Enhanced Oil Recovery in Post-CHOPS Cold Heavy Oil Production with Sand Heavy Oil Reservoirs of Alberta and Saskatchewan Part 2 : Field Piloting of Cycling Solvent Injection

2020 ◽  
Author(s):  
Gokhan Coskuner ◽  
Haibo Huang
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Production ◽  
Oil Reservoirs ◽  
Solvent Injection ◽  
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.

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.

Microorganisms of low-temperature heavy oil reservoirs (Russia) and their possible application for enhanced oil recovery

Microbiology ◽  
2017 ◽  
Vol 86 (6) ◽  
pp. 773-785 ◽  
Author(s):  
T. N. Nazina ◽  
D. Sh. Sokolova ◽  
T. L. Babich ◽  
E. M. Semenova ◽  
A. P. Ershov ◽  
...  
Keyword(s):  
Low Temperature ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Reservoirs ◽  
Heavy Oil Reservoirs

Comparative Effectiveness of CO2 Produced Gas, and Flue Gas for Enhanced Heavy-Oil Recovery

1999 ◽  
Vol 2 (03) ◽  
pp. 238-247 ◽  
Author(s):  
Raj K. Srivastava ◽  
Sam S. Huang ◽  
Mingzhe Dong
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Flue Gas ◽  
Thermal Recovery ◽  
Oil Reservoirs ◽  
Heavy Oil Recovery ◽  
Heavy Oil Reservoirs ◽  
The World ◽  
Recovery Methods

Summary A large number of heavy oil reservoirs in Canada and in other parts of the world are thin and marginal and thus unsuited for thermal recovery methods. Immiscible gas displacement appears to be a very promising enhanced oil recovery technique for these reservoirs. This paper discusses results of a laboratory investigation, including pressure/volume/temperature (PVT) studies and coreflood experiments, for assessing the suitability and effectiveness of three injection gases for heavy-oil recovery. The gases investigated were a flue gas (containing 15 mol % CO2 in N2), a produced gas (containing 15 mol?% CO2 in CH4), and pure CO2 . The test heavy-oil (14° API gravity) was collected from Senlac reservoir located in the Lloydminster area, Saskatchewan, Canada. PVT studies indicated that the important mechanism for Senlac oil recovery by gas injection was mainly oil viscosity reduction. Pure CO2 appeared to be the best recovery agent, followed by the produced gas. The coreflood results confirmed these findings. Nevertheless, produced gas and flue gas could be sufficiently effective flooding agents. Comparable oil recoveries in flue gas or produced gas runs were believed to be a combined result of two competing mechanisms—a free-gas mechanism provided by N2 or CH4 and a solubilization mechanism provided by CO2. This latter predominates in CO2 floods. Introduction A sizable number of heavy-oil reservoirs in Canada1 and in other parts of the world are thin and shaly. Some of these reservoirs are also characterized by low-oil saturation, heterogeneity, low permeability, and bottom water.2,3 For example, about 55% of 1.7 billion m3 of proven heavy-oil resource in the Lloydminster and Kindersley region in Saskatchewan, Canada, is contained in less than 5 m (15 ft.) pay zone and nearly 97% is in less than 10 m (30 ft.) pay zone.4,5 Primary and secondary methods combined recover only about 7% of the proven initial oil in place (IOIP).1 Such reservoirs are not amenable to thermal recovery methods: heat is lost excessively to surroundings and steam is scavenged by bottomwater zones.6,7 The immiscible gas displacement appears to be a very promising enhanced oil recovery (EOR) process for these thin reservoirs. The immiscible gas EOR process has the potential to access more than 90% of the total IOIP.1,7 It could, according to previous studies,6–12 recover up to an additional 30% IOIP incremental over that recovered by initial waterflood for some moderately viscous oils. For the development of a viable immiscible gas process applicable to moderately viscous heavy oils found in this sort of reservoirs, we selected three injection gases for study: CO2 reservoir-produced gas (RPG), and flue gas (FG) from power plant exhausts. Extensive literature is available on CO2 flooding for heavy-oil recovery, dealing with pressure/volume/temperature (PVT) behavior,3,6,7,13-15 oil recovery characteristics from linear and scaled models,3,6-8,10-12,15,16 numerical simulation, and field performance.17–19 However, only limited data are available on flue gas and produced gas flooding.20–22 To determine the most suitable gas for EOR application from laboratory investigations, we need knowledge of the physical and chemical interaction between gas, reservoir oil, and formation rock; and information on the recovery potential for various injection gases for a targeted oil. The test oil selected for this study was from the Senlac reservoir (14° API) located in northwest Saskatchewan (Lloydminster area). The PVT properties for the oil/injection gas mixtures were measured and compared. A comparative study of the oil recovery behavior for Senlac dead oil and Senlac reservoir fluid was carried out with different injection gases to assess their relative effectiveness for EOR. Senlac Reservoir Geology The Senlac oil pool is located within the lower Cretaceous sand/shale sequence of the Mannville Group. The Mannville thickens northward and lies unconformably on the Upper Devonian Carbonates of the Saskatchewan Group. The trapping mechanism for the oil is mainly stratigraphic. The lower Lloydminster oil reservoir is a wavy, laminated, very fine- to fine-grained, well sorted, and generally unconsolidated sandstone. It exhibits uniform dark oil staining throughout, interrupted by a number of shale beds of 2 to 9 m (6 to 27 ft) thick, which are distributed over the entire reservoir. The reservoir is overlain by a shale/siltstone/sandstone sequence and lies on a 3 m (9 ft) thick coal seam. The detailed reservoir (Senlac) data and operating characteristics are provided in Ref. 5. The reservoir temperature is 28°C (82.4°F) and the reservoir pressure varies between 2.5 and 4.1 MPa (363 and 595 psia). The virgin pressure of the reservoir at discovery was 5.4 MPa (783 psia) and the gas/oil ratio (GOR) was 16.2 sm3/m3 (89.8 sft3 /bbl). The reservoir matrix has a porosity of about 27.7% by volume and permeability of about 2.5 mD. The average water saturation is about 32% pore volume (PV). The pattern configuration for oil production is five-spot on a 16.2 ha (40 acre) drainage area. The estimated primary and secondary (solution gas and waterflood) recovery is 5.5% of the initial oil in place. Experiment Wellhead Dead Oil and Brine. Senlac wellhead dead oil and formation brine (from Well 16-35-38-27 W3M) were supplied by Wascana Energy, Inc. The oil was cleaned for the experiments by removal of basic sediment and water (BS&W) through high-speed centrifugation. The chemical and physical properties of cleaned Senlac stock tank oil are shown in Table 1. The formation brine was vacuum filtered twice to remove iron contamination from the sample barrels.

Enhanced oil recovery from heavy oil reservoirs utilizing a displacement agent

2012 ◽  
Vol 48 (3) ◽  
pp. 202-207 ◽  
Author(s):  
Fusheng Zhang ◽  
Jian Ouyang ◽  
Xintong Ma ◽  
Huaibin Zhang ◽  
Dewei Wang ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Reservoirs ◽  
Heavy Oil Reservoirs
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