Lessons Learned From Well to Field Level in Developing Heavy-Oil Reservoirs Using Thermal Recovery: Case Studies

2014 ◽  
Author(s):  
Reza Mehranfar
Keyword(s):  
Case Studies ◽  
Heavy Oil ◽  
Lessons Learned ◽  
Thermal Recovery ◽  
Oil Reservoirs ◽  
Field Level ◽  
Heavy Oil Reservoirs

The macroscopic and microscopic analysis on the performance of steam foams during thermal recovery in heavy oil reservoirs

Fuel ◽  
2018 ◽  
Vol 233 ◽  
pp. 166-176 ◽  
Author(s):  
Zhanxi Pang ◽  
Xiaocong Lyu ◽  
Fengyi Zhang ◽  
Tingting Wu ◽  
Zhennan Gao ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Microscopic Analysis ◽  
Thermal Recovery ◽  
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.

scholarly journals Experimental study on the mechanism and development effect of multi-gas assisted steam huff and puff process in the offshore heavy oil reservoirs

2021 ◽  
Author(s):  
Jie Fan ◽  
Zuqing He ◽  
Wei Pang ◽  
Daoming Fu ◽  
Hanxiu Peng ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Steam Injection ◽  
Thermal Recovery ◽  
Oil Reservoirs ◽  
Viscosity Reduction ◽  
Oil Viscosity ◽  
Enhanced Production ◽  
Heavy Oil Reservoirs ◽  
Water Gas ◽  
Development Mechanism

AbstractMulti-gas assisted steam huff and puff process is a relatively new thermal recovery technology for offshore heavy oil reservoirs. Some blocks of Bohai oilfield have implemented multi-gas assisted steam huff and puff process. However, the development mechanism still requires further study. In this paper, high-temperature high-pressure (HTHP) PVT experiments and different huff and puff experiments of sand pack were carried out to reveal the enhanced production mechanism and evaluate the development effect of multi-gas assisted steam huff and puff process. The results indicated that viscosity reduction and thermal expansion still were the main development mechanism of multi-gas assisted steam huff and puff process. Specifically, CO2 easily dissolved in the heavy oil that made it mainly play the role of reducing oil viscosity, N2 was characteristics of small solubility and good expansibility, and it could improve formation pressure, increase steam sweep volume and even reduce the heat loss. Meanwhile, injecting multi-gas and steam could break the balance of heavy oil component that made the content of resin reduce and the content of saturates, aromatics and asphaltene increase so as to further reduce the viscosity of heavy oil. Compared with steam huff and puff process, multi-gas assisted steam huff and puff process increased the recovery by 2–5%. The optimal water–gas ratio and steam injection temperature were 4:6 and 300℃, respectively. The results suggested that multi-gas assisted steam huff and puff process would have wide application prospect for offshore heavy oil reservoirs.

Variation Characteristics of Reservoir Physical Properties after Thermal Recovery in Heavy Oil Reservoirs

2012 ◽  
Vol 550-553 ◽  
pp. 2848-2852
Author(s):  
Xiao Hu Dong ◽  
Hui Qing Liu ◽  
Zhan Xi Pang ◽  
Yong Gang Yi
Keyword(s):  
Physical Properties ◽  
Heavy Oil ◽  
Steam Injection ◽  
Thermal Recovery ◽  
Oil Reservoirs ◽  
Sand Production ◽  
Heavy Oil Reservoirs ◽  
Variation Characteristics ◽  
Porosity And Permeability ◽  
Production Period

With the development of heavy oil reservoirs, it faced a series of problems. Using the theory of thermal-hydrological-mechanical (THM) coupling, a predictive model of reservoir physical properties (RPP) after thermal recovery is established. Based on this model, the changing process of reservoir physical properties is simulated by the method of numerical simulation. The obtained results show that the sand production has a significant influence on RPP. By contrast with rock deformation, it has a smaller influence on RPP. The influence caused by the former is about 5~8 times than latter. During the period of steam injection, resulting from the movement of sand grain and expansion of reservoir, both porosity and permeability of reservoir are on the rise. Due to the sand production and reservoir compression, a reducing tendency is happened in the production period. The changes of RPP in reservoir are huge along the main streamline direction, and it might change because of the presence of high-permeability path.

Designing Surfactant-Polymer Processes for Heavy Oil Reservoirs: Case Studies

2018 ◽  
Author(s):  
D. Rousseau ◽  
S. Bekri ◽  
J. Boujlel ◽  
S. Hocine ◽  
G. Degre
Keyword(s):  
Case Studies ◽  
Heavy Oil ◽  
Oil Reservoirs ◽  
Heavy Oil Reservoirs

Case Study on In-Depth Blocking for Thermal Recovery by Steam Stimulation in Heavy Oil Reservoirs

2015 ◽  
Author(s):  
Qing You ◽  
Huan Wang ◽  
Caili Dai ◽  
Yifei Liu ◽  
Jichao Fang ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Thermal Recovery ◽  
Oil Reservoirs ◽  
Heavy Oil Reservoirs ◽  
Steam Stimulation

scholarly journals Thermal Hydraulic Analysis Using GIS on Application of HTR to Thermal Recovery of Heavy Oil Reservoirs

2012 ◽  
Vol 2012 ◽  
pp. 1-15
Author(s):  
Yangping Zhou ◽  
Fu Li ◽  
Zhiwei Zhou ◽  
Yuanle Ma
Keyword(s):  
Heavy Oil ◽  
Superheated Steam ◽  
Steam Injection ◽  
Thermal Recovery ◽  
Oil Field ◽  
Oil Reservoirs ◽  
Hydraulic Analysis ◽  
Heavy Oil Reservoirs ◽  
Large Water ◽  
Thermal Hydraulic Analysis

At present, large water demand and carbon dioxide (CO2) emissions have emerged as challenges of steam injection for oil thermal recovery. This paper proposed a strategy of superheated steam injection by the high-temperature gas-cooled reactor (HTR) for thermal recovery of heavy oil, which has less demand of water and emission of CO2. The paper outlines the problems of conventional steam injection and addresses the advantages of superheated steam injection by HTR from the aspects of technology, economy, and environment. A Geographic Information System (GIS) embedded with a thermal hydraulic analysis function is designed and developed to analyze the strategy, which can make the analysis work more practical and credible. Thermal hydraulic analysis using this GIS is carried out by applying this strategy to a reference heavy oil field. Two kinds of injection are considered and compared: wet steam injection by conventional boilers and superheated steam injection by HTR. The heat loss, pressure drop, and possible phase transformation are calculated and analyzed when the steam flows through the pipeline and well tube and is finally injected into the oil reservoir. The result shows that the superheated steam injection from HTR is applicable and promising for thermal recovery of heavy oil reservoirs.

A New Method for Measuring Solvent Diffusivity in Heavy Oil by Dynamic Pendant Drop Shape Analysis (DPDSA)

SPE Journal ◽  
2006 ◽  
Vol 11 (01) ◽  
pp. 48-57 ◽  
Author(s):  
Chaodong Yang ◽  
Yongan Gu
Keyword(s):  
Carbon Dioxide ◽  
Mass Transfer ◽  
High Pressure ◽  
Objective Function ◽  
Heavy Oil ◽  
Oil Production ◽  
Thermal Recovery ◽  
Oil Reservoirs ◽  
Pressure Cell ◽  
Heavy Oil Reservoirs

Summary This paper presents a new experimental method and its computational scheme for measuring solvent diffusivity in heavy oil under practical reservoir conditions by DPDSA. In the experiment, a see-through windowed high-pressure cell is filled with a test solvent at desired pressure and temperature. Then, a heavy-oil sample is introduced through a syringe delivery system to form a pendant oil drop inside the pressure cell. The subsequent diffusion of the solvent into the pendant oil drop causes its shape and volume to change until an equilibrium state is reached. The sequential digital images of the dynamic pendant oil drop are acquired and digitized by applying computer-aided digital image-acquisition and -processing techniques. Physically, variations of the shape and volume of the dynamic pendant oil drop are attributed to the interfacial tension reduction and the well-known oil-swelling effect as the solvent gradually dissolves into heavy oil. Theoretically, the interfacial profile of the dynamic pendant oil drop is governed by the Laplace equation of capillarity, and the molecular diffusion process of the solvent into the pendant oil drop is described by the diffusion equation. An objective function is constructed to express the discrepancy between the numerically predicted and experimentally observed interfacial profiles of the dynamic pendant oil drop. The solvent diffusivity in heavy oil and the mass-transfer Biot number are used as adjustable parameters and thus are determined once the minimum objective function is achieved. This novel experimental technique is tested to measure diffusivities of carbon dioxide in a brine sample and a heavy-oil sample, respectively. It should be noted that, with the present technique, a single diffusivity measurement can be completed within an hour and only a small amount of oil sample is required. The interface mass-transfer coefficient at the solvent/heavy-oil interface can also be determined. In particular, this new technique allows the measurement of solvent diffusivity in an oil sample at constant prespecified high pressure and temperature. Therefore, it is especially suitable for studying the mass-transfer process of injected solvent into heavy oil during solvent-based post-cold heavy-oil production (post-CHOP). Introduction Western Canada has tremendous heavy oil and bitumen resources (Farouq Ali 2003, Miller et al. 2002). Approximately 80 to 95% of the original-oil-in-place is still left behind at the economic limit after cold heavy-oil production (Miller et al. 2002). This is a large oil-in-place target for follow-up enhanced oil recovery (EOR) processes. After primary production, most Canadian heavy-oil reservoirs cannot be further exploited economically by thermal recovery processes because reservoir formations are thin and/or there is active bottomwater. In the literature, some studies have been conducted to evaluate the other recovery methods for these heavy-oil reservoirs (Miller et al. 2002, Das 1995, Frauenfeld et al. 1998, Metwally 1998). Among these methods, vapor extraction (VAPEX) and other solvent-based post-CHOP processes are probably the most promising EOR techniques. In practice, the solvent can be carbon dioxide, flue gas, and light hydrocarbon gases, such as methane, ethane, propane, and butane.

Optimization of thermal recovery strategies for offshore heavy oil reservoirs in Bohai Bay, China

2016 ◽  
Vol 34 (2) ◽  
pp. 139-144 ◽  
Author(s):  
Yanyu Zhang ◽  
Huijuan Chen ◽  
Xiaofei Sun ◽  
Xuewei Duan ◽  
Wentao Hu ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Thermal Recovery ◽  
Oil Reservoirs ◽  
Bohai Bay ◽  
Heavy Oil Reservoirs ◽  
Recovery Strategies

Thermal recovery strategies for thin heavy oil reservoirs

Fuel ◽  
2014 ◽  
Vol 117 ◽  
pp. 431-441 ◽  
Author(s):  
David W. Zhao ◽  
Jacky Wang ◽  
Ian D. Gates
Keyword(s):  
Heavy Oil ◽  
Thermal Recovery ◽  
Oil Reservoirs ◽  
Heavy Oil Reservoirs ◽  
Recovery Strategies
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