Revitalizing Indonesia's Potential for Oil Production: The Study of Electromagnetically Heated Gravel Packs for Steam-produced Heavy Oil Reservoirs

2013 ◽  
Author(s):  
Fiki Hidayat Ferizal ◽  
Akmaral Amangeldievna Netzhanova ◽  
Jaehoon Lee ◽  
Wisup Bae ◽  
Suranto Am ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Oil Production ◽  
Oil Reservoirs ◽  
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.

scholarly journals The Adverse Impact of Muddy Laminae on Conventional SAGD Performance and Improvement Strategy with the Multilateral Well Pattern

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-19
Author(s):  
Yang Yu ◽  
Shangqi Liu ◽  
Yu Bao ◽  
Lixia Zhang ◽  
Jia Xie ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Oil Sands ◽  
Oil Production ◽  
Oil Reservoirs ◽  
Adverse Impact ◽  
Peak Oil ◽  
Improvement Strategy ◽  
Steam Chamber ◽  
Well Pattern ◽  
Heavy Oil Reservoirs

With further progress of Steam-Assisted Gravity Drainage (SAGD) technology, a growing number of oil sands or heavy oil reservoirs were put into production in an efficient way. However, owing to the existence of muddy laminae within reservoirs, there are challenges associated with the expansion of the steam chamber and oil drainage during the SAGD process. The purpose of this study is to evaluate the adverse impact of muddy laminae on conventional SAGD performance and introduce an improvement strategy with multilateral well patterns to reduce the adverse impact and improve the performance. In the research reported here, the reservoir numerical simulation approach is applied to conduct the research. The analysis conducted on a prototypical reservoir reveals that the steam chamber may expand slowly in some sections due to the poor capacity of heat and mass transfer, and the expansion of the steam chamber is relatively uneven along the wellbore, when the muddy laminae are existing in the formation. The influence level of the muddy laminae on conventional SAGD performance under different distribution modes is different, but the adverse effect is mainly reflected in the delay of peak oil production, the decrease in peak oil production, the decrease in steam chamber volume, and the increase in the cumulative steam oil ratio (mainly in early and middle stages of the SAGD process). On the basis of aforementioned researches, the improvement strategy with two different multilateral well patterns, planar multilateral well and upward multilateral well, is introduced to improve the SAGD performance. The results indicate that the combination of a planar multilateral injector and planar multilateral producer has the best performance. By adopting such kind of combination, the recovery factor can be increased from 31.36% to 47.08%, and the cumulative steam oil ratio can be decreased from 5.29 m3/m3 to 4.64 m3/m3 under the combined distribution mode of muddy laminae. It can be known that the branches of the planar multilateral well are very helpful for the expansion of the steam chamber and oil drainage, once the heat connection between branches of the injector and producer is well established. Overall results show that the multilateral well pattern is promising for SAGD applications at oil sands or heavy oil reservoirs which are rich in muddy laminae.

Enhanced Oil Production Owing to Sand Flow in Conventional and Heavy-Oil Reservoirs

2001 ◽  
Vol 4 (05) ◽  
pp. 366-374 ◽  
Author(s):  
Yarlong Wang ◽  
Carl C. Chen
Keyword(s):  
Heavy Oil ◽  
Oil Production ◽  
Oil Reservoirs ◽  
Absolute Permeability ◽  
Sand Production ◽  
Foamy Oil ◽  
Enhanced Production ◽  
Sand Control ◽  
Heavy Oil Reservoirs ◽  
Oil Flow

Summary A coupled reservoir-geomechanics model is developed to simulate the enhanced production phenomena in both heavy-oil reservoirs (northwestern Canada) and conventional oil reservoirs (i.e., North Sea). The model is developed and implemented numerically by fully coupling an extended geomechanics model to a two-phase reservoir flow model. Both the enhanced production and the ranges of the enhanced zone are calculated, and the effects of solid production on oil recovery are analyzed. Field data for solid production and enhanced oil production, collected from about 40 wells in the Frog Lake area (Lloydminster, Canada), are used to validate the model for the cumulative sand and oil production. Our studies indicate that the enhanced oil production is mainly contributed (1) by the reservoir porosity and permeability improvement after a large amount of sand is produced, (2) by higher mobility of the fluid caused by the movement of the sand particles, and (3) by foamy oil flow. A relative permeability reduction after a certain period of production may result in a pressure-gradient increase, which can promote further sand flow. This process can further improve the absolute permeability and the overall sand/fluid slurry production. Our numerical results simulate the fact that sand production can reach up to 40% of total fluid production at the early production period and decline to a minimum level after the peak, generating a high-mobility zone with a negative skin near the wellbore. Such an improvement reduces the near-well pressure gradient so that the sanding potential is weakened, and it permits an easier path for the viscous oil to flow into the well. Our studies also suggest that the residual formation cement is a key factor for controlling the cumulative sand production, a crucial factor that determines the success of a cold production operation and improved well completion. Introduction Field results from many heavy-oil reservoirs in northwestern Canada, such as Lindbergh and Frog Lake in the Lloydminster fields, suggest that primary recovery is governed mainly by the processes of sand production and foamy-oil flow.1–3 To manage production in such reservoirs, the challenge we face is optimizing production so that sand production is under control. For decades, industries have developed various highly effective tools for sand control. In practice, however, sand control often results in reduced oil flow or no production at all, particularly in heavy-oil reservoirs. For example, it has been observed that an average oil production of only 0.0 to 1.5 m3/d can be achieved in a well in which no sand production is allowed, while 7 to 15 m3/d oil may be produced with sand production.4 A significant improvement in production also has been reported by allowing a certain amount of sand produced before gravel packing in the high-rate production well in conventional reservoirs.5 It seems that sanding corresponds to a high oil production in these reservoirs, as sand production either increases the reservoir mobility or allows the development of highly permeable zones such as channels (wormholes).1 Encouraging sand production to enhance oil production, on the other hand, increases oil production costs owing to environmental problems. Consequently, neither trying to eliminate the sand production completely nor letting sand be produced freely, we attempt to develop a quantified model linking sand rate and reservoir enhancement so that we can forecast the economic outcome of such an operation. The investigation of sand production has been extensive, but it has been limited primarily to the areas of incipience of sand production and control. Sand arching and production initiation from a cavity simulating a perforating tunnel were studied, and a critical flow rate before sanding was found for single-phase steady-state flow.6 Such a study was extended to gas reservoirs, in which the gas density is a function of pressure,7 and to those formations subject to nonhydrostatic loading.8,9 Studying the enhanced production and the cumulative sand production, a series of simplified models for massive sand production have been developed.10,11 Similar models based on a coupled classic geomechanics model were also proposed thereafter.12,13 Because these aforementioned sand-production models are somewhat restricted by the fact that they are simplified by analytical methods, and in reality reservoir formations are much more complex (i.e. nonlinear behaviors), a numerical model coupling a multiphase transient fluid flow to elastoplastic geomechanical deformation is thus developed in this article; its purpose is to simulate these major nonlinear effects. According to the proposed model, a corresponding plastic yielding zone (or a disturbed zone) propagates into reservoir formation because of the transient fluid pressure diffusion, and the corresponding effective stresses change near a wellbore. A possible absolute permeability change inside the yielding zone is also considered, as dilatant deformation developed may enhance the permeability in the plastic zone. As a primary unknown, saturation is assumed to change with the induced pore-pressure change. The relative permeability is updated by the saturation, which in turn changes the response of the pore pressure and the skeleton deformation. A continuum mechanics approach is used in our calculation. Rather than characterizing each random wormhole proposed,1,4,5 we impose a homogeneous medium with an average permeability to make the numerical solutions manageable. The wormholes or geomechanical dilatation zone can be represented by a higher-permeability region in the plastic yielding zone owing to porosity enhancement,1 and solid flow is considered as a continuous moving phase along the transient fluid flow. Alternatively, a sand erosion model was introduced, and the geomechanics coupling to a single-phase flow was presented previously.14,15

Analysis and Optimization of Bubbly Oil Production in Heavy Oil Reservoirs

2017 ◽  
Author(s):  
Cenk Temizel ◽  
Raul Moreno ◽  
Bao Jia ◽  
Ahmad Alkouh ◽  
Basel Al-Otaibi ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Oil Production ◽  
Oil Reservoirs ◽  
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.

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