Nano Chemical Design for Excessive Water Production Control in Taq Taq Oil Field

2021 ◽  
Author(s):  
Sakar Soka ◽  
Hiwa Sidiq
Keyword(s):  
Oil And Gas ◽  
Production Control ◽  
Oil Field ◽  
Water Production ◽  
Gas Field ◽  
Nano Composite ◽  
Screening Criteria ◽  
Wellhead Pressure ◽  
Oil And Gas Field ◽  
Excessive Water

Abstract A common problem in oil and gas field is premature and excessive water production through higher permeable thief zone, faults, water conning or channeling and natural or induced fracture. Excessive water production impacts the economics of a well through increasing rate of corrosion, emulsion and scale formation, consequently shortening its production life and lowering flowing wellhead pressure. There are several techniques used to control excessive water production such as chemical and mechanical. In this work a novel chemical approach was followed to tackle excessive water production in Taq Taq oil field located in Kurdistan Region Iraq. Water production into the reservoir was determined to be through the fractures as the reservoir units are highly fractured carbonates. Therefore, the chemicals designed by this work were to reduce excessive water production selectively and fracture connectivity in the zones where excessive water production is expected. Three nano-solutions have been prepared and investigated for their rheological properties. Only one is selected and met the field screening criteria. The composition of the nano-solutions were mainly polyacrylamide mixed with nano composite of cement, clay and inorganic cross-linker. All nano-solution underwent extensive screening and studied for their mechanical strength, toughness and tensile module. Results showed that nano-solutions strength increases with increasing the nano concentration. Similarly, their viscosity and degradation resistance are improved noticeably with nano composites. The scanning Electron Microscopy (SEM) was also used to characterized the nano size and distribution studied by this work.

THE DEVELOPMENT OF THE TIRRAWARRA OIL AND GAS FIELD

1984 ◽  
Vol 24 (1) ◽  
pp. 278
Author(s):  
H. T. Pecanek ◽  
I. M. Paton
Keyword(s):  
Carbon Dioxide ◽  
Oil And Gas ◽  
Gas Injection ◽  
Oil Field ◽  
Oil Reservoir ◽  
Gas Reservoirs ◽  
Gas Field ◽  
Associated Gas ◽  
Oil And Gas Field ◽  
Cooper Basin

The Tirrawarra Oil and Gas Field, discovered in 1970 in the South Australian portion of the Cooper Basin, is the largest onshore Permian oil field in Australia. Development began in 1981 as part of the $1400 million Cooper Basin Liquids ProjectThe field is contained within a broad anticline bisected by a north-south sealing normal fault. This fault divides the Tirrawarra oil reservoir into the Western and Main oil fields. Thirty-four wells have been drilled, intersecting ten Patchawarra Formation sandstone gas reservoirs and the Tirrawarra Sandstone oil reservoir. Development drilling discovered three further sandstone gas reservoirs in the Toolachee Formation.The development plan was based on a seven-spot pattern to allow for enhanced oil recovery by miscible gas drive. The target rates were 5400 barrels of oil (860 kilolitres) per day with 13 million ft3 (0.37 million m3) per day of associated gas and 70 million ft3 (2 million m') per day of wet, non-associated gas. Evaluation of early production tests showed rapid decline. The 100 ft (30 m) thick, low-permeability Tirrawarra oil reservoir was interpreted as an ideal reservoir for fracture treatment and as a result all oil wells have been successfully stimulated, with significant improvement in well production rates.The oil is highly volatile but miscibility with carbon dioxide has been proven possible by laboratory tests, even though the reservoir temperature is 285°F (140°C). Pilot gas injection will assess the feasibility of a larger-scale field-wide pressure maintenance scheme using miscible gas. Riot gas injection wells will use Tirrawarra Field Patchawarra Formation separator gas to defer higher infrastructure costs associated with the alternative option of piping carbon dioxide from Moomba, the nearest source.

LANDSCAPE MAP OF BYTKIVSKE OIL FIELD AND NEIGHBORING TERRITORIES OF THE CARPATHIAN REGION

2017 ◽  
Vol 31 (2) ◽  
pp. 49-55
Author(s):  
Yaroslav Adamenko ◽  
◽  
Mirela Coman ◽  
Oleh Adamenko ◽  
Keyword(s):  
Oil And Gas ◽  
Gas Production ◽  
Oil Field ◽  
Nature Protection ◽  
Gas Field ◽  
Oil And Gas Production ◽  
Main Research ◽  
Oil And Gas Field ◽  
Age Features ◽  
Landscape Map

Environmentally safe oil and gas production demands permanent control for the development of ecological situation which should be managed on the basis of existing nature protection requirements and corresponding instruction documents. Purpose of the research and formulation of the problem is to select landscape complexes at the hierarchical levels of locations and facies in the Bykiv oil and gas field to make landscape map with morphological genetic and age features of landscape structure as the basis of environmental assessment of oil and gas field impact on the natural geosystems. Presentation of the main research material with full justification of the received scientific results. Landscape analysis of the investigated area allowed to select, ground and make mapping the following landscape complexes: landscape localities, foothill landscape complexes. Characteristic feature of the Bytkiv oil and gas field and neighborhoods is their high-altitude stratification from middle and lowmountainous to foothills and lowlands. The genesis or origin of the area under study is various - from denudation relics of the top peneplenization surface of leveling much younger pedyplenization surface pediments on the transition from mountainous to foothill relief, to deeply portioned erosionally active steep slopes and stairstepping of the river terraces. Age boundaries of the created landscape structures were determined on the availability of adjoint sedimentary formations from the producents of bedrock destruction, resedimented eolivan, deluvial, proluvial and alluvial processes.

Lost Hills Solar Project: Powering an Oil and Gas Field with California Sunshine

2021 ◽  
pp. 1-9
Author(s):  
T. N. Demayo ◽  
N. K. Herbert ◽  
D. M. Hernandez ◽  
J. J. Hendricks ◽  
B. Velasquez ◽  
...  
Keyword(s):  
Renewable Energy ◽  
Energy Storage ◽  
Oil And Gas ◽  
Oil Field ◽  
Carbon Intensity ◽  
Solar Pv ◽  
Gas Field ◽  
Solar Plant ◽  
Oil And Gas Field ◽  
Solar Electricity

Summary This paper outlines one of the first efforts by a major oil and gas company to build a net-exporting, behind-the-meter solar photovoltaic (PV) plant to lower the operating costs and carbon intensity of a large, mature oil and gas field. The 29 MWAC (35 MWDC) Lost Hills solar plant in Lost Hills, California, USA, commissioned in April 2020, covers approximately 220 acres on land adjacent to the oil field and is designed to provide more than 1.4 TWh of solar energy over 20 years to the field’s oil and gas production and processing facilities. The upgrades to the electrical infrastructure in the field also include new technology to reduce the risk of sulfur hexafluoride emissions, another potent greenhouse gas (GHG). Before the solar project, the Lost Hills field was importing all its electricity from the grid. With the introduction of the Innovative Crude Program as part of California’s Low Carbon Fuel Standard (LCFS) and revisions to the California Public Utilities Commission Net Energy Metering program, Lost Hills was presented with a unique opportunity to reduce its imported electricity expenses and reduce its carbon intensity, while also generating LCFS credits. The solar plant was designed to power the field during the day and export excess power to the grid to help offset nighttime electricity purchases. It operates under a power purchase agreement (PPA) with the solar PV provider and, initially, will meet approximately 80% of the oil field’s energy needs. Future plans include incorporating 20 MWh of lithium-ion batteries, direct current (DC)–coupled with the solar inverters. This energy storage system will increase the amount of solar electricity fed directly into the field and reduce costs by controlling when the site uses stored solar electricity rather than electricity from the grid. The battery system will also increase the number of LCFS credits by 15% over credits generated by solar alone. Together, solar power and energy storage provide a robust renewable energy solution. This project will generate multiple cobenefits for the Lost Hills oil field by lowering the cost of power, reducing GHG emissions, generating state LCFS credits and federal Renewable Energy Certificates, and demonstrating a commitment to energy transition by investing in renewable technology. Conceivably, the Lost Hills solar project can be a model for similar future projects in other oil fields, not only in California, but across the globe.

OFFSHORE GIPPSLAND BASIN FIELDS

1971 ◽  
Vol 11 (1) ◽  
pp. 85 ◽  
Author(s):  
B. R. Griffith ◽  
E. A. Hodgson
Keyword(s):  
Lower Cretaceous ◽  
Oil And Gas ◽  
Oil Field ◽  
Gas Field ◽  
Field Development ◽  
Oil And Gas Field ◽  
Cumulative Production ◽  
Gippsland Basin ◽  
Offshore Field ◽  
Unconformity Surface

The offshore Gippsland Basin, underlies the continental shelf and slope between eastern Victoria and Tasmania.The basin is filled with up to 25,000' of sediment, varying in age from Lower Cretaceous to Recent. The Lower Cretaceous section is represented by at least 10,000' of nonmarine greywackes of the Strzelecki Group. The overlying sediments of Upper Cretaceous to Eocene age comprise the interbedded sandstones, siltstones, shales and coals of the Latrobe Group, with a cumulative thickness of about 15,000'. Offshore, the Latrobe Group is overlain unconformably by up to 1500' of calcareous mudstones of the Lakes Entrance Formation and up to 5000' of Gippsland Limestone carbonates. Pliocene to Recent carbonates, reaching a maximum thickness of about 1000', complete the sedimentary section of the basin.Australia's first commercial offshore field, the Barracouta oil and gas field, was discovered in the Gippsland Basin in February 1965. Further exploratory drilling over the following two and a half years led to the discovery of the Marlin gas field and the Kingfish and Halibut oil fields.The principal hydrocarbon accumulations are reservoired by sediments of the Latrobe Group within closed structural highs on the Latrobe unconformity surface. Seal is provided by the mudstones and marls of the Lakes Entrance Formation and Gippsland Limestone.A field development programme was initiated immediately after Barracouta had been confirmed as a commercial gas reservoir. By the end of 1967, the Barracouta 'A' platform had been erected. Construction and positioning of the Marlin, Halibut and the two Kingfish platforms followed.To date development drilling has been completed on the Barracouta and Halibut fields, while development of the Marlin field has been temporarily suspended following completion of four wells. Development of the Kingfish oil field which commenced in March 1970, is still in a relatively early stage.The Barracouta field has been producing gas and oil since March and October, 1969 respectively. The Marlin gas field was put on stream in November, 1969 and the Halibut oil field in March 1970. As yet no wells drilled in the Kingfish oil field have been completed for production.The four fields provide a major source of hydrocarbons for the Australian market. By the end of September, 1970 cumulative production of sales quality gas from the Barracouta and Marlin fields was almost 23 BCF. Cumulative production of stabilised oil from Barracouta was 2 million barrels and over 26 million barrels from Halibut.

Lost Hills Solar Project: Powering an Oil and Gas Field with California Sunshine

2021 ◽  
Author(s):  
Trevor N. Demayo ◽  
Nevil K. Herbert ◽  
Dulce M. Hernandez ◽  
Jana J. Hendricks ◽  
Beberly Velasquez ◽  
...  
Keyword(s):  
Renewable Energy ◽  
Energy Storage ◽  
Oil And Gas ◽  
Oil Field ◽  
Carbon Intensity ◽  
Solar Pv ◽  
Gas Field ◽  
Solar Plant ◽  
Oil And Gas Field ◽  
Solar Electricity

Abstract This paper outlines one of the first efforts by a major oil and gas company to build a net exporting, behind the meter solar photovoltaic (PV) plant to lower the operating costs and carbon intensity of a large, mature oil and gas field in Lost Hills, California. The 29 MWAC (35 MWDC) Lost Hills solar plant, commissioned in April 2020, covers approximately 220 acres on land adjacent to the oil field and is designed to provide more than 1.4 billion kilowatt hours of solar energy over 20 years to the field's oil and gas field production and processing facilities. The upgrades to the electrical infrastructure in the field also include new technology to reduce the risk of sulfur hexafluoride (SF6) emissions, another potent greenhouse gas (GHG). Prior to solar, the Lost Hills field was importing all its electricity from the grid. With the introduction of the Innovative Crude Program as part of California's Low Carbon Fuel Standard (LCFS) and the revisions to the California Public Utilities Commission Net Energy Metering program, Lost Hills was presented with a unique opportunity to reduce its imported electricity expenses, reduce its carbon intensity, while also generating LCFS credits. The plant was designed to power the field during the day and export excess power to the grid to help offset night-time electricity purchases. The solar plant operates under a Power Purchase Agreement (PPA) with the solar PV provider and, initially, will meet approximately 80% of the oil field's energy needs. Future plans include the incorporation of lithium ion batteries, DC-coupled with the solar inverters, and with a total capacity of 20 MWh. This energy storage system will increase the amount of solar electricity fed directly into the field and reduce costs by controlling when the site uses stored solar electricity rather than electricity from the grid. The battery system will also increase the number of LCFS credits by 15% over credits generated by solar alone. Together, solar power plus energy storage provides a robust renewable energy solution. This project will generate multiple co-benefits for the Lost Hills oil field by lowering the cost of power, reducing GHG emissions, generating state LCFS credits and federal Renewable Energy Certificates, and demonstrating a commitment to energy transition by investing in renewable technology. Hopefully, Lost Hills solar can be a model for similar future projects in other oil fields, not only in California, but across the globe.

Hydrogeological conditions of the Mesozoic hydrogeological basin within the Russkoye gas and oil field

2020 ◽  
pp. 20-35
Author(s):  
V. A. Beshentsev ◽  
Yu. I. Salnikova ◽  
S. V. Vorobjeva
Keyword(s):  
Oil And Gas ◽  
Water Pressure ◽  
Regional Distribution ◽  
Geological Structure ◽  
Oil Field ◽  
Natural Conditions ◽  
Gas Field ◽  
Pressure System ◽  
The Earth ◽  
Oil And Gas Field

The article is devoted to the hydrogeochemical conditions of the Mesozoic hydrogeological basin within the Russkoye oil and gas field. The text gives valuable information on the natural conditions, geological structure, geotemperature regime of the bowels of the Earth and the composition of groundwater of the Aptian-Albian-Cenomanian, Neocomian, and Jurassic hydrogeological complexes. The change in the composition of groundwater in the section of the AptianAlbian-Cenomanian complex has been revealed. Vertical inversion zoning that traces the underlying the Neocomian complex is established. We describe the main features of the regional distribution of reservoir pressures. Hydrodynamic schemes of the Aptian-Albian-Cenomanian, Neocomian, and Jurassic hydrogeological complexes are given in the article. These schemes show that the Russkoye gas and oil field is located in the zone of low reservoir pressures. The above vertical inversion zoning and low reservoir pressures are associated with the location of the field within the elisional hydrodynamic water pressure system of the Yamal-Gydan lineaments. The data of the block-fault model of the considered field were used in the course of the study. The block-fault structure predetermined the migration of hydrocarbons and the formation of tectonically screened deposits.

scholarly journals EOR and Reservoir preservation in Rag-e Sefied Oil and Gas Field: With Base of Reservoir Fluid Geochemistry

2021 ◽  
Author(s):  
Seyed Hossein Hashemi ◽  
Abas Niknam ◽  
Amir Karimian Torghabeh
Keyword(s):  
Oil And Gas ◽  
Inorganic Ions ◽  
Operating Conditions ◽  
Oil Field ◽  
Reservoir Rock ◽  
Formation Water ◽  
Gas Reservoirs ◽  
Accurate Analysis ◽  
Gas Field ◽  
Oil And Gas Field

Abstract Mineral ions are present in aqueous solutions in most industrial and operational processes, including oil operation. Accurate analysis and sampling of the formation water and its dissolved minerals during the operation of the oil industry can be a valuable solution for the efficient management of oil production from the reservoir. Therefore, in this study, evaluation of inorganic ions and their concentration in formation water for 6 well samples in the Rag-e Sefid Oil and Gas Field was considered. According to the results of this study, calcium, sodium and magnesium cations as well as sulfate, bicarbonate and chloride anions are soluble inorganic ions in the Rag Sefid Oil Field Formation. Also, in this study formation of inorganic sediment CaSO4, CaSO4.2H2O, CaCO3 and MgCO3 was studied. Based on the operating conditions of the Rag-e Sefid Oil and Gas field, the formation of calcium sulfate and calcium carbonate mineral deposits is significant. With base of geochemical analysis in reservoir rock samples and ions ratios these reservoir is good for preservation. The results thus provide more accurate predictions in terms of where to find gas reservoirs in the Zagros basin, and can lead to significantly better exploitation of these resources and also estimation of rate of sedimentation for EOR.

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