Groundwater in the Mesozoic hydrogeological basin of the Middle Ob (a case study of the Ust-Balykskoye oil field)

2020 ◽  
pp. 20-30
Author(s):  
I. G. Sabanina ◽  
T. V. Semenova
Keyword(s):  
Sodium Bicarbonate ◽  
Oil And Gas ◽  
Practical Importance ◽  
Upper Jurassic ◽  
Oil Field ◽  
Reservoir Water ◽  
Petroleum Potential ◽  
Search Criterion

Despite the fact that there is the large amount of accumulated factual material, formation of hydrogeochemical conditions of deep oil and gas horizons in the Middle Ob and the West Siberian megabasin still contains many questions. This is due to numerous hydrogeodynamic and hydrogeochemical anomalies that don't have an unambiguous explanation. The presence of inversion hydrogeochemical zoning in the Lower Cretaceous and Upper Jurassic deposits and the presence of low-mineralized reservoir water of a sodium-bicarbonate composition are the peculiarity of groundwater in the considered territory. A change in the genetic type of water, a decrease in mineralization, a decrease in the content of calcium ion, and an increase in the amount of bicarbonate ion in the Mesozoic hydrogeological basin are associated with the transformation of mineral and organic matter in sedimentary rocks, when they are immersed, at the water expelling stage. The determination of the origin of low-mineralized reservoir water of a sodium-bicarbonate lying at significant depths is of great practical importance, since the relationship between the inversion of groundwater and oil content has been revealed, so this fact can be considered a search criterion for petroleum potential.

An integrated quantitative approach for determination of net reservoir cutoffs: A case study of Q oil field, Lake Albert, Uganda

2018 ◽  
Vol 145 ◽  
pp. 261-266 ◽  
Author(s):  
Wei Xu ◽  
Xinye Zhang ◽  
Fanjie Shang ◽  
Lei Fang ◽  
Jun Liu ◽  
...  
Keyword(s):  
Oil Field ◽  
Quantitative Approach

GEOLOGY OF BARROW ISLAND OIL FIELD

1973 ◽  
Vol 13 (1) ◽  
pp. 49 ◽  
Author(s):  
Keith Crank
Keyword(s):  
Oil And Gas ◽  
Water Injection ◽  
Water Source ◽  
Upper Jurassic ◽  
Oil Field ◽  
Late Triassic ◽  
Low Permeability ◽  
High Porosity ◽  
The South ◽  
The North

The Barrow Island oil field, which was discovered by the drilling of Barrow 1 in 1964, was declared commercial in 1966. Since then 520 wells have been drilled in the development of this field which has resulted in 309 Windalia Sand oil producers (from about 2200 feet), eight Muderong Greensand oil wells (2800 feet), five Neocomian/Upper Jurassic gas and oil producers (6200 to 6700 feet), eight Barrow Group water source wells and 157 water injection wells.Production averages 41,200 barrels of oil per day, and 98% of this comes from the shallow Windalia Sand Member of Cretaceous (Aptian to Albian) age. These reserves are contained in a broad north-plunging nose truncated to the south by a major down-to-the-south fault. The anticline is thought to have been formed initially from a basement uplift during Late Triassic to Early Jurassic time. Subsequent periods of deposition, uplift and erosion have continued into the Tertiary and modified the structure to its present form. The known sedimentary section on Barrow Island ranges from Late Jurassic to Miocene.The Neocomian/Jurassic accumulations are small and irregular and are not thought to be commercial in themselves. The Muderong Greensand pool is also a limited, low permeability reservoir. Migration of hydrocarbons is thought to have occurred mainly in the Tertiary as major arching did not take place until very late in the Cretaceous or early in the Palaeocene.The Windalia Sand reservoir is a high porosity, low permeability sand which is found only on Barrow Island. One of the most unusual features of this reservoir is the presence of a perched gas cap. Apparently the entire sand was originally saturated with oil, and gas subsequently moved upstructure from the north, displacing it. This movement was probably obstructed by randomly-located permeability barriers.

scholarly journals Determination of constituents receipt Kakhovka Reservoir water balance

2017 ◽  
pp. 209-214
Author(s):  
O.S. Koryagina
Keyword(s):  
Surface Water ◽  
Water Resources ◽  
Water Balance ◽  
Practical Importance ◽  
Surface Flow ◽  
Probable Error ◽  
Scientific Interest ◽  
Reservoir Water ◽  
Surface Water Flow

The study of the reservoirs is of great scientific interest and is of practical importance for the solution of problems of rational use and protection of water resources. The paper describes the latest reservoir in the cascade of Dnipro Kakhovka Reservoir and its component of water balance. The methods of determining the components of the water balance that were once offered the Kakhovka  hydrometeorological observatory are submitted. Great attention is drawn to the surface flow of water into the reservoir from unexplored rivers, which is determined by the method of analogy. The probable error of this method, in turn, is equal to for monthly values 30-50% and annual – 10-20%. So, there is provided somewhat different a method for determining the surface flow using the curve of security component amount of annual precipitation, maps of the norm runoff and tables SNiP 2.01.14.83. The proposed method simplifies and accelerates the process of calculating the amounts of surface water flow in unexplored rivers to Kakhovka reservoir.

Hammerfest Basin Composite Tectono-Sedimentary Element

2021 ◽  
pp. M57-2017-23
Author(s):  
E. Henriksen ◽  
L. Kvamme ◽  
T. A. Rydningen
Keyword(s):  
Late Jurassic ◽  
Oil And Gas ◽  
Barents Sea ◽  
Oil Field ◽  
Upper Permian ◽  
Tectonic Event ◽  
Petroleum Potential ◽  
Isostatic Rebound ◽  
Hydrocarbon Traps ◽  
Entry Points

AbstractThe Hammerfest Basin is an E -W trending graben located between the Loppa High and the Finnmark Platform in the southern part of the Norwegian Barents Sea. Mainly siliciclastic strata of Carboniferous to Cenozoic age cover the Caledonian basement and have a total estimated thickness of 5-8 km. The basin evolved through several tectonic phases: the Carboniferous rifting, Late Jurassic rifting, the opening of the Atlantic Ocean, Oligocene reorganisation of plate movements and postglacial isostatic rebound. An E-W trending dome in the centre of the basin developed during the main extensional tectonic event in Late Jurassic. Horst structures represent the main hydrocarbon traps. Erosional channels on the flanks of the basin represent entry points for Lower Cretaceous sands. For the rest of the Cretaceous and Cenozoic intervals no significant reservoir sands are expected.The first exploration well in the Barents Sea in 1980 was located in the Hammerfest basin, and by 2019 a total of 45 wells had been drilled in the basin where 34 are classified as exploration wells. The result is 18 oil and gas discoveries, which gives a discovery rate of 53%. Two fields are now in production: the Snøhvit gas-condensate fields and the Goliat oil field.A total of 340 Msm3 (2140 Mbbl) recoverable oil equivalents have been discovered. For the middle Jurassic Play, the yet-to-find potential may be around 50 Msm3, distributed in several small structures in the basin. Following the oil discovery in the Middle Triassic interval in the Goliat structure, and because several of the previously drilled structures only penetrated the Jurassic and the uppermost Triassic section, considerable exploration potential may exist in the deeper Triassic interval in structures with the best reservoir facies. Stratigraphic traps of Cretaceous age may have a moderate petroleum potential, with excellent reservoirs encountered along the flank of the basin. Exploration potential may also exist in Upper Permian sandstones along the southern and eastern flanks of the basin. However, in large parts of the basin, the remaining potential is in the deep structures and hence is gas prone.

scholarly journals Value Change in Oil and Gas Production: V. Incorporation of Uncertainties and Determination of Relative Importance

2002 ◽  
Vol 20 (5) ◽  
pp. 347-364
Author(s):  
I. Lerche ◽  
S. Noeth
Keyword(s):  
Oil And Gas ◽  
Development Project ◽  
Gas Production ◽  
Expected Value ◽  
Oil Field ◽  
Relative Importance ◽  
Oil And Gas Production ◽  
Equal Importance ◽  
Parameter Values

The influence of two fundamentally different types of uncertainty on the value of oil field production are investigated here. First considered is the uncertainty caused by the fact that the expected value estimate is not one of the possible outcomes. To correctly allow for the risk attendant upon using the expected value as a measure of worth, even with statistically sharp parameters, one needs to incorporate the uncertainty of the expected value. Using a simple example we show how such incorporation allows for a clear determination of the relative risk of projects that may have the same expected value but very different risks. We also show how each project can be risked on its own using the expected value and variance. This uncertainty type is due to the possible pathways for different outcomes even when parameters categorizing the system are taken to be known. Second considered is the risk due to the fact that parameters in oil field estimates are just estimates and, as such, have their own intrinsic errors that influence the possible outcomes and make them less certain. This sort of risk depends upon the uncertainty of each parameter, and also the type of distribution the parameters are taken to be drawn from. In addition, not all uncertainties in parameter values are of equal importance in influencing an outcome probability. We show how can determine the relative importance for the parameters and so determine where to place effort to resolve the dominant contributions to risk if it is possible to do so. Considerations of whether to acquire new information, and also whether to undertake further studies under such an uncertain environment, are used as vehicles to address these concerns of risk due to uncertainty. In general, an oil filed development project has to contend with all the above types of risk and uncertainty. It is therefore of importance to have quantitative measures of risk so that one can compare and contrast the various effects, and so that corporate decision-makers can use the information in a rational manner as they seek to enhance corporate profit. This paper provides such methods and measures of assessing risk.

The Beryl Field, Block 9/13, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 33-42 ◽  
Author(s):  
C. A. Knutson ◽  
I. C. Munro
Keyword(s):  
North Sea ◽  
Middle Jurassic ◽  
Oil And Gas ◽  
Upper Jurassic ◽  
Lower Jurassic ◽  
Gas Production ◽  
Upper Triassic ◽  
Oil Field ◽  
Oil And Gas Production ◽  
The North

AbstractThe Beryl Field, the sixth largest oil field in the UK sector of the North Sea, is located within Block 9/13 in the west-central part of the Viking Graben. The block was awarded in 1971 to a Mobil operated partnership and the 9/13-1 discovery well was drilled in 1972. The Beryl A platform was emplaced in 1975 and the Beryl B platform in 1983. To date, ninety-five wells have been drilled in the field, and drilling activity is anticipated into the mid-1990s.Commercial hydrocarbons occur in sandstone reservoirs ranging in age from Upper Triassic to Upper Jurassic. Structurally, the field consists of a NNE orientated horst in the Beryl A area and westward tilted fault blocks in the Beryl B area. The area is highly faulted and complicated by two major and four minor unconformities. The seal is provided by Upper Jurassic shales and Upper Cretaceous marls.There are three prospective sedimentary sections in the Beryl Field ranked in importance as follows: the Middle Jurassic coastal deltaic sediments, the Upper Triassic to Lower Jurassic continental and marine sediments, and the Upper Jurassic turbidites. The total ultimate recovery of the field is about 800 MMBBL oil and 1.6 TCF gas. As of December 1989, the field has produced nearly 430 MMBBL oil (primarily from the Middle Jurassic Beryl Formation), or about 50% of the ultimate recovery. Gas sales are scheduled to begin in the early 1990s. Oil and gas production is forecast until licence expiration in 2018.The Beryl Fields is located 215 miles northeast of Aberdeen, about 7 miles from the United Kingdom-Norwegian boundary. The field lies within Block 9/13 and covers and area of approximately 12 000 acres in water depths ranging from 350-400 ft. Block 9/13 contains several hydrocarbon-bearing structures, of which the Beryl Fields is the largest (Fig. 1). The field is subdivided into two producing areas: the Beryl Alpha area which includes the initial discovery well, and the Beryl Bravo area located to the north. The estimated of oil originally in place is 1400 MMBBL for Beryl A and 700 MMBBL for Beryl B. The fiel has combined gas in place of 2.8 TCF, consisting primarily of solution gas. Hydrocarbon accumulations occur in six reservoir horizons ranging in age from Upper Triassic to Upper Jurassic. The Middle Jurassic (Bathonian to Callovian) age Beryl Formation is the main reservoir unit and contains 78% of the total ultimate recovery.The field was named after Beryl Solomon, the wife of Charles Solomon, who was president of Mobil Europe in 1972 when the field was discovered. The satellite fields in Block 9/13 (Nevis, Ness and Linnhe) are named after Scottish lochs.

scholarly journals DETERMINATION OF THE CONCENTRATION AND SEPARATION OF VANADYLPORPHYRIN COMPLEXES BY EXTRACTION FROM OIL OF THE OIL AND GAS DISTRICT “NORTH BUZACH”

2021 ◽  
Vol 74 (2) ◽  
pp. 49-59
Author(s):  
Zh.K. Myltykbayeva ◽  
◽  
Zh.T. Yeshova ◽  
A.B. Seisembekova ◽  
M.B. Smaiyl ◽  
...  
Keyword(s):  
Chromatographic Separation ◽  
Oil And Gas ◽  
Total Concentration ◽  
Oil Field ◽  
Raw Material ◽  
The North ◽  
Absorption Zone

Oil vanadylporphyrin complexes were obtained by extraction in the presence of N-N-dimethylformamide. In the chromatographic separation of vanadylporphyrin complexes, four main fractions were obtained from the oils of the oil field “North Buzachi” , where all types of known oil porphyrin structures were identified, dominated by deoxophylloerythroethioporphyrin – types with two absorption maxima of 534 Nm and 573 nm. It was found that the total concentration of vanadylporphyrin complexes registered in the absorption zone of 534 nm and 573 nm is 11 times higher than the concentration of nickelporphyrin complexes characteristic of the absorption zone of 550 nm. The ratio of vanadylporphirins of the etio - and deoxo-phylloerythroethioporphyrin (DPEP) type was 0.11. The results of the research allow us to conclude that the oil of the “North Buzachi” oil and gas district is a promising raw material for obtaining vanadylporphyrin complexes.

scholarly journals Optimal Extraction Path in a Oil and Gas Broun Field Under the Buyback Contractual Framework (Case Study on the Iranian Oil Field in the Persian Gulf)

2016 ◽  
Vol 6 (24) ◽  
pp. 41-82
Author(s):  
علی امامی میبدی ◽  
وحید قربانی پاشاکلایی ◽  
محسن ابراهیمی ◽  
علی سوری ◽  
Said moha حاجی میرزایی ◽  
...  
Keyword(s):  
Persian Gulf ◽  
Oil And Gas ◽  
Oil Field ◽  
The Persian Gulf

scholarly journals Application of Fluid Inclusions to Petroleum Basin Recognition—A Case Study from Poland

Minerals ◽  
2021 ◽  
Vol 11 (5) ◽  
pp. 500
Author(s):  
Katarzyna Jarmołowicz-Szulc
Keyword(s):  
Fluid Inclusions ◽  
Oil Field ◽  
Field Sampling ◽  
Hydrocarbon Migration ◽  
Two Phase ◽  
Eutectic Melting ◽  
Variable Character ◽  
Petroleum Basin

Fluid inclusions were studied in rocks from different wells from the Barnówko–Mostno–Buszewo (BMB), the largest oil field in Poland and from the Lubiatów field. Sampling was performed at depths between about 3120–3220 m and 3221–3256 m, respectively. Different minerals (dolomite, calcite, anhydrite, quartz) reveal the presence of aqueous (AQFI) and hydrocarbon (HCFI) inclusions, the differentiation of which was checked by UV fluorescence and microthermometry. Inclusions occur in different abundances and are of variable character. The microthermometric studies of fluid inclusions resulted in the determination of temperatures of eutectic melting, ice melting, and homogenization. Based on the results obtained, three types of inclusions have been found. Two-phase non-fluorescent inclusions (AQFI) contain brines of differentiated salinity (from about 6 to 10 and from about 17 to 22 wt% NaCl equivalent). Two-phase fluorescent inclusions (HCFI 1) contain light mature oil of paraffin character. The oil is characterized by API gravity of about 41–42 degrees. Small one-phase non-fluorescent inclusions (HCFI 2) that homogenize in deep freezing contain methane with admixtures. The abundance of inclusions varies, depending on the mineral or well. They have been discussed in the context of hydrocarbon migration and accumulation.

scholarly journals Development of Selective Acidizing Technology for an Oil Field in the Zechstein Main Dolomite

Energies ◽  
2020 ◽  
Vol 13 (22) ◽  
pp. 5940
Author(s):  
Marek Czupski ◽  
Piotr Kasza ◽  
Łukasz Leśniak
Keyword(s):  
Crude Oil ◽  
Acid Treatment ◽  
Oil And Gas ◽  
Oil Field ◽  
Treatment Technology ◽  
Reservoir Water ◽  
Water Matrix ◽  
Acid Sludge ◽  
Water Cut ◽  
Viscoelastic Surfactant

This paper presents laboratory studies based on which a stimulation technology for an oil field located in the Zechstein Main Dolomite was investigated. A large number of oil wells in the Main Dolomite produce significant amounts of reservoir water. Matrix acidizing using conventional acid solutions in such wells has caused a significant increase in water cut, because of their affinity for water. The purpose of this cooperation between the Oil and Gas Institute–NRI and the Brenntag Polska was to develop an acid treatment technology that would not increase the water cut after acidizing treatment in wells where oil production is accompanied by the production of reservoir water. Therefore, a series of tests were performed, including the selection of a suitable viscoelastic surfactant that was sensitive to crude oil. The contact of the gel of the viscoelastic surfactant fluid with crude oil resulted in the reduction of its viscosity The tests described herein include dissolution/dispersion tests, rheological tests, acid sludge tests, compatibility tests, core flow experiments, and corrosion tests, which allowed recipes to be developed for the preflush, diverter, and acidizing liquid. Then, recommendations were established for using these liquids in matrix acid treatment. A series of treatments performed according to this technology allowed the removal of near-wellbore damage without increasing the water cut.

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