Horizontal Length Optimization of Cold Production with Horizontal Wells in Extra-Heavy Oil Reservoirs

2021 ◽  
pp. 802-810
Author(s):  
Zhao-peng Yang ◽  
Xing-min Li ◽  
Zhang-cong Liu ◽  
Yang Shen ◽  
Xiao-xing Shi
Keyword(s):  
Heavy Oil ◽  
Horizontal Wells ◽  
Oil Reservoirs ◽  
Horizontal Length ◽  
Heavy Oil Reservoirs ◽  
Length Optimization

Pressure Maintenance and Improving Oil Recovery by Means of Immiscible Water-Alternating-CO2 Processes in Thin Heavy-Oil Reservoirs

2013 ◽  
Vol 16 (01) ◽  
pp. 60-71 ◽  
Author(s):  
Sixu Zheng ◽  
Daoyong Yang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Production ◽  
Horizontal Wells ◽  
Operating Conditions ◽  
Oil Reservoirs ◽  
Oil Saturation ◽  
Water Alternating Gas ◽  
Heavy Oil Reservoirs ◽  
Water Cut

Summary Techniques have been developed to experimentally and numerically evaluate performance of water-alternating-CO2 processes in thin heavy-oil reservoirs for pressure maintenance and improving oil recovery. Experimentally, a 3D physical model consisting of three horizontal wells and five vertical wells is used to evaluate the performance of water-alternating-CO2 processes. Two well configurations have been designed to examine their effects on heavy-oil recovery. The corresponding initial oil saturation, oil-production rate, water cut, oil recovery, and residual-oil-saturation (ROS) distribution are examined under various operating conditions. Subsequently, numerical simulation is performed to match the experimental measurements and optimize the operating parameters (e.g., slug size and water/CO2 ratio). The incremental oil recoveries of 12.4 and 8.9% through three water-alternating-CO2 cycles are experimentally achieved for the aforementioned two well configurations, respectively. The excellent agreement between the measured and simulated cumulative oil production indicates that the displacement mechanisms governing water-alternating-CO2 processes have been numerically simulated and matched. It has been shown that water-alternating-CO2 processes implemented with horizontal wells can be optimized to significantly improve performance of pressure maintenance and oil recovery in thin heavy-oil reservoirs. Although well configuration imposes a dominant impact on oil recovery, the water-alternating-gas (WAG) ratios of 0.75 and 1.00 are found to be the optimum values for Scenarios 1 and 2, respectively.

scholarly journals Downhole electric heating of heavy-oil wells

2020 ◽  
Vol 10 (2) ◽  
pp. 61-72
Author(s):  
John Karanikas ◽  
Guillermo Pastor ◽  
Scott Penny
Keyword(s):  
Heavy Oil ◽  
Horizontal Wells ◽  
Electric Heating ◽  
Optimization Method ◽  
Economic Benefits ◽  
Production Optimization ◽  
Operating Conditions ◽  
Oil Reservoirs ◽  
Oil Well ◽  
Heavy Oil Reservoirs

Downhole electric heating has historically been unreliable or limited to short, often vertical, well sections. Technology improvements over the past several years now allow for reliable, long length, relatively high-powered, downhole electric heating suitable for extended-reach horizontal wells. The application of this downhole electric heating technology in a horizontal cold-producing heavy oil well in Alberta, Canada is presented in this paper. The field case demonstrates the benefits and efficacy of applying downhole electric heating, especially if it is applied early in the production life of the well. Early production data showed 4X-6X higher oil rates from the heated well than from a cold-producing benchmark well in the same reservoir. In fact, after a few weeks of operation, it was no longer possible to operate the benchmark well in pure cold-production mode as it watered out, whereas the heated well has been producing for twenty (20) months without any increase in water rate. The energy ratio, defined as the heating value of the incremental produced oil to the injected heat, is over 20.0, resulting in a carbon-dioxide footprint of less than 40 kgCO2/bbl, which is lower than the greenhouse gas intensity of the average crude oil consumed in the US. A numerical simulation model that includes reactions that account for the foamy nature of the produced oil and the downhole injection of heat, has been developed and calibrated against field data.  The model can be used to prescribe the range of optimal reservoir and fluid properties to select the most promising targets (fields, wells) for downhole electric heating as a production optimization method. The same model can also be used during the execution of the project to explore optimal operating conditions and operating procedures. Downhole electric heating in long horizontal wells is now a commercially available technology that can be reliably applied as a production optimization recovery scheme in heavy oil reservoirs. Understanding the optimum reservoir conditions where the application of downhole electric heating maximizes economic benefits will assist in identifying areas of opportunity to meaningfully increase reserves and production in heavy oil reservoirs around the world.

Development Features of Cold Production with Horizontal Wells in a Foamy Extra-Heavy Oil Reservoir

2021 ◽  
Author(s):  
Zhaopeng Yang ◽  
Xingmin Li ◽  
Xinxia Xu ◽  
Yang Shen ◽  
Xiaoxing Shi
Keyword(s):  
Heavy Oil ◽  
Horizontal Wells ◽  
Oil Field ◽  
Production Performance ◽  
Oil Reservoirs ◽  
Bubble Point ◽  
Foamy Oil ◽  
Bubble Point Pressure ◽  
Heavy Oil Reservoirs ◽  
Point Pressure

Abstract The block M as a foamy extra-heavy oil field in the Carabobo Area, the eastern Orinoco Belt, has been exploited by foamy oil cold production utilizing horizontal wells. The early producing area of block M has been put into production more than 10 years. And the development features of cold production in foamy extra-heavy oil reservoirs are different from the conventional oil field. It is necessary to investigate the development features of this kind reservoir and analyze its influence factors. Combining the production data with the reservoir geological characteristics of the research area, the cold production features of foamy extra-heavy oil using horizontal wells are analyzed. Then numerical simulations were adopted to study the influence factors of cold production performance. In the early stage of cold production, the oil production rate is high and the producing GOR is low. With the process of cold production, the reservoir pressure decreases gradually, the producing GOR increases gradually, and the oil production rate decreases gradually. When the bottom hole flowing pressure drops to below the bubble point pressure, the flow of extra-heavy oil in the reservoir can be divided into two zones: far well zone and near well area. In the far well zone, the pressure is higher than the bubble point pressure. The flow of oil is a single-phase flow, and the displacement mode is elastic driving. In the near well area, the pressure is lower than the bubble point pressure, and the oil flow is foamy oil flow, and the displacement mode is the dissolving gas drive driven by foamy oil. There exists many factors that influence the cold production performance of foamy extra-heavy oil, including reservoir depth, reservoir thickness, reservoir physical property and heterogeneity. The oil recovery factor per unit pressure drop can evaluate the cold production performance of foamy extra-heavy oil reservoirs. The effectiveness of cold production is closely related to reservoir parameters. Larger reservoir thickness, deeper reservoir depth and greater reservoir permeability will enhance the performance of cold production. Closer, larger and more interlayers above the horizontal well will hinder the performance of cold production. This research provides certain guidance and reference for further development adjustment and new project evaluation for foamy extra-heavy oil reservoirs in the Eastern Orinoco Belt.

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