Temperature-Dependent Irreducible Water Trapping in Heavy-Oil Reservoirs

SPE Journal ◽  
2021 ◽  
pp. 1-26
Author(s):  
Dongqi Ji ◽  
Shuhong Wu ◽  
Baohua Wang ◽  
Zhiping Li ◽  
Fengpeng Lai ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Sands ◽  
Elevated Temperatures ◽  
Water Saturation ◽  
Temperature Dependent ◽  
Thermal Methods ◽  
Water Separation ◽  
Irreducible Water Saturation ◽  
Oil Water

Summary Temperature-dependent irreducible water saturation has great implications for heavy-oil production. Especially in processes using thermal methods, the irreducible water saturation varies significantly when temperature rises from the initial reservoir condition to the temperature of injected hot fluids. In this work, the irreducible water saturation retained in a heavy-oil/oil-sands reservoir has been theoretically analyzed as a function of temperature in the view of thermodynamics. This analysis involves oil/water interactions, thermodynamic stability, pendular rings between particles, and a dense random-packing theory. The temperature-dependent irreducible water saturation in two heavy-oil reservoir samples (Coalinga and Huntington Beach) and two oil-sands reservoir samples (Cat Canyon and Peace River) have been analyzed using an oil/water/silica system. The computed results have been compared with published experimental data. The good agreements of the comparison demonstrate the feasibility of the proposed analysis to describe the irreducible water saturation in a heavy-oil/oil-sands reservoir up to 300°C. Through these analyses, the theoretical understandings of temperature-dependent irreducible water in a heavy-oil/oil-sands reservoir have been provided. As temperature increases, the mutual water/oil solubilities are increased by enhanced molecular interactions, as well as the surface energy at an oil/water connecting interface. As a result, the oil/water interfacial tension (IFT) decreases, which diminishes the contact angle and enlarges a water-filled pendular ring between particles at elevated temperatures. Thus, the irreducible water saturation is increased by the enlarged pendular rings in a dense packing porous medium. In addition, this study demonstrates the possibilities to alter the irreducible water saturation appropriately in a heavy-oil/oil-sands reservoir to enhance oil recovery, decrease water cut, save costs of surface oil/water separation, and reduce heat consumption.

scholarly journals Experimental Investigation on Oil Enhancement Mechanism of Hot Water Injection in tight reservoirs

Open Physics ◽  
2016 ◽  
Vol 14 (1) ◽  
pp. 703-713 ◽  
Author(s):  
Hao Yongmao ◽  
Lu Mingjing ◽  
Dong Chengshun ◽  
Jia Jianpeng ◽  
Su Yuliang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Water Injection ◽  
Hot Water ◽  
Water Flooding ◽  
Water Displacement ◽  
Pore Characteristics ◽  
Irreducible Water Saturation ◽  
Tight Reservoirs ◽  
Oil Water

AbstractAimed at enhancing the oil recovery of tight reservoirs, the mechanism of hot water flooding was studied in this paper. Experiments were conducted to investigate the influence of hot water injection on oil properties, and the interaction between rock and fluid, petrophysical property of the reservoirs. Results show that with the injected water temperature increasing, the oil/water viscosity ratio falls slightly in a tight reservoir which has little effect on oil recovery. Further it shows that the volume factor of oil increases significantly which can increase the formation energy and thus raise the formation pressure. At the same time, oil/water interfacial tension decreases slightly which has a positive effect on production though the reduction is not obvious. Meanwhile, the irreducible water saturation and the residual oil saturation are both reduced, the common percolation area of two phases is widened and the general shape of the curve improves. The threshold pressure gradient that crude oil starts to flow also decreases. It relates the power function to the temperature, which means it will be easier for oil production and water injection. Further the pore characteristics of reservoir rocks improves which leads to better water displacement. Based on the experimental results and influence of temperature on different aspects of hot water injection, the flow velocity expression of two-phase of oil and water after hot water injection in tight reservoirs is obtained.

Enhancing oil–solid and oil–water separation in heavy oil recovery by CO 2 ‐responsive surfactants

AIChE Journal ◽  
2020 ◽  
Vol 67 (1) ◽  
Author(s):  
Yi Lu ◽  
Rui Li ◽  
Rogerio Manica ◽  
Qingxia Liu ◽  
Zhenghe Xu
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Heavy Oil Recovery ◽  
Water Separation ◽  
Oil Water Separation ◽  
Oil Water

Electromagnetic Induction Heating for Bitumen Recovery: A Case Study in Athabasca Oil Sands

2021 ◽  
Author(s):  
Ahmed Sherwali ◽  
Mehdi Noroozi ◽  
William G. Dunford
Keyword(s):  
Induction Heating ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Sands ◽  
Electromagnetic Induction ◽  
Water Saturation ◽  
Oil Reservoirs ◽  
Athabasca Oil Sands ◽  
Heavy Oil Reservoirs ◽  
Electromagnetic Induction Heating

Abstract This paper demonstrates how electromagnetic induction heating is used for bitumen recovery from the Athabasca oil sands in Alberta with minimal external water requirements. The paper addresses the setup requirements and the necessary parameters for this method to achieve an economic energy to oil ratio. An iterative process is followed to couple the heat rate generated by electromagnetic induction heating to the reservoir model over a defined period. The reservoir model represents a 33 meter payzone with properties for the lower McMurray formation in an area north of Fort McMurray within the Athabasca oil sands deposit. Several scenarios are extensively explored to reach the most practical and feasible setup for oil recovery. The process enables operators to monitor and control reservoir pressure and temperature, liquid production, and energy to oil ratio to maximize recovery from oil sands and heavy oil reservoirs. The results show an expected ultimate oil recovery factor of +70% with an average energy to oil ratio that is lower than the average ratio associated with steam assisted gravity drainage. It is observed that the amount of energy required by the process correlates with water saturation in the near wellbore region, higher water saturation levels are preferred for enhanced oil recovery. It is also noticed that majority of the electromagnetically induced heat rate is generated in the near wellbore region vaporizing any existing water in that region, which eventually slows down the heating process. However, water injection improves the heat convection further into the reservoir, and therefore is essential for establishing a steam chamber using this method. Nevertheless, the volume of injected water required to establish a steam chamber is comparable to the overall volume of water produced from the reservoir, and thus minimal external water is necessary in this process. Moreover, the method is emissions free because heat is generated in the reservoir using an electrically powered downhole inductor (patent pending) that transfers electromagnetic energy to heat. In conclusion, this novel method shows high potential for responsible oil recovery from oil sands and heavy oil reservoirs while meeting economic and environmental expectations. This paper presents the use of a novel clean energy technology to recover bitumen from the Athabasca oil sands in Alberta. Furthermore, the technology is of high value to oil production from heavy oil reservoirs around the world and therefore provides large benefits to the energy industry.

Prospects for Heavy Oil Recovery and its Role in the Energy Picture

1986 ◽  
Vol 4 (5) ◽  
pp. 321-348
Author(s):  
Rawya Selby ◽  
S. M. Farouq Ali
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Sands ◽  
Thermal Recovery ◽  
Heavy Oil Recovery ◽  
Heavy Oils ◽  
Thermal Methods ◽  
Oil Reserves ◽  
Recovery Processes ◽  
Cyclic Steam Stimulation

Heavy oil and oil sands deposits constitute an important resource, with in-place estimates varying between 600 × 109 and 980 × 109 m3. These deposits are mostly concentrated in Canada, the US and Venezuela. The gradual depletion of conventional oil reserves is leading to a greater interest in heavy oil recovery. This paper presents on overview of heavy oil characteristics, worldwide deposits and recovery methods, with special emphasis on the heavy oils and oil sands of Canada. Thermal recovery techniques such as cyclic steam stimulation, steamflooding and in-situ combustion have been generally more successful than non-thermal methods. The principal thermal recovery processes are discussed in detail. Reservoir characteristics influencing the applicability of these processes are mentioned, and possible operational problems are outlined. Most of the Canadian heavy oils and oil sands deposits occur in the provinces of Alberta and Saskatchewan. Selected recovery projects currently in operation are described, outlining modifications to the basic process, problems encountered and range of success.

Remote monitoring of the steam‐flood enhanced oil recovery process

Geophysics ◽  
1987 ◽  
Vol 52 (11) ◽  
pp. 1457-1465 ◽  
Author(s):  
E. F. Laine
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
High Frequency ◽  
Oil Sands ◽  
Seismic Velocity ◽  
Color Image ◽  
Vertical Plane ◽  
Recovery Process ◽  
Steam Flood ◽  
Borehole Seismic

Cross‐borehole seismic velocity and high‐frequency electromagnetic (EM) attenuation data were obtained to construct tomographic images of heavy oil sands in a steam‐flood environment. First‐arrival seismic data were used to construct a tomographic color image of a 10 m by 8 m vertical plane between the two boreholes. Two high‐frequency (17 and 15 MHz) EM transmission tomographs were constructed of a 20 m by 8 m vertical plane. The velocity tomograph clearly shows a shale layer with oil sands above it and below it. The EM tomographs show a more complex geology of oil sands with shale inclusions. The deepest EM tomograph shows the upper part of an active steam zone and suggests steam chanelling just below the shale layer. These results show the detailed structure of the entire plane between boreholes and may provide a better means to understand the process for in situ heavy oil recovery in a steam‐flood environment.

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.

Advancement Towards the Full-Field Implementation of Marmul Alkaline-Surfactant-Polymer in the Sultanate of Oman

2021 ◽  
Author(s):  
Dawood Al Mahrouqi ◽  
Hanaa Sulaimani ◽  
Rouhi Farajzadeh ◽  
Yi Svec ◽  
Samya Farsi ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Phase 1 ◽  
Recovery Efficiency ◽  
Sultanate Of Oman ◽  
Water Separation ◽  
Full Field ◽  
Oil Water Separation ◽  
Oil Water ◽  
New Formulation ◽  
Alkaline Surfactant Polymer

Abstract In 2015-2016, the Alkaline-Surfactant-Polymer (ASP) flood Pilot in Marmul was successfully completed with ∼30% incremental oil recovery and no significant operational issues. In parallel to the ASP pilot, several laboratory studies were executed to identify an alternative and cost-efficient ASP formulation with simpler logistics. The studies resulted in a new formulation based on mono-ethanolamine (MEA) as alkali and a blend of commercially available and cheaper surfactants. To expediate the phased full field development, Phase-1 project was started in 2019 with the following main objectives are confirm high oil recovery efficiency of the new ASP formulation and ensure the scalability and further commercial maturation of ASP technology; de-risk the injectivity of new formulation; and de-risk oil-water separation in the presence of produced ASP chemicals. The Phase 1 project was executed in the same well pattern as the Pilot, but at a different reservoir unit that is more heterogeneous and has a smaller pore volume (PV) than those of the Pilot. This set-up allowed comparing the performance of ASP formulations and taking advantage of the existing surface facilities, thus reducing the project cost. The project was successfully finished in December 2020, and the following major conclusions were made: (1) with the estimated incremental recovery of around 15-18% and one of the producers exhibiting water cut reversal of more than 30%, the new ASP formulation is efficient and will be used in the follow-up phased commercial ASP projects; (2) the injectivity was sustained throughout the entire operations within the target rate and below the fracture pressure; (3) produced oil quality met the export requirements and a significant amount of oil-water separation data was collected. With confirmed high oil recovery efficiency for the cheaper and more convenient ASP formulation, the success of ASP flooding in the Phase-1 project paves the way for the subsequent commercial-scale ASP projects in the Sultanate of Oman.

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