EOR Techniques Tailored to Venezuelan Conventional and Unconventional Oils: Critical Review

2020 ◽  
Author(s):  
Fernancelys Rodriguez M.
Keyword(s):  
Oil Production ◽  
Mobility Control ◽  
Heavy Oils ◽  
The North ◽  
Viscous Oil ◽  
Fluid Systems ◽  
Producer Country ◽  
Chemical Eor ◽  
Gas Flooding ◽  
Compositional Gradients

Abstract Venezuela has been ranked as a potential oil producer country thanks to its huge reserves of conventional and unconventional oils. Conventional reservoirs with complex fluid systems, located in the North of Monagas state, where it is possible to observe thick fluid columns with significant compositional gradients (showing changes from gas condensate to non-mobile oil-Tar mat). In these types of reservoirs EOR methods such as miscible gas flooding have been successfully applied to compensate pressure decline and avoid asphaltene deposition issues. Production of unconventional oils, the largest highly-viscous oil reservoir of La Faja Petrolifera del Orinoco (La FPO), demands great challenges. Discovered in the 1930’s, the first rigorous evaluations of this reservoir started in the 1980s [1]; those huge deposits of highly viscous oils were considered technically and economically unattractive at that time. Due to production decline of conventional oil reservoirs, efforts are being done by the Venezuelan National Oil Company and collaborators to develop EOR projects to achieve increasing oil production in unconventional (heavy and extra-heavy) reservoirs, being the most promising options thermal and chemical EOR methods. Some authors agree that in the FPO, only 40–65% (depending on the site) of the oil-bearing formations is suitable for thermal EOR methods. Recent works have been showing the potential of chemical EOR for extra-heavy oils in La FPO [2, 3, 4, 5, 6, 7, 8, 9], mostly for mobility control and mobilization of residual oil. This work presents a literature review of the EOR projects in Venezuela for conventional and highly viscous oils, based on both lab and field experiences, and the perspectives for applications to increase Venezuelan oil production.

Review of Chemical EOR Projects in Venezuela: From Light to Extra-Heavy Oil Reservoirs

2021 ◽  
Author(s):  
Fernancelys Rodriguez M.
Keyword(s):  
Oil Recovery ◽  
Mobility Control ◽  
Oil Reservoirs ◽  
Oil Reserves ◽  
Viscous Oil ◽  
Lake Maracaibo ◽  
Heavy Oil Reservoirs ◽  
Producer Country ◽  
Chemical Eor ◽  
Water Treatments

Abstract Venezuela is widely recognized as an oil producer country of great potential thanks to its huge hydrocarbon resources located in Eastern Venezuela and Maracaibo basins, comprising the largest oil reserves in the world, with around 302 billion barrels according to recent OPEC and EIA estimates [1]. Despite those immense hydrocarbon resources, oil production in Venezuela is a challenge in mature and waterflooded reservoirs, as well as in thin highly viscous oil reservoirs where thermal IOR/EOR methods are not technically and/or economically feasible. This is the case of many oil fields in Lake Maracaibo and in La Faja Petrolifera Del Orinoco (La FPO), where the application of Chemical Enhanced Oil Recovery (CEOR) methods is being envisaged with a view to increasing oil recovery factors. The objective of this article is to review most of the Venezuelan CEOR projects reported in the literature to identify the main insights/status of each reported project and its potentiality of application to increase oil recovery. A detailed description of each project and its main conclusions is given. According to this literature review, CEOR project evaluations for Venezuelan reservoirs have been performed mostly at laboratory and numerical simulation scales, including several pilot test designs. Only 2 executed pilot tests have been reported (ASP flooding at VLA-6/9/21 Field in Lake Maracaibo and polymer flooding at Petrocedeño Field in La FPO). Despite the encouraging results in terms of oil recovery at laboratory scale, the greatest challenges related to the application of CEOR methods in Venezuelan reservoirs are linked to technical and economic aspects (e.g. high adsorption/retention of chemicals, mobility control, complex emulsions, separation of phases, water treatments, costs of investment, oil prices, etc.).

Planning And Development Of Polymer Assisted Surfactant Flooding For The Gullfaks Field, Norway

1998 ◽  
Vol 1 (02) ◽  
pp. 161-168 ◽  
Author(s):  
T. Maldal ◽  
E. Gilje ◽  
R. Kristensen ◽  
T. Karstad ◽  
A. Nordbotten ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Current Drive ◽  
Mobility Control ◽  
Residual Oil ◽  
Surfactant Flooding ◽  
Oil Viscosity ◽  
Full Field ◽  
The North ◽  
Injection Water

Abstract This paper presents parts of the work performed in order to develop and qualify a Polymer Assisted Surfactant Flooding (PASF) system for economical use in the Gullfaks Field. The paper addresses experimental work done in the laboratory, numerical simulation of PASF, and the evaluation of the potential for PASF in full field scale. The experimental part comprises core flooding experiments at different temperatures, pressures, and gas-oil ratios in order to optimise the PASF system for the Gullfaks Brent formation conditions. The surfactant in the PASF system is a branched sulphonate (5000 ppm) and xanthan (500 ppm). The surfactant-polymer slug is followed by a slug of xanthan (500 ppm) for mobility control. No cosolvent is used. In coreflood experiments more than 70 percent of the waterflood residual oil was recovered. By using reservoir simulation a suitable pilot area was found in the Brent reservoir. Additional results from simulations were the amount of chemicals, the time needed for the pilot test, and additional oil recovery. Much effort was put into estimating the full field PASF potential. Firstly, the areas of the field where PASF possibly could be used were selected. Key factors were existing and planned well locations, production data, and long term production forecasts. Then the amount of chemicals needed and the expected technical efficiency for each area were calculated. To verify these calculations, an area of the field containing two possible injection wells, and three producers, was selected for a simulation study. This area was considered as the most promising area for PASF. The main conclusion from this work is that, with the present crude oil price and chemical costs, the PASF process is not economical attractive for use in the Gullfaks field, mainly because the residual oil was considerable lower than believed at project start. Introduction The Gullfaks field is located in the north-eastern part of block 34/10 in the Norwegian sector of the North Sea. The oil production started in December 1986 and the cumulative oil production to date is 168 mill. Sm3 or 59 % of recoverable reserves. Water injection is the current drive mechanism, aiming at maintaining reservoir pressure above the bubble point. At the project start in 1989, the Gullfaks field was from a technical standpoint a prime target for enhanced oil recovery . The residual oil saturation after waterflooding was believed to be about 0.35, which indicated a high technical potential for surfactant flooding. Most of the reservoir characteristics are favourable for PASF, i. e. multidarcy sands, low oil viscosity (1.5 cP), relatively low reservoir temperature (70 C) and low salinity of the formation water (42000 ppm) and moderate low clay content (5-10 %). A single well injection test with surfactant alone was performed during the first half of 1992. The surfactant was successfully injected without any special treatment of the injection water, and the test confirmed that residual oil was mobilised by the surfactant. Exxon conducted a series of five pilot tests in the Loudon field from 1980 to 1989. The test sizes ranged from a single pattern of 2800 m2 to multi-pattern tests with pilot areas of 161600 m2 and 323200 m2 areas, respectively. For the 2800 m2 pilot, recovery was 68 % of the waterflood residual oil. In the larger multi-pattern floods, oil recovery dropped to 26.9 % in the 161600 m2 and 33.4 % in the 323200 m2 project. The tests showed that the use of polymer in the injection water is crucial for obtaining a successful surfactant flooding. An other observation in these field tests was that the surfactant retention was less than half of that measured in conventional laboratory coreflood experiments. This was explained by a change of wettability from aerobic, oxidising conditions, in the laboratory, to the anaerobic, reducing conditions, in the reservoir.

Russian Oil: Production and Exports

2003 ◽  
pp. 136-146
Author(s):  
K. Liuhto
Keyword(s):  
Baltic Sea ◽  
Statistical Data ◽  
Oil Production ◽  
The Baltic Sea ◽  
North West ◽  
The North ◽  
Oil Transportation ◽  
Sea Ports ◽  
The Baltic

Statistical data on reserves, production and exports of Russian oil are provided in the article. The author pays special attention to the expansion of opportunities of sea oil transportation by construction of new oil terminals in the North-West of the country and first of all the largest terminal in Murmansk. In his opinion, one of the main problems in this sphere is prevention of ecological accidents in the process of oil transportation through the Baltic sea ports.

Numerical Optimization of WAG Injection in a Sandstone Field using a Coupled Surface and Subsurface Model

2021 ◽  
Author(s):  
Thaer I. Ismail ◽  
Emad W. Al-Shalabi ◽  
Mahmoud Bedewi ◽  
Waleed AlAmeri
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Coupled Model ◽  
Sensitivity Study ◽  
Mobility Control ◽  
Base Case ◽  
The North ◽  
Injection Process ◽  
Interaction Terms ◽  
Wag Injection

Abstract Gas injection is one of the most commonly used enhanced oil recovery (EOR) methods. However, there are multiple problems associated with gas injection including gravity override, viscous fingering, and channeling. These problems are due to an adverse mobility ratio and cause early breakthrough of the gas resulting, in poor recovery efficiency. A Water Alternating Gas (WAG) injection process is recommended to resolve these problems through better mobility control of gas, leading to better project economics. However, poor WAG design and lack of understanding of the different factors that control its performance might result in unfavorable oil recovery. Therefore, this study provides more insight into improving WAG oil recovery by optimizing different surface and subsurface WAG parameters using a coupled surface and subsurface simulator. Moreover, the work investigates the effects of hysteresis on WAG performance. This case study investigates a field named Volve, which is a decommissioned sandstone field in the North Sea. Experimental design of factors influencing WAG performance on this base case was studied. Sensitivity analysis was performed on different surface and subsurface WAG parameters including WAG ratio, time to start WAG, total gas slug size, cycle slug size, and tubing diameter. A full two-level factorial design was used for the sensitivity study. The significant parameters of interest were further optimized numerically to maximize oil recovery. The results showed that the total slug size is the most important parameter, followed by time to start WAG, and then cycle slug size. WAG ratio appeared in some of the interaction terms while tubing diameter effect was found to be negligible. The study also showed that phase hysteresis has little to no effect on oil recovery. Based on the optimization, it is recommended to perform waterflooding followed by tertiary WAG injection for maximizing oil recovery from the Volve field. Furthermore, miscible WAG injection resulted in an incremental oil recovery between 5 to 11% OOIP compared to conventional waterflooding. WAG optimization is case-dependent and hence, the findings of this study hold only for the studied case, but the workflow should be applicable to any reservoir. Unlike most previous work, this study investigates WAG optimization considering both surface and subsurface parameters using a coupled model.

scholarly journals Detailed investigations of the influence of catalyst packing porosity on the performance of THAI-CAPRI process for in situ catalytic upgrading of heavy oil and bitumen

2021 ◽  
Author(s):  
Muhammad Rabiu Ado
Keyword(s):  
Oil Production ◽  
Accessible Surface Area ◽  
Mitigation Strategies ◽  
Catalytic Reactions ◽  
Heavy Oils ◽  
World Energy ◽  
Catalyst Life ◽  
Free Transition ◽  
Accessible Surface

AbstractHeavy oils and bitumen are indispensable resources for a turbulent-free transition to a decarbonized global energy and economic system. This is because according to the analysis of the International Energy Agency’s 2020 estimates, the world requires up to 770 billion barrels of oil from now to year 2040. However, BP’s 2020 statistical review of world energy has shown that the global total reserves of the cheap-to-produce conventional oil are roughly only 520.2 billion barrels. This implies that the huge reserves of the practically unexploited difficult-and-costly-to-upgrade-and-produce heavy oils and bitumen must be immediately developed using advanced upgrading and extraction technologies which have greener credentials. Furthermore, in accordance with climate change mitigation strategies and to efficiently develop the heavy oils and bitumen resources, producers would like to maximize their upgrading within the reservoirs by using energy-efficient and environmentally friendly technologies such as the yet-to-be-fully-understood THAI-CAPRI process. The THAI-CAPRI process uses in situ combustion and in situ catalytic reactions to produce high-quality oil from heavy oils and bitumen reservoirs. However, prolonging catalyst life and effectiveness and maximizing catalytic reactions are a major challenge in the THAI-CAPRI process. Therefore, in this work, the first ever-detailed investigations of the effects of alumina-supported cobalt oxide–molybdenum oxide (CoMo/γ-Al2O3) catalyst packing porosity on the performance of the THAI-CAPRI process are performed through numerical simulations using CMG STARS. The key findings in this study include: the larger the catalyst packing porosity, the higher the accessible surface area for the mobilized oil to reach the inner coke-uncoated catalysts and thus the higher the API gravity and quality of the produced oil, which clearly indicated that sulphur and nitrogen heteroatoms were catalytically removed and replaced with hydrogen. Over the 290 min of combustion period, slightly more oil (i.e. an additional 0.43% oil originally in place (OOIP)) is recovered in the model which has the higher catalyst packing porosity. In other words, there is a cumulative oil production of 2330 cm3 when the catalyst packing porosity is 56% versus a cumulative oil production of 2300 cm3 in the model whose catalyst packing porosity is 45%. The larger the catalyst packing porosity, the lower the mass and thus cost of the catalyst required per m3 of annular space around the horizontal producer well. The peak temperature and the very small amount of produced oxygen are only marginally affected by the catalyst packing porosity, thereby implying that the extents of the combustion and thermal cracking reactions are respectively the same in both models. Thus, the higher upgrading achieved in the model whose catalyst packing porosity is 56% is purely due to the fact that the extent of the catalytic reactions in the model is larger than those in the model whose catalyst packing porosity is 45%.

Seabirds associated with oil production platforms in the North Sea

1986 ◽  
Vol 7 (1) ◽  
pp. 7-14 ◽  
Author(s):  
Mark L. Tasker ◽  
Peter Hope Jones ◽  
Barry F. Blake ◽  
Tim J. Dixon ◽  
Andrew W. Wallis
Keyword(s):  
North Sea ◽  
Oil Production ◽  
The North ◽  
The North Sea

RESEARCH OF LOADS ON DRIVE OF ROD INSTALLATIONS IN LOW SPEED MODE AT HIGH-VISCOUS OIL PRODUCTION

2020 ◽  
Vol 18 (1) ◽  
pp. 120
Author(s):  
K.R. Urazakov ◽  
R.Z. Nurgaliev ◽  
G.I. Bikbulatova ◽  
S.L. Sabanov ◽  
Yu.A. Boltneva
Keyword(s):  
Oil Production ◽  
Low Speed ◽  
Viscous Oil ◽  
Speed Mode
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