Quality Sandstones Research Articles

Mindoro: a rifted microcontinent in collision with the Philippines volcanic arc; basin evolution and hydrocarbon potential

The Mindoro area is the easternmost part of the Palawan-Mindoro microcontinent which rifted away from the South China margin during the Early Oligocene. Sea floor spreading carried it southwards until the Late Miocene, when collision with the Philippines Arc in the east, and other terranes to the south began. This paper considers the collision tectonics which operated at the eastern end of the microcontinent, which resulted in the inversion and thrusting of its rifted margin. These processes are documented by seismic data and field outcrop. The syn- and post-rift sedimentary sequences contain prospective source and reservoir intervals. Subsequent burial and deformation have resulted in the generation of hydrocarbons, as proved by the existence of several oil seeps on Mindoro Island, and by hydrocarbon shows recorded in offshore exploration wells. The structural history of the area since the Eocene is divided into four phases: Syn-Rift: Early Eocene-Mid-Oligocene Drift: Late Oligocene-Mid-Miocene Collision: Mid-Late Miocene transpression: Latest Miocene-Present The unconformities which separate these stratigraphic sequences can be identified on seismic data. The sequences show characteristic differences in stratigraphy and structure, which control their prospectivity. The Syn-Rift Sequence consists of non-marine arkosic sandstones at the base, becoming marine towards the top and including platform and reefal limestones. The Drift Sequence records an overall regression, beginning with the deposition of marine shales, sandstones and detrital limestones and passes upwards into deltaic sands, shales and coals. This sequence contains reservoir quality sandstones and several potential source horizons. On Mindoro Island, the Collision/Transpression Sequence interval is dominated by coarse clastics derived from the uplifted collision zone. In offshore areas to the south and west, away from the collision zone with the arc, a more uniform blanket of parallel bedded shale and calcaeous siltstones was deposited. These form a regional seal to structural traps which may contain significant volumes of hydrocarbons.

３Ｄ震探解釈の一事例―オーストラリア・チモール海，Ｔａｌｂｏｔ油田

Talbot oilfield was discovered by AC/P12 joint ventures in December 1989. The AC/P12 permit was gazetted for competitive bidding and awarded in February 1989. Work obligation of the permit was composed of the seismic program involving acquistion of 2, 660km of 2-D and 3, 350km of 3-D data, seismic reprocessing and drilling of four wildcat wells. 3-D seismic acquisition covered the C2 prospect, which was delineated as a significant fault-dependent structural high during the bidding study in 1988. Interpretation of this oil field, subsequently named Talbot, revealed tectonic and stratigraphic similarities to the Challis oil field, 40km to the north. The Talbot-1 produced oil and gas at and unstabilized rate of 4, 981 BOPD and 3.71 MMCFGD in December 1989. The Talbot-2 appraisal also produced oil and gas at a maximum unstabilized rate of 4, 992 BOPD and 2.93 MMCFGD in June 1990. By comparison with Challis oil field, the reservoir sandstone of the Talbot oil field was expected to be thick and of excellent quality. However, it was composed of a thin bedded poor reservoir quality sandstone, alternated with siltstone, claystone and dolomite.The purpose of this study was to clarify the structure of Base Cretaceous horizon and upper Triassic reservoir itself together with the oil and gas reserves estimation of the Talbot oil field in detail. The study has clarified the structure of the Talbot oil field including the dip and minor faults of the reservoir section. The 3-D seismic interpretation was one of the most useful methods to evaluate a thin bedded reservoir like the Talbot oil field in detail.

Petroleum geology of the Niger Delta

Abstract The Niger Delta is one of the World’s largest Tertiary delta systems and an extremely prolific hydrocarbon province. It is situated on the West African continental margin at the apex of the Gulf of Guinea, which formed the site of a triple junction during continental break-up in the Cretaceous. Throughout its history, the delta has been fed by the Niger, Benue and Cross rivers, which between them drain more than 10 6 km 2 of continental lowland savannah. Its present morphology is that of a wave-dominated delta, with a smoothly seaward-convex coastline traversed by distributary channels. From apex to coast the subaerial portion stretches more than 300 km, covering an area of 75 000 km 2 . Below the Gulf of Guinea, two enormous lobes protrude a further 250 km into deeper waters. The delta sequence comprises an upward-coarsening regressive association of Tertiary clastics up to 12 km thick. It is informally divided into three gross lithofacies: (i) marine claystones and shales of unknown thickness, at the base; (ii) alternations of sandstones, silstones and claystones, in which the sand percentage increases upwards; (iii) alluvial sands, at the top. Delta structure and stratigraphy are intimately related, the development of each being dependant on the interplay between sediment supply and subsidence rates. The dominant subsurface structures are syn- and post- sedimentary listric normal faults which affect the main delta sequence. They die out upwards into the alluvial sands and sole out at depth near the top of the marine claystones. Major growth-fault trends cross the delta from northwest to southeast, dividing it into a number of structural and stratigraphic belts, called depobelts, which become younger towards the south. The deltaic sequence in each of these depobelts is distinct in age, so that they actually represent successive phases in the delta’s history. Hydrocarbons have been located in all of the depobelts of the Niger Delta, in good quality sandstone reservoirs belonging to the main deltaic sequence (the ‘paralic sequence’ of common usage). Most of the larger accumulations occur in roll-over anticlines in the hanging-walls of growth faults, where they may be trapped in either dip or fault closures. In the 30 or 50 years since the first discoveries were made, approximately 4 × 10 9 m 3 of oil and an unestablished, but very substantial quantity of associated and unassociated gas have been discovered. Most fields are small, ranging up to 50 × 10 6 m 3 , though several larger fields contain recoverable reserves in excess of 80 × 10 6 m 3 . The hydrocarbons are found in multiple pay sands with relatively short columns, and adjacent fault blocks usually have independent accumulations.

Core Facies, Petrology, and Permeability of Tirrawarra Sandstone, Moorari Field, Cooper Basin, South Australia: ABSTRACT

The oil and gas-bearing Tirrawarra Sandstone lies in the basal section of the Cooper basin sequence, which is largely Permian in age. The sandstone is characteristically thick, but both interfingers with and conformable overlies glacio-lacustrine diamictites and varvites of the late Carboniferous-Early Permian Merrimeleia Formation. The Tirrawarra Sandstone has previously been interpreted as being deposited in a glacio-fluvial braided river environment. The sandstone produces high gas:oil-ratio oil at the Moorari field, from depths of 9,400 ft below sea level. Appraisal and development of the field has been hampered by the patchy distribution of reservoir quality sandstone. This study investigated the cause of reservoir quality variations. For seven cored wells, core facies analysis, core plug porosity/permeability, petrology, and wireline logs were all matched and compared. The results are as follows. (1) Facies states (grain size and bed form) largely control permeability distribution in the Tirrawarra Sandstone at the Moorari field, such that horizontally bedded medium-coarse sandstones are consistently more permeable than cross-bedded equivalents. (2) Diagenesis levels are high and include extensive silica cement and patchy kaolinite and siderite cements. However, diagenesis rarely operates independently of original depositional fabric. (3) An association between depositional environment and permeability is recognizable, with medial barsmore » in particular providing better reservoir quality.« less

Effects of Primary Sedimentary Processes on Reservoir Quality of Deep Wilcox"(Eocene) Sandstones in Fordoche Field, Louisiana: ABSTRACT"

The initial discovery and subsequent development of Fordoche field established a Deep Wilcox production trend in south-central Louisiana. Production in the field occurs within five intervals: the W4, W5, W8, W12, and W15 sandstones. The W8 and W12 sandstones are the most prolific. They represent shoreface sequences which formed at or near the shelf margin. Cumulative hydrocarbon production from these sandstones is in excess of 22 million bbl of oil and 151 bcf of gas. Over 1100 ft (335 m) of conventional core from the W8 and W12 sandstones in six wells were analyzed and compared to petrophysical data to effectively characterize reservoir quality. Primary sedimentation patterns (i.e., physical and biogenic sedimentary structures and sequences) are the dominant control on reservoir quality throughout the field. Burrowed to bioturbated (> 75% burrowed) lower shoreface sandstones possess relatively high average porosity values (16.7%); however, permeability values are extremely low (< 0.2 md). Clay-lined burrow walls create numerous permeability barriers which significantly alter fluid flow patterns within this facies. In contrast, massive to burrowed middle shoreface sandstones, although possessing similar average porosity values (19.8%), have substantially higher average permeability values (8.6 md). Within the middle shoreface facies, higher wave energies winnow the fine-grainedmore » silts and clays, resulting in the deposition of a clean, well-sorted sandstone. The entire sequence coarsens upward in both grain size and percent sand and is overlain by a thin (3.5 ft; 1.0 m), tightly cemented calcareous sandstone. Average thickness of the middle shoreface facies in Fordoche field is 23 ft (7.0 m) with stacked sequences within the W12 sandstone as thick as 57 ft (17.4 m) of high reservoir quality sandstones.« less

Depositional Environments and Reservoir Properties, Lonetree Field, Southern Denver Basin, Colorado: ABSTRACT

Significant accumulations of oil and gas are stratigraphically trapped in the Lower Cretaceous sandstone in the southern Denver-Julesburg basin of Colorado. Lonetree Field (T3S, R59W) provides a typical example of trapping mechanisms and reservoir properties. Examination of 5 cores and 75 wire-line logs within the field resulted in several conclusions. The deltaic J sandstone at Lonetree can be divided into three genetic units; a lower delta front (J-3), a middle delta plain sequence (J-2), and overlying destructional marine (J-1). Production at Lonetree is primarily from channel and crevasse splay sandstones of the J-2 interval. Traps are formed by the updip pinch-out of quality sandstone. Channel sandstones are characterized by a coarse to very fine-grained upward-fining sequence. Trough cross-beds predominate at the base, and ripples and rootlets at the top. Carbonized wood is ubiquitous throughout. These northeast-southwest-trending channels attain thicknesses of 15 to 50 ft (4.5 to 15 m) and widths up to 2,500 ft (760 m). Crevasse splay deposits show extreme lateral and vertical variation. Both coarsening and fining upward deposits are possible. Maximum thicknesses of 15 ft (4.5 m) are developed only in close proximity to channel sandstones. Rooted zones and ripple cross-stratification are common. Porosity in both channels and splays is secondary in nature, resulting from the dissolution of feldspars and calcite cement. This overprinting of secondary porosity on a complex depositional system has created numerous separate reservoirs within the field. Porosity in producing zones is commonly 13 to 20%, with permeabilities in excess of 75 md. Kaolinite is abundant in pore throats, and may present completion problems associated with brushpiling of fines during treatment. Little petrographic or petrophysical differences appear to exist between productive splay and channel sandstones. Typical cumulatives to date are 100,000 bbl of oil per well from splay sandstones, while channels contribute 125,000 bbl of oil per well. The 17 producing wells are expected to yield 2.4 million bbl of oil and 4 bcf of gas. End_of_Article - Last_Page 1335------------

Continuity of Pliocene Turbidite Sandstones, Ventura Area, California, with Applications to Supplemental Recovery: ABSTRACT

Outcrops of turbidite sandstones of the Pico Formation (upper Pliocene) at Ventura field and vicinity were examined to gain an insight into their continuity. Two types of reservoir quality sandstones were recognized based on physical and petrophysical properties. Type A sandstones (graded, poorly sorted) have low permeabilities (several hundred millidarcys). Type B sandstones (nongraded, moderately to well sorted) have high permeabilities (several thousand millidarcys). Three classes of turbidite packages were distinguished based on internal arrangement of sandstone types. All 3 packages contain thin-bedded Type A and B sandstones. A Class I package has, in addition, massive, composite Type A sandstones at the base; a Class II package has the massive, composite Type A sandstones in the middle; and a Class III package has no massive, composite Type A sandstones. Thick, composite Type A sandstones have good lateral continuity because they are amalgamated. Type B sandstones have poorer lateral continuity because of lack of communication with other sandstones. Observations on a single turbidite package over a End_Page 366------------------------------ lateral distance of 1,000 ft indicate that 80% of the Type A sandstone is continuous for this distance, whereas only 10% of the Type B sandstone is continuous. Factors for lateral continuity with distance multiplied by kh (millidarcy-feet) give a measure of the kh which may be expected to be in connection between wells various distances apart. At a distance of 500 ft from an injection well, only 60-80% of the total kh of the injection well may be in connection with a producing well, in the direction of depositional strike (north-south). In the depositional dip direction (east-west) this value may be 80-100%. End_of_Article - Last_Page 367------------

EXPLORATION OF THE SOUTHWEST FLANK OF THE PAPUAN SASIN

Since 1965, Tenneco Australia and Signal Pacific have been exploring three tenements totalling 30,082 square miles off the eastern coast of the Cape York Peninsula Queensland. The area is relatively unexplored but the recent drilling of the Anchor Cay well, along with seismic mapping, provides a vital link between the Papuan Basin and the Laura and other basins of the Queensland coast.The primary objective of the exploration venture was initially and remains, the Mesozoic age sandstones believed to exist in a near shore environment in the subject area. Carboniferous pyroclastics and Permian granites form the positive Cape York-Oriomo Platform. Mid-Mesozoic age sediments, are found east of this ridge, becoming thicker and more basinal regionally eastward. Tension faulting along the southwest flank of the basin has created several closed structures. Tertiary sediments are primarily carbonates and exist in a shelf, reef, forereef arrangement with petroliferous pinnacle reefs being located on bathymetrically favored structures.Seismic mapping directed at the northern portion of the tenements located several structures worthy of testing. The one with the maximum sedimentary column, the Anchor Cay structure, was chosen for a stratigraphic test and drilled in early 1969. No severe drilling problems were found at shallow depths but below 10,700 feet sloughing of cobbles into the borehole became a problem. The well was abandoned at 11,888 feet, still in sediments, where continued drilling became impracticable. The lithology encountered in this stratigraphic test was similar to that anticipated. A reef core of Pliocene rock was penetrated. Miocene rocks in a near back reef environment, and a thin Eocene carbonate section were penetrated. At approximately 7,000 feet an unconformity separated the Tertiary carbonates from the Mesozoic elastics. Immediately beneath the unconformity were reservoir quality sandstones of lower Cretaceous age. Volcanic and/or intrusive exotics became increasingly common in the Jurassic.Based on the facies encountered in the Anchor Cay stratigraphic test, it seems apparent that the most favored fairway for sandstone reservoir development is to the west where seismic shooting has indicated several structures. The initial basic concepts regarding this exploration venture are still valid and much more effort is required before a thorough evaluation can be made.