scholarly journals Study of thin layered reservoirs with toroidal sources and receivers (on the example of the Priobskoe oil field)

Author(s):  
I. V. Mikhaylov ◽  
D. V. Velesov ◽  
V. N. Glinskikh

On the example of the Priobskoye oil field of the West Siberian oil and gas province, we show the relevance of studying thin-layered oil-saturated reservoirs, as well as consider the corresponding world experience. The operating principle of a probe system with toroidal sources and receivers is described, after which we perform 2D finite-difference simulation and analysis of its signals in typical geoelectric reservoir models. The dependence of the signals on the resistivity anisotropy coefficient is demonstrated. In realistic geoelectric sections of the Priobskoye field, obtained by numerical inversion of BKZ field data, 2D finite-difference simulation for the system with toroids is conducted. It implies the fundamental possibility of investigating thin-layered electrically anisotropic deposits of the Priobskoye field by means of the system with toroidal sources and receivers.

2012 ◽  
Vol 430-432 ◽  
pp. 1773-1776
Author(s):  
Jun Peng Liu ◽  
Xiao Lan Luo ◽  
Meng Lan Duan ◽  
Kai Tian ◽  
Wei Feng

Developing deepwater oil and gas resource is the trend of oil industry development. It is important to select a proper development scenario and riser system which works as a key tool to connect subsea equipment and surface body in a deepwater project. Based on the West Africa’s deepwater target field CNOOC owned, this paper designs a detailed development scenario-FPSO +SPS +Shuttle tanker according to the following factors: well, reservoir layout, environment, floaters availability, commercial considerations. Floater and riser selection interact with each other. Considering the development scenario, a basic method for selecting a proper riser system is presented. As a result, FSHR is selected from existing risers based on technology, reliability, risk and cost.


2021 ◽  
pp. 61-72
Author(s):  
I. G. Sabanina ◽  
T. V. Semenova ◽  
Yu. Ya. Bolshakov ◽  
S. V. Vorobjeva

Currently, most of the oil fields in the West Siberian oil and gas province are in the final stage of development. There is water-cut in production, a decrease in oil production, and the structure of residual reserves deteriorates. The search and application of the most successful scientific methods and technologies for improving oil recovery in the development of fields is quite an urgent task.It should be taken into account that hydrophobic reservoirs are common in the oil fields of Western Siberia, and when applying the method of reservoir flooding, this fact should be taken into account and a more detailed approach should be taken to the study of capillary forces to prevent flooding of productive objects. Despite the good knowledge of the West Siberian megabasin, some fundamental issues of its structure and oil and gas potential remain debatable.The article proposes methods for improving oil recovery of the BS10 formation of the Ust-Balykskoye oil field based on the study of capillary pressures in productive reservoir formations, and provides recommendations for the placement of injection wells. The study of the capillary properties of reservoir rocks will significantly improve the efficiency of exploration and field operations in oil fields.


2019 ◽  
pp. 121-132
Author(s):  
Larisa N. Gileva ◽  
Natalya V. Egorova

The growth of energy consumption entails an increase in the production of hydrocarbons, the number of fields, which are involved in this process, and the territory of license areas. Overall, environmental impact may be increased. Northern territories of our country are more exposed to anthropogenic impact from the oil and gas facilities because of huge oil and gas reserves availability. Therefore, the strategic developments for the greening of production on the basis of the concept of sustainable exploitation of these territories are very important. Suggested concept involves a balanced activity that provides high economic efficiency and environmental safety, aimed at reducing adverse anthropogenic consequences.The assessment of the impact of oil and gas facilities on the environment was carried out in the territory of the West Chatylkinsky field of Krasnoselkupsky district of the Yamalo-Nenets Autonomous Okrug. The results obtained allowed assessing the degree of impact of cluster sites and communication corridors of the objects of the land and property complex of the oil field and developing recommendations to reduce adverse anthropogenic consequences in order to protect the environment and ensure the greening of land use.


1977 ◽  
Author(s):  
James W. Clarke ◽  
O.W. Girard ◽  
James Peterson ◽  
Jack Rachlin

2016 ◽  
Vol 53 (4) ◽  
pp. 283-329
Author(s):  
Marieke Dechesne ◽  
Jim Cole ◽  
Christopher Martin

This two-day field trip provides an overview of the geologic history of the North Park–Middle Park area and its past and recent drilling activity. Stops highlight basin formation and the consequences of geologic configuration on oil and gas plays and development. The trip focuses on work from ongoing U.S. Geological Survey research in this area (currently part of the Cenozoic Landscape Evolution of the Southern Rocky Mountains Project funded by the National Cooperative Geologic Mapping Program). Surface mapping is integrated with perspective from petroleum exploration within the basin. The starting point is the west flank of the Denver Basin to compare and contrast the latest Cretaceous through Eocene basin fill on both flanks of the Front Range. The next stop continues on the south end of the North Park–Middle Park area, about 60 miles [95km] west from the first stop. A general clockwise loop is described by following U.S. Highway 40 from Frasier via Granby and Kremmling to Muddy Pass after which CO Highway 14 is followed to Walden for an overnight stay. On the second day after a loop north of Walden, the Continental Divide is crossed at Willow Creek Pass for a return to Granby via Highway 125. The single structural basin that underlies both physiographic depressions of North Park and Middle Park originated during the latest Cretaceous to Eocene Laramide orogeny (Tweto, 1957, 1975; Dickinson et al., 1988). It largely filled with Paleocene to Eocene sediments and is bordered on the east by the Front Range, on the west by the Park Range and Gore Range, on the north by Independence Mountain and to the south by the Williams Fork and Vasquez Mountains (Figure 1). This larger Paleocene-Eocene structural basin is continuous underneath the Continental Divide, which dissects the basin in two approximately equal physiographic depressions, the ‘Parks.’ Therefore Cole et al. (2010) proposed the name ‘Colorado Headwaters Basin’ or ‘CHB,’ rather than North Park–Middle Park basin (Tweto 1957), to eliminate any confusion between the underlying larger Paleocene-Eocene basin and the two younger depressions that developed after the middle Oligocene. The name was derived from the headwaters of the Colorado, North Platte, Laramie, Cache La Poudre, and Big Thompson Rivers which are all within or near the study area. In this field guide, we will use the name Colorado Headwaters Basin (CHB) over North Park–Middle Park basin. Several workers have described the geology in the basin starting with reports from Marvine who was part of the Hayden Survey and wrote about Middle Park in 1874, Hague and Emmons reported on North Park as part of the King Survey in 1877, Cross on Middle Park (1892), and Beekly surveyed the coal resources of North Park in 1915. Further reconnaissance geologic mapping was performed by Hail (1965 and 1968) and Kinney (1970) in the North Park area and by Izett (1968, 1975), and Izett and Barclay (1973) in Middle Park. Most research has focused on coal resources (Madden, 1977; Stands, 1992; Roberts and Rossi, 1999), and oil and gas potential (1957, all papers in the RMAG guidebook to North Park; subsurface structural geologic analysis of both Middle Park and North Park (the CHB) by oil and gas geologist Wellborn (1977a)). A more comprehensive overview of all previous geologic research in the basin can be found in Cole et al. (2010). Oil and gas exploration started in 1925 when Continental Oil's Sherman A-1 was drilled in the McCallum field in the northeast part of the CHB. It produced mostly CO2 from the Dakota Sandstone and was dubbed the ‘Snow cone’ well. Later wells were more successful finding oil and/or gas, and exploration and production in the area is ongoing, most notably in the unconventional Niobrara play in the Coalmont-Hebron area.


2020 ◽  
Vol 58 (3) ◽  
pp. 397-424
Author(s):  
Jesse Salah Ovadia ◽  
Jasper Abembia Ayelazuno ◽  
James Van Alstine

ABSTRACTWith much fanfare, Ghana's Jubilee Oil Field was discovered in 2007 and began producing oil in 2010. In the six coastal districts nearest the offshore fields, expectations of oil-backed development have been raised. However, there is growing concern over what locals perceive to be negative impacts of oil and gas production. Based on field research conducted in 2010 and 2015 in the same communities in each district, this paper presents a longitudinal study of the impacts (real and perceived) of oil and gas production in Ghana. With few identifiable benefits beyond corporate social responsibility projects often disconnected from local development priorities, communities are growing angrier at their loss of livelihoods, increased social ills and dispossession from land and ocean. Assuming that others must be benefiting from the petroleum resources being extracted near their communities, there is growing frustration. High expectations, real and perceived grievances, and increasing social fragmentation threaten to lead to conflict and underdevelopment.


Author(s):  
Zhenhua Zhang ◽  
Longbin Tao

Slug flow in horizontal pipelines and riser systems in deep sea has been proved as one of the challenging flow assurance issues. Large and fluctuating gas/liquid rates can severely reduce production and, in the worst case, shut down, depressurization or damage topside equipment, such as separator, vessels and compressors. Previous studies are primarily based on experimental investigations of fluid properties with air/water as working media in considerably scaled down model pipes, and the results cannot be simply extrapolated to full scale due to the significant difference in Reynolds number and other fluid conditions. In this paper, the focus is on utilizing practical shape of pipe, working conditions and fluid data for simulation and data analysis. The study aims to investigate the transient multiphase slug flow in subsea oil and gas production based on the field data, using numerical model developed by simulator OLGA and data analysis. As the first step, cases with field data have been modelled using OLGA and validated by comparing with the results obtained using PIPESYS in steady state analysis. Then, a numerical model to predict slugging flow characteristics under transient state in pipeline and riser system was set up using multiphase flow simulator OLGA. One of the highlights of the present study is the new transient model developed by OLGA with an added capacity of newly developed thermal model programmed with MATLAB in order to represent the large variable temperature distribution of the riser in deep water condition. The slug characteristics in pipelines and temperature distribution of riser are analyzed under the different temperature gradients along the water depth. Finally, the depressurization during a shut-down and then restart procedure considering hydrate formation checking is simulated. Furthermore, slug length, pressure drop and liquid hold up in the riser are predicted under the realistic field development scenarios.


2021 ◽  
Author(s):  
Joseph Rizzo Cascio ◽  
Antonio Da Silva ◽  
Martino Ghetti ◽  
Martino Corti ◽  
Marco Montini

Abstract Objectives/Scope The benefits of real-time estimation of the cool down time of Subsea Production System (SPS) to prevent formation of hydrates are shown on a real oil and gas facility. The innovative tool developed is based on an integrated approach, which embeds a proxy model of SPS and hydrate curves, exploiting real-time field data from the Eni Digital Oil Field (eDOF, an OSIsoft PI based application developed and managed by Eni) to continuously estimate the cool down time before hydrates are formed during the shutdown. Methods, Procedures, Process The Asset value optimization and the Asset integrity of hydrocarbon production systems are complex and multi-disciplinary tasks in the oil and gas industry, due to the high number of variables and their synergy. An accurate physical model of SPS is built and, then, used to develop a proxy model, which integrates hydrate curves at different MeOH concentration, being able to estimate in real time the cool down time of SPS during the shutdown exploiting data from subsea transmitters made available by eDOF in order to prevent formation of hydrates. The tool is also integrated with a user-friendly interface, making all relevant information readily available to the operators on field. Results, Observations, Conclusions The integrated approach provides a continues estimation of cool down time based on real time field data (eDOF) in order to prevent formation of hydrates and activate preservation actions. An accurate physical model of SPS is built on a real business case using Olga software and cool down curves simulated considering different operating shutdown scenarios. Hydrate curves of the considered production fluid are also simulated at different MeOH concentration using PVTsim NOVA software. Off-line simulated curves are then implemented as numerical tables combined with eDOF data by an Eni developed fast executing proxy model to produce estimated cool down time before hydrates are formed. A graphic representation of SPS behavior and its cool down time estimation during shutdown are displayed and ready to use by the operators on field in support of the operations, saving cost and time. Novel/Additive Information The benefits of real time estimation of the cool down time of SPS to prevent hydrates formation are shown in terms of saving of time and cost during the shutdown operations on a real case application. This integrated approach allows to rely on a continue, automatic and acceptably accurate estimate of the available time before hydrates are formed in SPS, including the possibility to be further developed for cases where subsea transmitters are not available or extended to other flow assurance issues.


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