Water-bearing Sandstone Research Articles

Exploration in the Gulf of Thailand in deltaic reservoirs, related to the Bongkot Field

Abstract Statoil has been involved in exploration in the Gulf of Thailand since 1985, following an invitation by PTTEP (National Exploration and Production Oil Company of Thailand) to assist in the evaluation and possible development of the Bongkot gas and condensate Field. Statoil and PTTEP jointly studied the field in 1985 and 1986. In 1990 PTTEP farmed 60% out to a group consisting of Total, British Gas and Statoil. Development work on the field started in 1990 with the acquisition of 3D seismic data. The field came on stream in June 1993, and production increased from the original planned 150 10 6 ft 2 /day to 350 10 6 ft 2 /day at present. In the joint PTTEP/Statoil study the Oligocene to Middle Miocene reservoirs were described as fluvial point bar sandstones, deposited in a meandering river system located on a delta top or coastal plain. Based on available data it was not possible to map the individual reservoirs. 22 wells found intermingled gas- and water-bearing sandstones without obvious relation to structure. No field fluid contacts were found, and the pressure regime was thought to be hydrostatic. Statoil simulated a reservoir model consisting of numerous pointbar deposits on a muddy delta plain. The pointbars were assumed to be isolated sandbodies which favoured stratigraphic trapping. Structural mapping of existing 2D and old 3D data sets was thought to give reliable structural maps, although it was difficult to correlate single events. Stratigraphic traps were interpreted as the main traps in the field because no relationship was found between structural closure and gas pools. Since 1990 when field development started with Total as operator around 2500 km 2 of 3D data has been acquired, and approximately 20 exploration wells and 45 development wells have been drilled. These data resulted in a much more accurate description of the field, especially through the use of high-resolution 3D seismic data. The well information allowed the identification of high GR intervals with a continuous seismic expression. Also individual sand reservoirs could be correlated. It became evident from the detailed 3D seismic interpretation that structural traps form the main trapping mechanism, although a minor part of the reserves are found in isolated channel sands, which could be detected from amplitude maps. It has been difficult to identify stratigraphic traps but it is hoped that ongoing seismic attribute analyses will help. In 1993 Statoil farmed in to licence B10/32, operated by Ampolex. The Bongkot model of isolated fluvial channels, with traps formed by several faults with or without structural closure was accepted as an attractive play type. Not withstanding this, the first wildcat well, Karawake-1 was a structural test. The well failed to find hydrocarbons because it intersected a series of overlapping alluvial fans; these lack internal seal and would have precluded hydrocarbon migration and entrapment. Ampolex made a reinterpretation of the block based on the existing 2D seismic, and concentrated on seismic facies mapping. The mapping resulted in two prospect areas where fluvial facies could be recognized above a lacustrine source rock; and also the results of the Karawake-1 well could be better explained. A second well should prove the model.

Hydrodynamic Control on an Oil Entrapment in Channel Sandstones of the Dakota Sandstone, South Cole Creek Field, Converse County, Wyoming

South Cole Creek field, located in the southwest Powder River Basin of Wyoming has produced 11 million barrels of oil from the Dakota Sandstone. Detailed mapping of rock and reservoir properties including sandstone isopachs, initial potentials, cumulative production, and porosity-permeability data, reveals the existence of channel sandstones with excellent reservoir properties which are surrounded by marine rocks of poorer reservoir properties. The areal extent of the accumulation is controlled by factors other than structure and stratigraphy, as water-bearing channel sandstones exist lateral to and up-dip of producing channel sandstones. By comparing the known accumulation to the theoretical model for fluid flow, it can be shown that hydrodynamics has played an important role in modifying the accumulation at South Cole Creek field.

Preservation of Porosity in the Deep Woodbine/Tuscaloosa Trend, Louisiana

Summary Cores of the Woodbine/Tuscaloosa formation from False River field, Pointe Coupee Parish, LA. contain sandstones from 20,000 ft (6562 m) with anomalously high porosities and permeabilities. Porosities greater than 25% and permeabilities of hundreds of millidarcies are common. Scanning electron microscopy (SEM) shows that individual grains of these olive-green semifriable sandstones are coated with chlorite. The chlorite occurs as 7 to 10 micron- (µm-) wide hexagonal plates that arrange themselves edgewise one crystal thick on grain surfaces. Sandstones with continuous chlorite coatings around quartz grains display little framework compaction and minor development of secondary quartz overgrowths; however, interbedded sandstones with little or no chlorite often are cemented completely by secondary quartz. Intermediate between these extremes are sandstones with incomplete or poorly developed chlorite coatings; these display outgrowths of secondary quartz rather than overgrowths of an envelope nature. Petrographic and SEM data indicate an early diagenetic origin for the chlorite, which apparently ceased to form once detrital grains were coated with a single layer of crystals. This layer was sufficient to mask nucleation sites for silica overgrowths, and in addition may have prevented compaction by pressure solution, thereby allowing the sandstones to be buried to great depths without appreciably reducing porosity. A late dissolution event resulted in the formation of some secondary porosity, but the bulk of the observed porosity is relict primary in origin, formed in the manner previously described. Reservoir engineers and petrophysicists might ask themselves what effects the micropore system produced by the chlorite coatings will have on irreducible and critical water saturations as well as porosity logs. Introduction In mid-1965, Chevron Oil Co. discovered a deep gas accumulation in Pointe Coupee Parish, LA, in what is now called False River field. The field is 12 miles (20.81 km) downdip of the Lower Cretaceous Edwards shelf margin (Fig. 1) and production is from Woodbine/Tuscaloosa sandstones at about 20,000 ft (6462 m). A core of a water-bearing sandstone was taken from below 21,000 ft (6890 m) in the discovery well, Alma Plantation Well 1, with reported measured porosity values up to 26% (unstressed) and permeability values as much as 200 md. With this well the deep Woodbine/Tuscaloosa play was born. That these porosity values are anomalously high is illustrated in Fig. 2, which plots porosity vs. depth for an average reservoir sandstone. The high porosity values for the Alma Plantation Well 1 depart markedly from the normal trend. This observation prompted our study. Chlorite in a Deeply-Buried Sandstone Petrography Selected portions of the deep sandstone core in the Alma Plantation Well 1 are shown in Fig. 3, along with petrophysical data. Intervals with high porosity were recovered as crumbly fragments and are semifriable. The sandstones are fine grained and well sorted. The only important internal sedimentary structure is a faint graded bedding. A few marine shells are present, but adjacent shales are barren of fossils. Core samples from the nearby Crochet Well 1 also were examined. These samples ranged from crumbly and semi friable to hard and almost quartaitic. Core analyses of selected intervals from the two wells are shown in Tables 1 and 2. Petrography Selected portions of the deep sandstone core in the Alma Plantation Well 1 are shown in Fig. 3, along with petrophysical data. Intervals with high porosity were recovered as crumbly fragments and are semifriable. The sandstones are fine grained and well sorted. The only important internal sedimentary structure is a faint graded bedding. A few marine shells are present, but adjacent shales are barren of fossils. Core samples from the nearby Crochet Well 1 also were examined. These samples ranged from crumbly and semi friable to hard and almost quartaitic. Core analyses of selected intervals from the two wells are shown in Tables 1 and 2.

Diagenetic Features of Grand Rapids Formation, North-Central Alberta, Canada: ABSTRACT

The Lower Cretaceous Grand Rapids Formation of north-central Alberta consists of three massive sandstone units separated by shales and siltstones. Average thickness of the formation is approximately 90 m. In the subsurface these sandstones are impregnated with bitumen and form the Wabasca oil sands deposit, with resources estimated at 10.5 × 109 cu m (66 × 109 bbl). The Grand Rapids sandstones are arkosic to lithic sandstones with a fairly heterogeneous mineralogy in which the predominant constituents are quartz, feldspar, chert, rock fragments, mica, glauconite, and locally siderite. They are poorly consolidated, the main cementing agents being authigenic clays. Kaolinite tends to be the dominant clay mineral in the oil-saturated sandstones while montmorillonite and Fe-rich chlorite predominate in the underlying water-bearing sandstones. Scanning electron microscope studies show that kaolinite occurs as booklets, irregularly scattered throughout the sandstone in a pore-filling habit. Montmorillonite and chlorite have both pore-lining and pore-bridging habits, while illite is mostly a pore-bridging clay. Montmorillonite-chlorite mixed layer clays are found in some samples. The clays in the sandstones all appear to be authigenic in origin. Calcite is the only other common cementing agent. The calcareous cement formed early, apparently replacing most of the original matrix material and locally forming large concretions up to 5 m in diameter in the lower sandstone unit. Other authigenic minerals which may be local cementing agents include siderite, K-feldspar, pyrite, and zeolites(?). End_of_Article - Last_Page 735------------

Oil-Column Calculations in Stratigraphic Traps: ABSTRACT

Oil columns can be calculated for simple stratigraphic traps if the rock and fluid properties are known or can be estimated. Because oil migration is prevented by capillary pressure in small pores of the trap facies, direct measurements of capillary pressure allow oil columns to be calculated, but such measurements are rare. An alternative is to determine pore size from porosity and permeability data using an empirical equation, and then to compute the capillary pressure by an estimate of fluid properties. An example of oil-column calculation is from the Milbur field, Burleson County, Texas, a lower Wilcox stratigraphic trap. Using core analysis from a nearby well, an oil column of 40-80 ft would be expected for the trap, and this estimate agrees reasonably well with an actual oil column of 60-75 ft for the field. The most important part of such calculations is the realization that the trapping facies itself can have significant porosity and permeability and yet form an effective barrier to oil migration. The result is that the best reservoir may occur downdip from dry holes with porous water-bearing sandstone and oil shows, rather than updip at the pinchout. End_of_Article - Last_Page 1896------------

SEDIMENTARY AND EPIGENETICAL TRENDS AIDING THE HYDROCARBON EXPLORATION IN WEST SIBERIA

Several observations on Jurassic and Cretaceous clastic rocks of west Siberia may be important not only for oil and gas exploration but also for other fields of interest: 1 The sand and silt percentage of the sections and the sand grain-size increase in structural uplifts. This points to synsedimentary initiation of the present structures. 2 The percentage of convexo-concave grain contacts increases with depth, this increase is greater below a depth of 2,300 m. 3 The percentage of wedge-shaped grain contacts is higher in the water-bearing sandstones from the same depth. 4 In the clay matrix of water-bearing sandstones, kaolinite is widespread, whereas mixed-layer minerals (montmorillonite-hydromica) prevail in oil-bearing sandstones. The quantitative evaluation of these and other investigations proved a relatively young oil accumulation and a still younger gas accumulation in the area under consideration. The older oils differ chemically from the younger ones. 5 The clay cover of oil- and gas-bearing structures proved to contain less silt content and sand flasers than the clay cover of water-bearing structures. It is suggested, that the sandy and silty clays were not effective in trapping the hydrocarbon accumulations, mainly because of stronger jointing (when compared to pure clays). With increasing depth, the content in expanded layers decreases in these clays. At the same time, the number of jointed covers increases.

Distribution of slow neutrons in homogeneous, water-bearing sandstone

Distribution of slow neutrons in homogeneous, water-bearing sandstone

Structural Features of North Tejon-Wheeler Ridge Area: ABSTRACT

Both the North Tejon and Wheeler Ridge oil fields lie almost directly over the deeply buried portion of the White Wolf fault, but are found to occupy structures quite different in origin. The Wheeler Ridge anticline is one of a series of folds occurring along the southern border of the San Joaquin Valley. These folds and extensive thrust faults are easily recognized as the product of northerly directed compressive stresses. The principal North Tejon structure, located along the western side of Highway 99, has a north-south anticlinal axis striking nearly at right angles to the Wheeler Ridge axis, and does not have the related thrust faulting common to the other anticlinal folds. Development of the North Tejon field showed the presence of numerous high-angle faults and revealed a segmentation of oil reservoirs into blocks containing oil of different gravities. The peculiar structure and distribution of Miocene basalt, capping most of the faulted reservoir rocks, and the gentle doming of formations lying above it indicate that the shape of the North Tejon structure resulted from an upwarping of the probably highly fractured basement rock with little regard to the existing faults. A northeasterly regional tilt, accompanied by depression of gas-condensate-filled, former structural highs to positions below the level of present heavier oil- and water-bearing sandstones, has long been recognized in the segmented reservoirs at North Tejon field. Such a tilt may well have been caused by the large-scale sinking of the portion of the positive block of the White Wolf fault in the area just northeast of the field, which, like the negative block, was exposed to the very rapid End_Page 1091------------------------------ accumulation of Plio-Pleistocene debris derived from adjacent uplifts. End_of_Article - Last_Page 1092------------

Maintenance of Rock Wells

THE city of Lansing, Mich, and the metropolitan area adjoining obtain their water supply principally from rock wells drilled into the waterbearing sandstones of the Pennsylvanian formation which is common to the area. The sandrock is encountered at depths of 50 to 150 ft and extends to a depth of 400 to 450 ft below the ground level. At greater depths, limestone and highly mineralized water (especially that high in chlorides) may be encountered. The city operates some 100 wells with a total capacity of approximately 30 mgd. Average daily production is approximately 18 mgd. Sixty-four of the wells are equipped with deep-well turbine pumps and 36 are pumped by air. The deep-well turbine pumps are set at 200 to 220 ft and the diameter of the wells ranges from 6 to 14 in. Drilled over a period of 47 years (1909 to 1956), the Lansing wells are generally located along water transmission mains which supply the water conditioning plant with untreated water. The transmission mains extend from the southeast to the northwest sections of the city. The wells are spaced at distances of 300 to 1,500 ft, with 1,000 ft the optimum spacing. Some idea of the problem of maintaining the yield and life of the wells can be seen from the fact that fifteen new wells drilled in 1935 had an initial