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Collaborating Authors
Results
Abstract Foam is a promising means to assist in the permanent, safe subsurface sequestration of CO2, whether in aquifers or as part of an enhanced-oil-recovery (EOR) process. Here we review the advantages demonstrated for foam that would assist CO2 sequestration, in particular sweep efficiency and residual trapping, and the challenges yet to be overcome. CO2 is trapped in porous geological layers by an impermeable overburden layer and residual trapping, dissolution into resident brine, and conversion to minerals in the pore space. Over-filling of geological traps and gravity segregation of injected CO2 can lead to excessive stress and cracking of the overburden. Maximizing storage while minimizing overburden stress in the near term depends on residual trapping in the swept zone. Therefore, we review the research and field-trial literature on CO2 foam sweep efficiency and capillary gas trapping in foam. We also review issues involved in surfactant selection for CO2 foam applications. Foam increases both sweep efficiency and residual gas saturation in the region swept. Both properties reduce gravity segregation of CO2. Among gases injected in EOR, CO2 has advantages of easier foam generation, better injectivity, and better prospects for long-distance foam propagation at low pressure gradient. In CO2 injection into aquifers, there is not the issue of destabilization of foam by contact with oil, as in EOR. In all reservoirs, surfactant-alternating-gas foam injection maximizes sweep efficiency while reducing injection pressure compared to direct foam injection. In heterogeneous formations, foam helps equalize injection over various layers. In addition, spontaneous foam generation at layer boundaries reduces gravity segregation of CO2. Challenges to foam-assisted CO2 sequestration include the following: 1) verifying the advantages indicated by laboratory research at the field scale 2) optimizing surfactant performance, while further reducing cost and adsorption if possible 3) long-term chemical stability of surfactant, and dilution of surfactant in the foam bank by flow of water. Residual gas must reside in place for decades, even if surfactant degrades or is diluted. 4) verifying whether foam can block upward flow of CO2 through overburden, either through pore pathways or microfractures. 5) optimizing injectivity and sweep efficiency in the field-design strategy. We review foam field trials for EOR and the state of the art from laboratory and modeling research on CO2 foam properties to present the prospects and challenges for foam-assisted CO2 sequestration.
- North America > United States > Texas (1.00)
- Europe (1.00)
- North America > United States > Oklahoma (0.68)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.66)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (43 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Reaction Kinetics Determined from Core Flooding and Steady State Principles for Stevns Klint and Kansas Chalk Injected with MgCl2 Brine at Reservoir Temperature
Andersen, Pål Østebø (Department of Energy Resources, University of Stavanger, 4021 Norway) | Korsnes, Reidar Inge (Department of Energy and Petroleum Engineering, University of Stavanger, 4021 Norway) | Olsen, Andre Tvedt (Department of Energy Resources, University of Stavanger, 4021 Norway) | Bukkholm, Erik (Department of Energy Resources, University of Stavanger, 4021 Norway)
Abstract A methodology is presented for determining reaction kinetics from core flooding: A core is flooded with reactive brine at different compositions with injection rates varied systematically. Each combination is performed until steady state, when effluent concentrations no longer change significantly with time. Lower injection rate gives the brine more time to react. We also propose shut-in tests where brine reacts statically with the core a defined period and then is flushed out. The residence time and produced brine composition is compared with the flooding experiments. This design allows characterization of the reaction kinetics from a single core. Efficient modeling and matching of the experiments can be performed as the steady state data are directly comparable to equilibrating the injected brine gradually with time and does not require spatial and temporal modeling of the entire dynamic experiments. Each steady state data point represents different information that helps constrain parameter selection. The reaction kinetics can predict equilibrium states and time needed to reach equilibrium. Accounting for dispersion increases the complexity by needing to find a spatial distribution of coupled solutions and is recommended as a second step when a first estimate of the kinetics has been obtained. It is still much more efficient than simulating the full dynamic experiment. Experiments were performed injecting 0.0445 and 0.219 mol/L MgCl2 into Stevns Klint chalk from Denmark, and Kansas chalk from USA. The reaction kinetics of chalk are important as oil-bearing chalk reservoirs are chemically sensitive to injected seawater. The reactions can alter wettability and weaken rock strength which has implications for reservoir compaction, oil recovery and reservoir management. The temperature was 100 and 130°C (North Sea reservoir temperature). The rates during flooding were varied from 0.25 to 16 PV/d while shut-in tests provided equivalent rates down to 1/28 PV/d. The results showed that Ca ions were produced and Mg ions retained (associated with calcite dissolution and magnesite precipitation, respectively). This occurred in a substitution-like manner, where the gain of Ca was similar to the loss of Mg. A simple reaction kinetic model based on this substitution with three independent tuning parameters (rate coefficient, reaction order and equilibrium constant) was implemented together with advection to analytically calculate steady state effluent concentrations when injected composition, injection rate and reaction kinetic parameters were stated. By tuning reaction kinetic parameters, the experimental steady state data could be fitted efficiently. From data trends, the parameters were determined relatively accurate for each core. The roles of reaction parameters, pore velocity and dispersion were illustrated with sensitivity analyses. The steady state method allows computationally efficient matching even with complex reaction kinetics. Using a comprehensive geochemical description in the software PHREEQC, the kinetics of calcite and magnesite mineral reactions were determined by matching the steady state concentration changes as function of (residence) time. The simulator predicted close to identical production of Ca as loss of Mg. The geochemical software predicted much higher calcite solubility in MgCl2 than observed at 100 and 130°C for Stevns Klint and Kansas.
- Europe (1.00)
- North America > United States > Kansas (0.91)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (0.66)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.34)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Nebraska > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Kansas > Laramie Basin > Niobrara Formation (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Integration of geomechanics in models (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- (2 more...)
Abstract This paper presents a new wettability alteration model based on surface complexation theory and an extensive experimental dataset. The objective is to provide a general correlation for contact angle calculation that (1) captures the main mechanisms that impact rock-brine-oil wettability and (2) minimizes the number of parameters used to tune with experimental data. We compile a set of 141 zeta-potential and contact-angle measurements from the literature. We study the oil/rock surface-complexation reactions and model the electrostatic behavior of each data point. We develop a new wettability model that estimates the contact angle and consists of five terms based on the Young-Laplace equation. We use the Nelder-Mead optimization algorithm to determine the model-parameter values that produce the best fit of experimental observations. The contact angle estimates produced by our model are also verified against those calculated by Extended-Derjaguin-Landau-Verwey-Overbeekand (EDLVO) theory and are validated using UTCOMP-IPhreeqc to simulate five limestone Amott tests from the literature. The Blind-testing test reveals that our model is predictive of the experimental data (R = 0.81, RMSE = 12.5). While reducing the tuning parameters by half, our model is comparable to and–in some cases–even superior to the EDLVO modeling in predicting the contact angle measurements. We argue that EDLVO modeling has 10+ parameters, and the individual errors associated with each parameter could lead to wrong predictions. Amott-test simulations show excellent agreement between the proposed wettability-alteration model and experimental data. The rock's initial wettability was measured to be strongly oil-wet, with a negative Amott index and recovery factor around 5%, corroborating the calculated contact angle of 160 degrees. The recovery factor increases to about 20-35% as the rock becomes more water-wet after interaction with engineered water (contact angle changes to 90-64 degrees). Further analysis indicates the proposed model's capability to capture significant wettability-alteration trends. For example, we report increased water-wetting as brine ionic strength decreases, depicting the low-salinity effect. In addition, our model resulted in better convergence in some of the simulated core floods compared to EDLVO modeling. We conclude that our physics-based and data-driven model is a practical and efficient approach to predict rock-brine-oil wettability.
- Geology > Geological Subdiscipline (1.00)
- Geology > Mineral (0.69)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.48)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- North America > United States > Texas (0.89)
- Europe > United Kingdom > North Sea (0.89)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (0.67)
CO2 Foam Pilot in a West Texas Field: Design, Operation and Results
Mirzaei, Mohammad (Occidental Oil and Gas) | Kumar, Deepanshu (Occidental Oil and Gas) | Turner, Dwight (Occidental Oil and Gas) | Shock, Austin (Occidental Oil and Gas) | Andel, Derek (Occidental Oil and Gas) | Hampton, David (Occidental Oil and Gas) | Knight, Troy E. (Dow) | Katiyar, Amit (Dow) | Patil, Pramod D. (Dow) | Rozowski, Peter (Dow) | Nguyen, Quoc P. (The Univesity of Texas at Austin)
Abstract In this paper, we describe the design, implementation and results of a CO2 foam pilot in a mature CO2 flood in West Texas. The objective of the pilot was to demonstrate improved conformance/sweep efficiency of the CO2 foam over CO2 WAG injection. Laboratory experiments to guide design of the flood and the monitoring program to understand and model flood performance are described. Monitoring included rate and pressure tracking, injection profiles and inter-well tracer programs before and during the foam flood. While changes in injection rate and injection profile confirmed the formation of strong foam near the wellbore and redistribution of fluids in the injectors, oil response was weak, with significant oil gain observed in one of the four patterns. The gas production rate also changed very slightly from the baseline conditions. The comprehensive monitoring program in this pilot provides new insights into effectiveness of CO2 foam in actual field applications. The results from this pilot may help to better screen and design future foam injection pilots.
- North America > United States > Texas > Permian Basin > Salt Creek Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- (10 more...)
Sizing Gelant Treatment for Conformance Control in Hydraulically-Fractured Horizontal Wells
Liang, Bin (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Jiang, Hanqiao (China University of Petroleum, Beijing) | Li, Junjian (China University of Petroleum, Beijing) | Li, Min (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Lan, Yuzheng (University of Texas at Austin) | Seright, Randall (New Mexico Petroleum Recovery Research Center)
Abstract Horizontal wells are subject to water breakthrough problems caused by natural or hydraulic fracture connections. Treatment with gelant normally is an effective choice. However, at present, no methods can provide quantitative guidance for designing gelant treatment in fractured horizontal wells. In this paper, we proposed a fracture-conductivity-based analytical model to guide sizing gelant treatment in hydraulically fractured horizontal wells. It includes the evaluation of fracture number intersected with the horizontal well, calculation of gelant leakoff distance according to the desired water productivity reduction, and the method to determine optimal gelant volume. The principle for controlling gelant injection and the method for forecasting water shutoff performance are also included. The successful application is based on two requirements: (1) gelant can penetrate a short distance from fracture surface into adjacent matrices; and (2) gelant or gel can reduce permeability to water more than to hydrocarbon. Finally, we summarize a 9-step procedure for sizing gelant treatment in fractured horizontal wells. This work provides quantitative guidance for water shutoff treatment using cross-linked polymer gels that create disproportionate permeability reduction.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
Successful Field Implementation of CO2-Foam Injection for Conformance Enhancement in the EVGSAU Field in the Permian Basin
Katiyar, Amit (The Dow Chemical Company) | Hassanzadeh, Armin (The Dow Chemical Company) | Patil, Pramod (Rock-Oil Consulting Group) | Hand, Michael (ConocoPhillips) | Perozo, Alejandro (ConocoPhillips) | Pecore, Doug (ConocoPhillips) | Kalaei, Hosein (ConocoPhillips) | Nguyen, Quoc (The University of Texas at Austin)
Abstract This paper presents the performance of a CO2 foam injection pilot implemented in the East Vacuum Grayburg San Andres Unit (EVGSAU) by ConocoPhillips in cooperation with The Dow Chemical Company. The pilot project focuses on a single CO2 injection pattern, consisting of one injector and eight producers, selected due to signs of early gas breakthrough and poor overall sweep efficiency. To solve these conformance issues and increase overall pattern production performance, a new foaming surfactant with low adsorption and high gas partitioning characteristics was developed and experimentally tested at simulated reservoir conditions. A "water alternating surfactant-in-gas" injection strategy was created utilizing a history matched reservoir simulation model and an empirical foam model. This reservoir model was also utilized to better understand the dependency of surfactant concentration on foam generation and fluid diversion. Injection profile logs (IPLs) were also run, in both water and CO2 phases, prior to pilot implementation to establish baseline injection performance. This paper will detail several performance indicators that illustrate sustained improvement in pattern injection and production after more than 15 cycles of alternating water, CO2+surfactant, and CO2-only injection. During each cycle, gas injectivity trends were calculated and compared to the baseline to monitor foam strength and performance. Four additional IPLs were run, which indicated continuous improvement in vertical sweep efficiency and ultimately resulted in uniform injection distribution between the upper and lower sections of the producing zone. Finally, the most significant result of the trial was the uplift in pattern oil production. It has averaged ~20% above the baseline production forecast throughout the entire pilot period and peaked within the first six months at ~60% above the baseline. The success of this pilot illustrates the benefits of using a low adsorbing and CO2 soluble foaming surfactant to address reservoir conformance issues for CO2 floods. Further optimization of the pilot based on the simulation forecast is planned to improve long-term pilot economics.
- North America > United States > New Mexico (1.00)
- North America > United States > Texas (0.82)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (42 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Improving CO2 Vertical Sweep Efficiency in Tinsley Field with Dedicated Injectors
Sheikha, Hussain (Denbury Resources Inc.) | Blackmer, Scott Mitchell (Denbury Resources Inc.) | Sharaf, Essam (Denbury Resources Inc. & Geology Department, Faculty of Science, Mansoura University) | Marks, Dustin (Denbury Resources Inc.)
Abstract Lower oil production rate, conformance, and poor sweep efficiency are major concerns in an enhanced oil recovery (EOR) flood when implemented across multiple intervals. Oil recovery and flood performance in reservoirs with multiple lobes characterized by heterogeneous rock properties suffer greatly when the lobes are commingled. Tinsley Field is a reservoir with two distinct lobes. Initial development of the EOR flood commenced by commingling injection in the same wellbore and production from the two lobes to decrease the capital cost and boost oil production. Reservoir management of the CO2 flood indicated good sweep was taking place in one lobe. Concerns about the possibility of early breakthrough of CO2 in the dominate lobe, leaving stranded oil in the other lobe, prompted the initiation of a dedicated injection program. Early breakthrough could lead to filling up our compressors more quickly than anticipated, which could increase our capital requirements. Dedicated injection into individual lobes was initiated to improve the sweep efficiency. The team devised a methodology to select prospective wells and quantify the feasibility of adding new dedicated injectors in some of the existing patterns at Tinsley field. The methodology utilized a combination of geological cross sections to identify areas that are characterized by two lobes separated by a shale barrier or baffle, injection profiles to identify the current CO2 allocation, and an estimation of remaining oil in place. A sector model was constructed to simulate the recovery process and aid in understanding the impact of dedicated injection on oil production rate and recovery from individual lobes. The study revealed that only two of the three fault blocks can be characterized with an upper and lower lobe. Within those two fault blocks, several producers were identified as having poor conformance with a high remaining oil in place. Numerical results of the simulation model show that without dedicated injectors, the two lobes will be flooded at two different injection rates leaving substantial oil unrecovered because of the different injectivity of each zone. Candidate dedicated injectors were selected and ranked for execution based on our methodology. The early results from the dedicated injection program indicate it will lead to a higher recovery factor in the lower lobe because of dedicated injection into the lower lobe resulting in higher processing rate of CO2. The methodology presented in this paper provides a logical workflow that can identify areas with stranded oil in a reservoir with multiple zones. Following this process could lead to opportunities to drill dedicated injectors to improve oil production rate, conformance, and recovery factor.
- North America > United States > Mississippi > Yazoo County (1.00)
- North America > United States > Texas (0.93)
- Geology > Geological Subdiscipline (0.88)
- Geology > Structural Geology (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.35)
- South America > Venezuela > Anzoátegui > Eastern Venezuela Basin > Maturin Basin > Santa Rosa Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (36 more...)
Abstract This paper describes the use of advanced completions employing passive inflow control devices (ICD) and autonomous inflow control devices (AICD) in multi-zone horizontal wells to improve the distribution of gas injection and to restrict premature production of gas in gas injection soak EOR process for unconventional oil wells. The recovery efficiency of unconventional oil reserves is very low due to the micro-permeability of these reservoirs and rapid depletion of pore pressure proximal to the fractures and wellbore. Several enhanced oil recovery schemes have been proposed to stimulate production and increase recovery efficiency in these reservoirs by injecting gas or carbon dioxide in fracture stimulated, long horizontal wells, and either producing oil from adjacent wells (gas injection flooding drive mechanism), or by back-producing the injectant and reservoir fluids in the same wellbore after a suitable "soak" period (huff and puff). The effective distribution of the injected gas in these wells and the ability to keep the gas in the reservoir to maintain energy can greatly affect the recovery efficiency that can be achieved. Advanced completions utilizing appropriately designed ICDs and AICDs can enhance the performance of these EOR schemes. ICDs can be used to balance the distribution of gas injection along the length of the wellbore, while AICDs can help control the early back-production of gas. The Autonomous Inflow Control Device (AICD) is an active flow control device that delivers a variable flow restriction in response to the properties (viscosity) of the fluid flowing through it. Water or gas flowing through the device is restricted more than oil. When used in a horizontal well, segmented into multiple compartments, this design prevents excessive production of gas after breakthrough occurs in one or more compartments. The implementation of advanced completions in EOR applications has been studied by reservoir and well performance simulation. This proper use of ICDs and AICDs in these applications can significantly improve recovery efficiency without further well intervention. To evaluate the performance of the AICD, a comprehensive multi-phase flow model of the autonomous performance has been developed and workflow created for simulation of performance within the reservoir. This paper will describe the experience with the technology and modelling prediction for EOR projects.
- North America > United States > North Dakota (1.00)
- Europe (0.94)
- North America > United States > Texas (0.93)
- Geology > Petroleum Play Type > Unconventional Play (0.69)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.66)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.32)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (17 more...)
Creation of Insitu EOR Foams by the Injection of Surfactant in Gas Dispersions - Lab Confirmation and Field Application
Ocampo, Alonso (Equion Energia Limited) | Restrepo, Alejandro (Equion Energia Limited) | Lopera, Sergio H. (Universidad Nacional De Colombia) | Mejia, Juan M. (Universidad Nacional De Colombia)
Abstract This work presents the conceptual development and experimental evaluation for a new technique to create blocking foams in matrix rock systems by the injection of the foaming agent dispersed in the hydrocarbon gas stream. This new technique aims at simplifying the operation and reducing costs for the deployment of EOR foams in gas injection based projects, and overcoming the disadvantage of limited reservoir volume of influence obtained in the SAG technique. A systematic experimental work is implemented to investigate the effect of the dispersed chemical (surfactant) concentration and the gas velocity on the ability to create blocking foams at high pressure and temperature, and using representative consolidated porous medium and fluids coming from the Piedemonte fields in Colombia. The concept behind this new technique is the transfer of chemical foamer from the gas dispersion into the connate or residual waters present in the hydrocarbon reservoirs under exploitation, due mainly to the chemical potential derived from the contrast in chemical concentration between the dispersed phase and the in-situ water. Results herein confirm that it is possible to create blocking foam by this technique in a consolidated sandstone core at residual oil and water conditions, after being submitted to a gas flooding displacement. This condition is obtained as far as the gas velocity is above a minimum threshold, and the concentration of the active chemical is above certain limit (138 ppm for this case). Successful experiments with foams created by gas dispersed surfactant showed much longer stability periods when compared with results from foams created by the SAG technique at much higher chemical concentration (2,000 ppm). Application of this foams technique was done in a field pilot. About 600 Bbls of foaming solution were dispersed in the hydrocarbon gas stream in one gas injector of a Piedemonte field (Colombia, South America). Gas injectivity in the well was impaired after two weeks of injection, and the oil production well influenced by this injector changed its performance showing incremental oil production and flattening of the gas oil ratio (GOR) shortly after the dispersed chemical injection period. This innovative foams technique could also be extended to other non-condensable gases at field operating conditions like CO2, Nitrogen, Air, and Flue Gas.
- Asia (0.95)
- South America > Colombia (0.71)
- North America > United States > Texas (0.47)
- (3 more...)
- North America > United States > California > San Joaquin Basin > Midway-Sunset Field > Webster Formation (0.99)
- North America > United States > California > San Joaquin Basin > Midway-Sunset Field > Monterey Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- (11 more...)
Abstract The in-situ steam based technology is still the main exploitation method for bitumen and heavy oil resources all over the world. But most of the steam-based processes (e.g., cyclic steam stimulation, steam drive and steam assisted gravity drainage) in heavy oilfields have entered into anexhaustion stage. Considering the long-lasting steam-rock interaction, how to further enhance the heavy oil recovery in the post-steam injection era is currently challenging the EOR (enhanced oil recovery) techniques. In this paper, we present a comprehensive review of the EOR processes in the post steam injection era both in experimental and field cases. Specifically, the paper presents an overview on the recovery mechanisms and field performance of thermal EOR processes by reservoir lithology (sandstone and carbonate formations) and offshore versus onshore oilfields. Typical processes include thein-situ combustion process, the thermal/-solvent process, the thermal-NCG (non-condensable gas, e.g., N2, flue gas and air) process, and the thermal-chemical (e.g., polymer, surfactant, gel and foam) process. Some new in-situ upgrading processes are also involved in this work. Furthermore, this review also presents the current operations and future trends on some heavy oil EOR projects in Canada, Venezuela, USA and China. This review showsthat the offshore heavy oilfields will be the future exploitation focus. Moreover, currently several steam-based projects and thermal-NCG projects have been operated in Emeraude Field in Congo and Bohai Bay in China. A growing trend is also found for the in-situ combustion technique and solvent assisted process both in offshore and onshore heavy oil fields, such as the EOR projects in North America, North Sea, Bohai Bay and Xinjiang. The multicomponent thermal fluids injection process in offshore and the thermal-CO2and thermal-chemical (surfactant, foam) processes in onshore heavy oil reservoirs are some of the opportunities identified for the next decade based on preliminary evaluations and proposed or ongoing pilot projects. Furthermore, the new processes of in-situ catalytic upgrading (e.g., addition of catalyst, steam-nanoparticles), electromagnetic heating and electro-thermal dynamic stripping (ETDSP) and some improvement processes on a wellbore configuration (FCD) have also gained more and more attention. In addition, there are some newly proposed recovery techniques that are still limitedto the laboratory scale with needs for further investigations. In such a time of low oil prices, cost optimization will be the top concerns of all the oil companies in the world. This critical review will help to identify the next challenges and opportunities in the EOR potential of bitumen and heavy oil production in the post steam injection era.
- South America > Venezuela (1.00)
- Asia > Middle East (1.00)
- Asia > China (1.00)
- (7 more...)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.92)
- South America > Venezuela > Zulia > Maracaibo Basin > Tia Juana Field (0.99)
- South America > Colombia > Putumayo Department > Putumayo Basin (0.99)
- South America > Brazil > Espírito Santo > South Atlantic Ocean > Campos Basin > Block BM-C-30 > Jubarte Field (0.99)
- (40 more...)