothermal gradient.
GEOCHEMICAL CHARACTERISTICS AND THERMAL MATURITY OF OILS FROM THE THRACE BASIN (WESTERN TURKEY) AND WESTERN TURKMENISTAN
Authors: Gürgey K.
Published: December 2007

Crude oils in the Thrace Basin (western Turkey) and western Turkmenistan are believed to have been generated by a common Oligocene siliciclastic source rock. This widespread source rock extends over the area between western Turkey and the eastern South Caspian Basin. Oils from three Eocene reservoirs in the Thrace Basin and from four Pliocene reservoirs onshore western Turkmenistan were analyzed to investigate and compare their source‐rock characteristics. In order to understand controls on the timing of hydrocarbon generation and source‐rock maturation in both basins, the results of quantitative basin modelling were compared with those of geochemical analyses.

The results indicate that all the oil samples exhibit similar geochemical characteristics, such as IP13‐IP20 acyclic isoprenoid, terpane, regular sterane, methylsterane, and dinosterane profiles. The low tricyclic/pentacyclic terpane ratios, low C29 norhopane/C30 hopane ratios and low diasterane/regular sterane ratios, and the presence of 18α (H)30 oleanane and gammacerane further support a common source or source facies. Based on these observations, it is concluded that shallow‐marine clastics of Oligocene age constitute source rocks in both basins.

The oils are of low maturity (Req(%) < 0.60), as indicated by their low ethylcholestane 20S/20S+20R, 17α (H), 21β (H)‐bishomohopane 22S/22S+ 22R, and high 17β (H), 21α (H) moretane/17β (H), 21α (H) hopane ratios. However, oils from west Turkmenistan appear to be more mature than those from the Thrace Basin. This is consistent with their earlier generation, which resultedfrom the higher sedimentation rate and higher heating rate. Present‐day reservoir depths and temperatures appear to play only a minor role in determining the oils' maturities.
PERMEABILITY PREDICTION FROM WELL LOGS USING AN IMPROVED WINDOWING TECHNIQUE
Authors: Wong P.M.
Published: December 2007

Permeability prediction from well logs is of great importance in reservoir characterization and engineering. In this paper, a new method is proposed to correlate conventional well logs and core permeability data. It uses an improved “windowing” technique to incorporate adjacent core data to the permeability predictor in such a way that the scales of the well log and core measurements are matched. It also has the capability to evaluate the reliability of each and every prediction. The method is implemented by the use of a neural network and is demonstrated by means of a case study. The study uses a set of well logs and limited core permeability data to produce continuous permeability profiles. The results show that the permeability profiles are consistent with the core permeability and the geological sequence of the reservoir. The reliability indicator is particularly useful for examining reservoir heterogeneity and sampling.
CRETACEOUS SOURCE ROCKS AT THE ABU GHARADIG OIL‐ AND GASFIELD, NORTHERN WESTERN DESERT, EGYPT
Authors: Khaled K. A.
Published: December 2007

The Abu Gharadig oil‐ and gasfield is located in the north of the Western Desert of Egypt. In this paper, the geochemical characteristics of kerogens from Cretaceous shales at this field are described. The shale samples came from the Abu Roash Formation E and G Members (late Cenomanian‐ Turonian), the Bahariya Formation (early Cenomanian) and the Betty Formation (Neocomian‐ Barremian). Kerogen type and quality was evaluated by optical microscopy and by standard methods (elemental analysis, infrared spectroscopy and Rock‐Eval pyrolysis). The results show that the shale samples analysed contain fair to high quantities of organic matter, and that this takes the form of marine amorphous sapropelic and structured liptinite macerals which can be classified as Types I and II kerogens.

Maturation indicators and burial history curves indicate that shales from the Abu Roash E and G Members are currently located in the oil‐generation window. Oil generation in these units has taken place since the late Palaeocene‐early Eocene—i.e. since the formation of structural traps in the Abu Gharadig area, which occurred in the Maastrichtian—Eocene. Shales in the Bahariya and Betty Formations passed through the oil window during the Late Cretaceous before the traps were formed, but the shales reached the wet‐gas zone in the late Miocene ‐ early Pliocene.

Most of the liquid hydrocarbons in the Abu Gharadig field are sourced by Cretaceous shales in the Abu Roash E and G Members; and most gas is generated by shales in the underlying Bahariya and Betty Formations. The Jurassic Khatatba Formation may also have generated some gas.
VOLCANIC RESERVOIR ROCKS: A CASE STUDY OF THE CRETACEOUS FENGHUADIAN SUITE, HUANGHUA BASIN, EASTERN CHINA
Authors: Jinglan Luo , Chengli Zhang , Zhihao Qu
Published: December 2007

The lithofacies and reservoir properties of Cretaceous volcanic rocks in the Fenghuadian Suite (Huanghua Basin, eastern China) are described in this paper. Three lithofacies have been identified (pyroclastics, lavas and volcaniclastics) and each has different reservoir potential due to differences in porosity and permeability. Pyroclastics and lavas have better reservoir properties than do volcaniclastic rocks. In the pyroclastics, voids and fractures within brecciated rocks together with dissolution voids and fissures result in highly connected porosity (up to 22%). In the lavas, vesicles, dissolution joints and cooling fissures together with weathering cracks and fissures are abundant and have high connectivity in the upper portions of each volcanic cycle, giving rise to excellent reservoir properties. By contrast, volcaniclastic rocks have low porosities and poor reservoir potential.

We suggest that porosity development is partly related to palaeo‐geomorphology. Thus, volcanic rocks in palaeo‐highs and in neighbouring transitional areas have enhanced reservoir properties as a result of weathering and the consequent development of vugs and fissures.

Chromatographic analyses of crude oils and rock extracts indicate that the Kong‐2 Member of the Eocene Kongdian Formation, which overlies the Fenghuadian Suite in the study area and which also occurs in the nearby Cangdong Depression, is the principal source of hydrocarbons reservoired in the Fenghuadian Suite. Faults may have acted as conduits for hydrocarbon migration.
OVERPRESSURE DEVELOPMENT AND HYDROFRACTURING IN THE YINGGEHAI BASIN, SOUTH CHINA SEA
Authors: Xinong Xie , Sitian Li , Weiliang Dong , Qiming Zhang
Published: December 2007

Intensely overpressured compartments are present in the centre of the Yinggehai Basin, South China Sea. In this part of the basin, a diapiric area can be distinguished from a non‐diapiric area; structures in the former area result from shale diapirism at depth, and from the movement of hydrothermal fluids at more shallow levels. In the diapiric zone, the top of the overpressured compartment is relatively shallow (1,500m to 2,500m deep), whereas it is more than 3,200m deep in the non‐diapiric area. The top of the overpressured compartment in the diapiric zone has been raised to relatively shallow levels due to vertical fluid expulsion.

Hydrofracturing has occurred in the Neogene‐Quaternary marine sedimentary succession, particularly in mud‐rich intervals such as the Lower Member of the Pliocene Yinggehai Formation. Hydrofracturing may have allowed the rapid lateral and vertical migration of enormous volumes of pore fluids. The presence of additional steeply‐dipping faults in the diapiric area may have led to vertical expulsion of fluids from overpressured compartments to normally‐pressured areas, and caused the top of the overpressured compartment to be uplifted. Gaseous hydrocarbons are assumed to have migrated vertically through fractures around diapiric structures from overpressured to normally‐pressured zones. We believe that this mechanism has had a significant effect on hydrocarbon transport and accumulation in the Yinggehai Basin.
TECTONIC EVOLUTION OF THE SOUTHERN ‐ CENTRAL IRISH SEA BASIN
Authors: Maingarm S. , Izatt C. , Whittington R. J. , Fitches W. R.
Published: December 2007

Interpretation of 2D seismic reflection data combined with correlation of five wells in the southern part of the Central Irish Sea Basin show a NE‐SW trending graben, whose bounding faults are considered to be reactivated lineaments of Precambrian age. The basin‐fill comprises mainly Carboniferous and Triassic successions, with localised and thin occurrences of Lower Jurassic and Tertiary rocks, all of which are unconformably overlain by Quaternary sediments. Due to poor data quality, the structural evolution of the area during the Late Palaeozoic is poorly understood. During the Triassic, the basin was subjected to thermal subsidence with a phase of minor uplift in the Anisian. The major phase of extension in the basin took place during the ?Middle ‐ Late Jurassic and had a NW‐SE orientation. Subsequent Late Jurassic sinistral shear along the NE‐SW trending basin bounding fault is suggested to have taken place, giving rise to a series of north‐south intra‐basinal faults. The present‐day structure of the basin is a broad anticline, inherited from a Cretaceous ‐ Early Tertiary compressional phase. During the Palaeocene the area was subjected to regional uplift, followed by minor extension along the NW boundary fault during the Eocene ‐ Oligocene. A Late Tertiary phase of transpression is postulated to have occurred, which inverted north‐south trending faults and folded the base‐Tertiary unconformity.