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.).

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.

scholarly journals Enhanced Oil Recovery Using CO2 in Alaska

Geosciences ◽  
2021 ◽  
Vol 11 (2) ◽  
pp. 98
Author(s):  
Banabas Dogah ◽  
Vahid Atashbari ◽  
Mohabbat Ahmadi ◽  
Brent Sheets
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Comprehensive Overview ◽  
Thermal Methods ◽  
Oil Reserves ◽  
Viscous Oil ◽  
Co2 Eor ◽  
Permafrost Thawing ◽  
Petroleum Reserves ◽  
Shallow Reservoirs

Alaska holds more than 68 billion barrels of proved oil reserves and more than 36.7 trillion cubic feet of proved natural gas reserves with some special conditions such as proximity to permafrost, making Alaskan petroleum reserves unique. The low temperature in shallow reservoirs prohibited hydrocarbons’ ideal maturation, thereby generating several heavy and viscous oil accumulations in this state. This also limits the enhanced oil recovery (EOR) options, leaving the thermal methods off the table to avoid permafrost thawing, which can cause wellbore collapse. Several solutions have been attempted for improving oil production from heavy and viscous oil in Alaska; however, they have not yielded the desired recovery, and ultimate recovery factors are still less than the global average. One solution identified as a better alternative is using CO2 as an injecting fluid, alternated by water or mixed with other injectants. This paper provides a comprehensive overview of all studies on using CO2 for enhanced oil recovery purposes in Alaska and highlights common and unique challenges this approach may face. The suitability of CO2-EOR methods in the Alaskan oil pools is examined, and a ranking of the oil pools with publicly available data is provided.

scholarly journals Effect of Non-Newtonian Flow on Polymer Flooding in Heavy Oil Reservoirs

Polymers ◽  
2018 ◽  
Vol 10 (11) ◽  
pp. 1225 ◽  
Author(s):  
Xiankang Xin ◽  
Gaoming Yu ◽  
Zhangxin Chen ◽  
Keliu Wu ◽  
Xiaohu Dong ◽  
...  
Keyword(s):  
Porous Media ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Flow Behavior ◽  
Polymer Flooding ◽  
Oil Reservoirs ◽  
Flow In Porous Media ◽  
Newtonian Flow ◽  
Heavy Oil Reservoirs

The flow of polymer solution and heavy oil in porous media is critical for polymer flooding in heavy oil reservoirs because it significantly determines the polymer enhanced oil recovery (EOR) and polymer flooding efficiency in heavy oil reservoirs. In this paper, physical experiments and numerical simulations were both applied to investigate the flow of partially hydrolyzed polyacrylamide (HPAM) solution and heavy oil, and their effects on polymer flooding in heavy oil reservoirs. First, physical experiments determined the rheology of the polymer solution and heavy oil and their flow in porous media. Then, a new mathematical model was proposed, and an in-house three-dimensional (3D) two-phase polymer flooding simulator was designed considering the non-Newtonian flow. The designed simulator was validated by comparing its results with those obtained from commercial software and typical polymer flooding experiments. The developed simulator was further applied to investigate the non-Newtonian flow in polymer flooding. The experimental results demonstrated that the flow behavior index of the polymer solution is 0.3655, showing a shear thinning; and heavy oil is a type of Bingham fluid that overcomes a threshold pressure gradient (TPG) to flow in porous media. Furthermore, the validation of the designed simulator was confirmed to possess high accuracy and reliability. According to its simulation results, the decreases of 1.66% and 2.49% in oil recovery are caused by the difference between 0.18 and 1 in the polymer solution flow behavior indexes of the pure polymer flooding (PPF) and typical polymer flooding (TPF), respectively. Moreover, for heavy oil, considering a TPG of 20 times greater than its original value, the oil recoveries of PPF and TPF are reduced by 0.01% and 5.77%, respectively. Furthermore, the combined effect of shear thinning and a threshold pressure gradient results in a greater decrease in oil recovery, with 1.74% and 8.35% for PPF and TPF, respectively. Thus, the non-Newtonian flow has a hugely adverse impact on the performance of polymer flooding in heavy oil reservoirs.

Experimental Analysis of the Effects of Varying Temperature and Viscosities on Foamy Oil Production

2021 ◽  
Author(s):  
Jasmine Shivani Medina ◽  
Iomi Dhanielle Medina ◽  
Gao Zhang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Elevated Temperatures ◽  
Oil Production ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Gas Recovery ◽  
Foamy Oil ◽  
Heavy Oil Reservoirs ◽  
Pressure Depletion

Abstract The phenomenon of higher than expected production rates and recovery factors in heavy oil reservoirs captured the term "foamy oil," by researchers. This is mainly due to the bubble filled chocolate mousse appearance found at wellheads where this phenomenon occurs. Foamy oil flow is barely understood up to this day. Understanding why this unusual occurrence exists can aid in the transfer of principles to low recovery heavy oil reservoirs globally. This study focused mainly on how varying the viscosity and temperature via pressure depletion lab tests affected the performance of foamy oil production. Six different lab-scaled experiments were conducted, four with varying temperatures and two with varying viscosities. All experiments were conducted using lab-scaled sand pack pressure depletion tests with the same initial gas oil ratio (GOR). The first series of experiments with varying temperatures showed that the oil recovery was inversely proportional to elevated temperatures, however there was a directly proportional relationship between gas recovery and elevation in temperature. A unique observation was also made, during late-stage production, foamy oil recovery reappeared with temperatures in the 45-55°C range. With respect to the viscosities, a non-linear relationship existed, however there was an optimal region in which the live-oil viscosity and foamy oil production seem to be harmonious.

An Experimental Study of Improving Viscous Oil Recovery by Using Hybrid Enhanced Oil Recovery Techniques: A Case Study of Alaska North Slope Reservoir

SPE Journal ◽  
2021 ◽  
pp. 1-20
Author(s):  
Yaoze Cheng ◽  
Yin Zhang ◽  
Abhijit Dandekar ◽  
Jiawei Li
Keyword(s):  
Oil Recovery ◽  
Oil Reservoirs ◽  
Viscosity Reduction ◽  
Displacement Efficiency ◽  
Natural Sand ◽  
Ζ Potential ◽  
Low Salinity ◽  
Viscous Oil ◽  
Reservoir Conditions ◽  
Salinity Water

Summary Shallow reservoirs on the Alaska North Slope (ANS), such as Ugnu and West Sak-Schrader Bluff, hold approximately 12 to 17 × 109 barrels of viscous oil. Because of the proximity of these reservoirs to the permafrost, feasible nonthermal enhanced oil recovery (EOR) methods are highly needed to exploit these oil resources. This study proposes three hybrid nonthermal EOR techniques, including high-salinity water (HSW) injection sequentially followed by low-salinity water (LSW) and low-salinity polymer (LSP) flooding (HSW-LSW-LSP), solvent-alternating-LSW flooding, and solvent-alternating-LSP flooding, to recover ANS viscous oils. The oil recovery performance of these hybrid EOR techniques has been evaluated by conducting coreflooding experiments. Additionally, constant composition expansion (CCE) tests, ζ potential determinations, and interfacial tension (IFT) measurements have been conducted to reveal the EOR mechanisms of the three proposed hybrid EOR techniques. Coreflooding experiments and IFT measurements have been conducted at reservoir conditions of 1,500 psi and 85°F, while CCE tests have been carried out at a reservoir temperature of 85°F. ζ potential determinations have been conducted at 14.7 psi and 77°F. The coreflooding experiment results have demonstrated that all of the three proposed hybrid EOR techniques could result in much better performance in reducing residual oil saturation than waterflooding and continuous solvent flooding in viscous oil reservoirs on ANS, implying better oil recovery potential. In particular, severe formation damage or blockage at the production end occurred when natural sand was used to prepare the sandpack column, indicating that the natural sand may have introduced some unknown constituents that may react with the injected solvent and polymer, resulting in a severe blocking issue. Our investigation on this is ongoing, and more detailed studies are being conducted in our laboratory. The CCE test results demonstrate that more solvent could be dissolved into the tested viscous oil with increasing pressure, simultaneously resulting in more oil swelling and viscosity reduction. At the desired reservoir conditions of 1,500 psi and 85°F, as much as 60 mol% of solvent could be dissolved into the ANS viscous oil, resulting in more than 31% oil swelling and 97% oil viscosity reduction. Thus, the obvious oil swelling and significant viscosity reduction resulting from solvent injection could lead to much better microscopic displacement efficiency during the solvent flooding. The ζ potential determination results illustrate that LSW resulted in more negative ζ potential than HSW on the interface between sand and water, indicating that lowering the salinity of injected brine could result in the sand surface being more water-wet, but adding polymer to the LSW could not further enhance the water wetness. The IFT measurement results show that the IFT between the tested ANS viscous oil and LSW is higher than that between the tested viscous oil and HSW, which conflicts with the commonly recognized IFT reduction effect by LSW flooding. Thus, the EOR theory of the LSW flooding in our proposed hybrid techniques may be attributed to low-salinity effects (LSEs) such as multi-ion exchange, expansion of electrical double layer, and salting-in effect, while water wetness enhancement may benefit the LSW flooding process to some extent. The LSP’s viscosity is much higher than the viscosities of LSW and solvent, so LSP injection could result in better mobility control in the tested viscous oil reservoirs, leading to improvement of macroscopic sweep efficiency. Combining these EOR theories, the proposed hybrid EOR techniques have the potential to significantly increase oil recovery in viscous oil reservoirs on ANS by maximizing the overall displacement efficiency.

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