Cyclic Steam Injection Research Articles

Improved Genetic Algorithm for Injection Production Parameters Optimized Design of Steam Soak Well

He development effect of steam soak well is influenced by the combination of the following parameters: injection speed, dryness fraction of steam, cyclic steam injection volume, soaking time and bottom hole flowing pressure. Take the advantage of annealed genetic algorithm which characterize with the traits of fast search and globally optimization. Based on the mathematical model of the output of the steam soak well, and optimize injection production parameter of the steam soak well which is aimed at the cycle average daily profit maximum, and make the field application.

Optimal Orthogonal Design for Herringbone Wells Injection and Production Parameters of Steam Stimulation in Heavy Oil Reservoir

Herringbone wells can effectively increase the exposed area of oil layer, increase reservoir producing degree, and extend the steam swept volume, ultimately to enhance recovery. The result of steam stimulation depends on injection-production parameters. This paper studies the six injection-production parameters including steam quality, steam injection rate, steam injection pressure, soaking time, cyclic steam injection volume and the maximum lifting rate, and considers the interaction among steam quality, steam injection rate and steam injection pressure. Using visual analysis and variance analysis to analyze the test results, the optimal combination of injection-production parameters were obtained, and the various factors were sorted according to their impact on the cumulative oil steam ratio. Research shows that the impact of interaction is not significant. The results of orthogonal numerical test can provide a theoretical guidance for herringbone wells injection-production parameter analysis optimization of steam stimulation in the field, and also have some practical significance.

Shallowest Horizontal Well Drilled in the Middle East: Challenges and Successes

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142439, ’Shallowest Horizontal Well Drilled in the Middle East: Challenges and Successes,’ by Abhijit Dutta and Bader M. Al Azmi, Kuwait Oil Company, and Hakim Al Abri, and Musab Ali, Halliburton, prepared for the 2011 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 25-28 September. The paper has not been peer reviewed. Major plans are underway to exploit heavy-oil resources in very shallow regions of Kuwait. Drilling horizontal wells poses great challenges in these shallow formations and requires high dogleg severity (DLS) through extremely loose formations while drilling with a conventional Kelly-drive rig. The use of multitier planning and exact execution enabled successful drilling and completion of the shallowest horizontal well in Kuwait on the first attempt. Introduction The Lower Fars is a shallow unconsolidated heavy-oil reservoir in northern Kuwait. The reservoir is mainly in the southern part of the Ratqa field. The lithology sequence from the surface to the Lower Fars includes the surface Kuwait-series sand, which has the Dibdiba freshwater aquifer (approximately 150 to 250 ft deep) and a brackish-water channel just above the shale cap of the heavy-oil-sand strata. Because the unconsolidated-sand reservoir is at an extremely shallow depth of approximately 700 ft and is in close proximity to infrastructure, it is attractive for exploitation by vertical wells but poses many challenges for drilling horizontal wells with an extremely shallow kickoff point (KOP) and high DLS. More than 75 vertical wells have been drilled, with coring, sampling, vertical-seismic profiling, full-suite logging (including imaging), and extended leakoff testing in many wells to evaluate the friable, unconsolidated, and loose sand. The preferred production method is cyclic steam injection (huff-’n’-puff) to reduce the viscosity of the oil for enhancing production. Both casing strings (surface and production) in all wells drilled at Lower Fars are cemented with thermal cement that can withstand thermal-cyclic stress. Challenges Concerns were raised in regard to the technical viability of drilling these horizontal wells with a conventional Kelly-driven rig. A slant rig could eliminate many of the disadvantages expected with a vertical rig. However, the cost of hiring a slant rig and nonviability of deploying a vertical rig for workover operations in slant wells prevented use of this method. The biggest challenges in drilling a horizontal well were to maintain the directional trajectory and to lower the casing and liner by use of a Kelly-driven rig with little weight available. Drilling through shale at a high angle also was perceived as a potential challenge.

Field scale applicability and efficiency analysis of Steam-Over-Solvent Injection in Fractured Reservoirs (SOS-FR) method for heavy oil recovery

Heavy oil recovery from fractured carbonates is a real challenge, yet no proven technology exists as an efficient solution. Reservoir heating is generally inevitable and steam injection is the only effective way to heat heavy-matrix oil in such reservoirs using the steam distributed through fracture network. We propose a new method minimizing heat needed for efficient heavy oil recovery from oil-wet fractured rocks by adding solvent component. Efficiency is a critical issue in this process due to potentially high cost of the process. A new technique we proposed previously called Steam-Over-Solvent in Fractured Reservoirs (SOS-FR) consists of a cyclic injection of steam and solvent in the following manner: Phase-1: Steam injection to heat up the matrix and recover oil mainly by thermal expansion, Phase-2: Solvent injection to produce matrix oil through diffusion–imbibition-drainage processes, and Phase-3: Steam injection to retrieve the injected solvent and recover more heavy oil. Laboratory scale static and dynamic experiments had shown that, under very unfavorable conditions (oil-wet matrix, 4000cp crude), oil recovery at the end of Phase-3 was around 85–90% OOIP with 80–85% solvent retrieval (Al-Bahlani and Babadagli, 2008, 2009a). In this paper, the experimental results obtained earlier were matched to a single matrix/single fracture numerical model and parameters needed for field scale simulation (matrix-fracture thermal diffusion, solvent diffusion and dispersion coefficients) were obtained (Al-Bahlani and Babadagli, 2009b). Using the data obtained through matching, field scale simulations were performed for efficiency analysis and to identify the optimal injection schemes (soaking time for cyclic and injection rate for continuous injection) and durations, and surface steam quality. Specific conclusions as to how to apply this technique efficiently in the field considering the cost of the process were reported.

Inflow Performance of a Cyclic-Steam-Stimulated Horizontal Well Under the Influence of Gravity Drainage

Summary In this paper, we present a new, semianalytical gravity-drainage model to predict the oil production of a cyclic-steam-stimulated horizontal well. The underlying assumption is that the cyclic steam injection creates a cylindrical steam chamber in the upper area of the well. Condensed water and heated oil in the chamber are driven by gravity and pressure drawdown toward the well. The heat loss during the soak period and during oil production is estimated under the assumption of vertical and radial conduction. The average temperature change in the chamber during the cycle is calculated using a semianalytical expression. Nonlinear, second-order ordinary differential equations are derived to describe the pressure distribution caused by the two-phase flow in the wellbore. A simple iteration scheme is proposed to solve these equations. The influx of heated oil and condensed water into the horizontal wellbore is calculated under the assumption of steady-state radial flow. The solution from the semianalytical formulation is compared against the results from a commercial thermal simulator for an example problem. It is shown that the model results are in good agreement with those obtained from reservoir simulation. Sensitivity studies for optimization of wellbore length, gravity drainage, bottomhole pressure, and steam-injection rate are conducted with the model. Results indicate that the proposed model can be used in the optimization of individual-well performance in cyclic-steam-injection heavy-oil development. The semianalytical thermal model presented in this work can offer an attractive alternative to numerical simulation for planning heavy-oil field development.

Changes Associated with Field-Scale Demonstration in a Steam-Stimulated Crude Oil from the Lagunillas Oilfield (Lake Maracaibo, Venezuela)

Cyclic steam injection with alkali is currently very commonly used to improve heavy-crude oil production in Venezuela. This work is an analysis of oil-associated water and crude samples from LL-2670 well in the Lagunillas oilfield at Lake Maracaibo (northwestern Venezuela). The aim of this research is to analyze the organic acids thus generated and evaluate chemistry changes in the saturated and aromatic fractions of crude oil during the first cycle of steam stimulation by cyclic injection with alkali. It was noted that the percentages of sulfur and saturates, aromatics, resins, and asphaltenes (SARA) and the American Petroleum Institute (API) gravity varied little in the analyzed crude. In contrast, there were significant variations in the biomarker distribution, particularly in the mono- and triaromatic steranes, benzothiophenes, phenanthrenes, and alkyl-naphthalenes of the crude.

Case History: Steam-Injection Monitoring With Optical-Fiber Distributed-Temperature Sensing

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 127937, ’Case History - Steam-Injection Monitoring with Optical-Fiber Distributed Temperature Sensing,’ by Marcelo A.P. Batocchio, SPE, Halliburton, and Adriana L.C. Triques, Hardy L.C. Pereira Pinto, Luis A.S. de Lima, Carlos F.S. Souza, and Ronaldo G. Izetti, Petrobras, prepared for the 2010 SPE Intelligent Energy Conference and Exhibition, Utrecht, The Netherlands, 23-25 March. A project was initiated by Petrobras to map the steam-front progress in a steam-assisted-production heavy-oil field. A distributed-temperature-sensing (DTS) system was installed to monitor the temperature distribution in a wellbore of a pilot program having three producers and one continuous-steam-injection well. Introduction In heavy-oil fields produced by steam injection, companies seek information to improve the drive mechanism that moves the crude oil into the wellbore. Monitoring equipment and interpretive-software tools help to achieve production requirements, maintain economic feasibility, and promote safety. In this project, high-temperature conditions were factors also. Optical-fiber DTS is a downhole-monitoring technology that provides permanent and continuous well-temperature profiling. This method enables real-time data collection, whereas traditional downhole monitoring during production provides temperature data only at a fixed point for each reading. Alternatively, wireline temperature logs can be run, but this method does not offer continuous monitoring and it affects production. With the DTS technique, the optical fiber typically is attached to the tubing and provides a complete log of the well temperature for each reading, enabling permanent and continuous monitoring without production interruption. Steam-front progress, which can improve the understanding of the reservoir geological model, can be followed; steam-breakthrough can be identified; and improved injection-efficiency then can be achieved. Project Implementation Estreito is an onshore field in northeast Brazil, 180 km from the city of Natal. This field is part of the Potiguar basin. The main reservoirs are Açu 100 and Açu 50/60, which are part of the Açu formation. These shallow reservoirs (approximately 200 m deep) originated from a fluvial depositional system. They have strong heterogeneities, have a strong active bottom aquifer (Açu 100), and are controlled by an ensemble of faults known as Carnaubais. The 15°API oil has high viscosity (2,000 cp). Cyclic steam injection began in 1984 as an improved-recovery process. This method is no longer economically viable and is being replaced by continuous steam injection. The efficiency of continuous steam injection is related directly to knowledge of heat-flow paths, which is reflected in the steam/oil ratio and the recovery factor of the area. Therefore, the operator has monitored heat transfer throughout the field since the beginning of steam injection.

Solar assisted method for recovery of bitumen from oil sand

A novel concept for the recovery of bitumen from oil sands in a natural gas limited environment with and without CO 2 constraints is presented. We suggest a feasible method for the recovery of unconventional oil in an environmentally friendly and sustainable way that has the potential of eliminating the need of natural gas as a process fuel. The proposed concept involves mid temperature steam generation for stimulating an oil sand formation. The steam is generated by utilizing solar radiation. The method uses the thermal mass of the oil sand formation to allow for cyclic steam injection during solar availability while still yielding continuous bitumen recovery. Feasibility assessments of the concept from both a thermodynamic and financial point of view are presented for a scenario of development in the Athabasca region in Alberta, Canada.

NUMERICAL SIMULATION FOR CYCLIC STEAM INJECTION AT SANTA CLARA FIELD

This article presents the methodology used and the results obtained in the construction, match and prediction of the first thermal composition simulation model done in Colombia by employing advanced thermal process commercial software, globally recognized because of its effectiveness in modeling these types of processes (CMG-STARS, 2005). The Santa Clara and Palermo fields were modeled and an excellent history match was achieved. All in all 28 wells and 17 years of production were matched. Two production scenes were proposed. The first involved primary production from existing wells, in other words: primary production; and a second escen where all the wells in the field are converted into injectors and producers, to simulate cyclic steam injection. This injection process included a series of sensitivity studies for several of the parameters involved in this technology, such as: pressure and temperature injection, time and rate of injection, heat injected, soaking period, steam quality, and injection cycles. This sensitivity study was focused on optimizing the processes to obtain the maximum end recovery possible. The information entered into the simulator was validated by laboratory tests developed at the Instituto Colombiano del Petróleo (ICP). Among the tests performed the following were assessed: rock compressibility, relative permeability curve behavior at different temperatures, formation sensitivity to injection fluids, DRX analysis and residual saturation of crude oil for steam injection. The aforementioned results are documented in this paper.

Labyrinth Packer Lowers Costs for Steam-Injection Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 110454, "Labyrinth Packer Lowers the Costs for Steam-Injection Wells: Theoretical and Experimental Results," by C. Teodoriu, SPE, and G. Falcone, SPE, Texas A&M U., originally prepared for the 2008 SPE Symposium on Improved Oil Recovery, Tulsa, 19-23 April. The paper has not been peer reviewed. The full-length paper describes a low-cost completion technique that uses conventional tubing and replaces the expensive thermal packer with a new low-cost design. The new design allows free tubing expansion and protects casing through continuous gas circulation in the annulus. It also makes possible simultaneous injection of combustion gases from steam generators when conventional systems are used, or small amounts of nitrogen (N2) when the generators are not available. Introduction Steam injection is an enhanced-oil-recovery technique that is used in heavy-oil exploitation. Steam injection and steamflooding are used widely in heavy-oil production. A typical steam-injection completion contains a special thermal packer designed to withstand the downhole injection temperatures, an expansion joint, and insulated tubing. Temperatures as high as 350°C are common for steam-injection projects. Simplifying the well completion will reduce operating costs and intervention time. Most of the heat-transport phenomena in steam-injection wells are the result of water in the annulus. Several papers have reported on the importance of water removal from the annulus to reduce heat transfer and keep the casing temperature low. For long-term injection processes it is impossible to prevent the casing from reaching high temperatures. However, when short-term processes are involved, such as in huff ‘n’ puff operations, it is possible to keep the casing cool. Two processes are available to keep the casing cool: passive cooling, in which the tubing is insulated and the casing is kept cool because the heat flux is reduced, and active cooling, in which the heat dissipated by the tubing is transported away from the casing. Active cooling has the advantage that it can keep the casing cool for a much longer time than passive cooling. The common failures of casing that may occur in wells stimulated through huff ‘n’ puff (cyclic) steam injection are rupture, collapse, connection leaking, and corrosion. Most of these failures are caused by excessive casing temperature. New casing designs and new materials are reducing these failures in new wells. Thus, the new steam-stimulation process is applied to existing wells where casing strings have not been designed to withstand high temperature. The nature of the cyclic steam process keeps the casing exposure time to high temperatures low, and the completion equipment used must keep the heat away from the casing for 4 to 10 days. A classical well completion for cyclic steam injection consists of insulated tubing, expansion joint, and thermal packer. When the steam temperature exceeds 250°C, a gravel-pack completion must be run after the injection phase, because the sand-grain size will shrink or sand will disintegrate in contact with hot steam or water.

A Critical Review of Electromagnetic Heating for Enhanced Oil Recovery

A variety of enhanced oil recovery methods have been developed and applied to mature and depleted reservoirs in order to improve the efficiency of primary (pressure deleted) and secondary recovery (water flooding) methods. In thermal recovery methods, cyclic steam and hot water injection, steam and hot water flooding, in situ combustion, electrical heating, and electromagnetic heating are used. However, each of these methods is highly energy intensive. Electromagnetic enhanced oil recovery method is a relatively new method and has been of great interest in the recent years. This article presents a critical review of electromagnetic heating of reservoirs for enhanced oil recovery.

Technology Focus: Artificial Lift (July 2008)

Technology Focus Artificial lift plays a fundamental role in several international plays. This month, artificial lift in oil-sand and deepwater developments is highlighted. In both cases, artificial lift is not just accelerating production but is vital to the economic success of the overall development. Today, the Canadian oil-sand developments have followed these different approaches: mining, cyclic steam injection, and steam-assisted gravity drainage (SAGD). As reservoir depth increases, artificial lift, rather than mining, is used to bring hydrocarbons to the surface. While cyclic steam injection and SAGD both push the high-temperature envelope for pumping, new techniques are being proved for this harsh environment. During the production phase of cyclic steam injection, the wells initially flow to the surface. Later production moves into the "flumping" stage (simultaneous flowing and pumping) and then into pumping. While sucker-rod pumping has been dominant, progressing-cavity pumps and electrical submersible pumps (ESPs) are being proved under these extreme conditions. In addition to downhole pumping, there is widespread use of surface multiphase pumps. Technologies that allow pumping high-temperature fluids without cooling represent opportunities to retain heat and improve the overall process efficiency. Surface pumping of a high-temperature multiphase mixture has become an established technology in Alberta. For deep water, artificial lift plays a strategic role, enabling companies that possess advanced technology to develop fields that other companies may determine to be too difficult. The ability to deliver an advanced artificial-lift system is the difference between booking reserves and walking away from deepwater discoveries. Only recently have we seen rapid growth in the application of subsea multiphase pumping. In addition to seafloor boosting, several other artificial-lift methods are applied in deep water, including gas lift and wellbore ESPs. In all cases, the ultimate success of these developments depends on the reliability of the artificial-lift system combined with the cost of intervention. Artificial Lift additional reading available at the SPE eLibrary: www.spe.org SPE 113904 • "Recent Advances and Practical Applications of Integrated Production Modeling at Jack Asset in Deepwater Gulf of Mexico" by Umut Ozdogan, Chevron Energy Technology Company, et al. IPTC 11594 • "A New Approach to Gas Lift Optimization Using an Integrated Asset Model" by Fernando Gutierrez, Schlumberger, et al. SPE 110234 • "Overview of Beam-Pump Operations" by O. Lynn Rowlan, Echometer Company, et al. Additional reading available at OnePetro: www.onepetro.org OTC 18820 • "The Use of Subsea Gas Lift in Deepwater Applications" by Subash S. Jayawardena, Shell Global Solutions, et al. (See JPT June, 2008, page 64.)

Mapping Reservoir Volume Changes During Cyclic Steam Stimulation Using Tiltmeter-Based Surface-Deformation Measurements

Surface-deformation measurements have been used for years in oil fields to monitor production, waterflooding, waste injection, steam flooding, and cyclic steam stimulation (CSS). They have been proved to be a very effective way to monitor field operations and save money for operators wishing to avoid unwanted surface breaches, casing failures, and excessive subsidence because of production. This paper demonstrates that more information can be extracted from surface-deformation measurements by inverting the surface deformation for the volumetric deformation at the reservoir level using the inversion techniques from the literature, so that the areal distribution of volumetric deformation can be identified. This leads to a better understanding of reservoir behavior and also provides additional data for integration into coupled reservoir simulation modeling. This paper shows the results of mapped reservoir volume changes from two cyclic steam injection projects using tiltmeter-based surface deformation measurements.

Extra Heavy Crude Oil Downhole Upgrading Using Hydrogen Donors Under Cyclic Steam Injection Conditions: Physical and Numerical Simulation Studies

Summary Physical simulation experiments of a downhole upgrading process showed that the use of a hydrogen donor additive (tetralin) in the presence of methane (natural gas) and mineral formation under cyclic steam injection conditions led to an increase of at least three degrees in API gravity of treated extra heavy crude oil, a three-fold viscosity reduction and an approximate 8% decrease in the asphaltene content with respect to the original crude. A continuous bench scale plant was used at different temperatures (280 – 315 ºC) and residence times (24 – 64 h) for carrying out kinetic studies. A reaction model involving four pseudo-components (light, medium, heavy and asphaltene fractions) was used and the kinetic parameters (pre-exponential factors and activation energies) were determined. Using these data, compositional-thermal numerical simulations were carried out and validated using the bench scale data. The results showed a good match between the calculated and experimental ºAPI gravities of the upgraded crude oil (average relative error 4%). Using the previous model, the downhole upgrading process was numerically simulated under cyclic steam injection conditions. The simulation runs showed the production of 12 ºAPI upgraded crude oil, accumulated over a 70-day cycle. However, a reduction in the percentage of conversion of tetralin was observed (0.8%) in comparison with the bench scale experiments (3%), which was attributed to gravitational segregation of the steam coupled with low mixing efficiency of the hydrogen donor with the extra heavy crude oil at reservoir conditions. Introduction Underground upgrading processes have always been of interest to the petroleum industry, mainly because of the intrinsic advantages compared with aboveground counterparts. Lower lifting and transportation costs from the underground to refining centres can be achieved, as well as a potential increase in the volumetric production of wells. In addition, a decrease in the consumption of costly light and medium petroleum oils used as solvents for heavy and extra heavy crude oil production can also be obtained. Finally, the use of porous media (mineral formation) as a natural chemical 'catalytic reactor' will allow the improvement of the properties of the upgraded crude oil, further reducing expenses for downstream refining operations. Several methods of underground crude oil upgrading have been reported. These concepts include downhole steam distillation(1), deasphalting(2–5), underground visbreaking(6–9), hydrogen(10–17) or hydrogen precursor injection(18–22) and in situ combustion(23–25). With the exception of the latter, the numerical simulation of downhole upgrading processes has relatively little research on it. Shu and Hartman(8) and Shu and Venkatesan(26) used compositional simulation and experimentally measured kinetic data to determine the effect of the visbreaking reactions on the percentages of recovery of heavy crude oil produced by cyclic steam injection and steamflood. For the former route, the authors found an increase of 5% in the oil recovery due to viscosity reduction in the heated zones of the reservoir(8). Similarly, Kaskale and Farouq Ali(7) reported the numerical simulation of a steamflood in a five-spot array for the production of upgraded Saskatchewan crude oil.

Heavy-Crude-Oil Upgrading With Transition Metals

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 107837, "Heavy-Crude-Oil Upgrading With Transition Metals," by H.R. Nares, P. Schacht-Hernandez, M.A. Ramirez-Garnica, and M.C. Cabrera-Reyes, Inst. Mexicano del Petroleo, and L. Noe-Valencia, U. La Salle, Mexico, prepared for the 2007 SPE Latin American and Caribbean Petroleum Engineering Conference, Buenos Aires, 15–18 April. The full-length paper discusses the effects of some metallic oxides used to upgrade heavy-crude-oil properties. The objective is to increase oil mobility in the reservoir by reducing viscosity and improving oil quality by use of alumina-supported transition metals and liquid-phase transition-metals catalysts derived from acetylacetonate or alkylhexanoate compounds. Heavy crude oil from the Gulf of Mexico (GOM) was studied. Oil gravity was increased from 12.5 to 21 to 26°API, asphaltene content was reduced from 26 to 7 wt%, and distillable fraction was increased by 20 to 30 wt%. Introduction Some of the main problems that heavy crude oil presents are:low mobility through the reservoir because of its high viscosity, which affects the wells productivity index (PI);difficult transportation to the refineries and the high cost of that transportation; andthe low processing capacity in the refineries. For these reasons, it is necessary to enhance the heavy crude oil, both above ground and underground. Some of the main processes used are carbon rejection, hydrogen addition, and physical separation. All these processes are focused on converting oil residues into more-valuable products such as gasoline, middle distillate, and fluid-cracking catalytic feedstock. An interesting alternative to recover the heavy and extra heavy crude oil is downhole catalytic upgrading. This alternative presents several advantages compared with its above ground counterpart such as an increase in the well PI, a reduction in the lifting and transportation costs to the refining center, the production of more-valuable products as a result of the decreases in viscosity values, resins, asphaltenes, sulfur, and metal contents. Some of the most important processes that have been studied to enhance heavy and extra heavy crude oil are steam-drive, cyclic steam injection, steam-assisted gravity drainage, fireflood, and downhole catalytic processes. The main objective of these processes is to decrease the viscosity of the heavy crude oil to improve its flow from the reservoir to the producer well. This viscosity reduction can be achieved by increasing the reservoir temperature or by injecting hydrogen-donor compounds. Two ways to improve the quality of heavy crude oil are hydrocracking and hydrotreating such as aromatic hydrogenation and desulfurization. This removal can be achieved by injection of a catalytic solution [organic metallic compounds of molybdenum (Mo), iron (Fe), cobalt (Co), and nickel (Ni)].

Investigation of Drainage-Height Effect on Production Rate in the Vapor-Extraction Process

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 101684, "Further Investigation of Drainage-Height Effect on Production Rate in Vapex," by A.J. Yazdani, SPE, and B.B. Maini, SPE, U. of Calgary, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September. The full-length paper presents the results of a new set of vapor-extraction (vapex) -process experiments in a newly designed very-large physical model. The results are in good agreement with the trend of previous experiments in smaller models. The previously proposed scaleup relationship adequately predicts the results obtained with the new physical model. The new results were used to improve the previously reported empirical scaleup correlation for the vapex process. Experiments with different sand-packs reconfirm square-root functionality of the dead-oil production rate to the permeability. Introduction Interest in heavy-oil- and bitumen-recovery methods is growing because of the huge amount of proven resources in the world. Steam-assisted gravity drainage (SAGD), cyclic steam injection, and other steam-injection methods have been implemented successfully in some oil fields. However, there are many situations where economic constraints limit the application of these thermal processes. High costs of steam generation, excessive heat losses in thin reservoirs, produced-CO2 emission problems, water treatment, and many other technical problems are some of the reasons that make it necessary to look for alternatives to thermal methods. Solvent-based heavy-oil-recovery methods have gained attention recently because of their potential advantages over thermal processes. Solvents, if dissolved in the oil, are able to reduce oil viscosity dramatically. This viscosity reduction is comparable to that obtained by heating. Among the solvent-based methods, vapex has received more interest because of the very encouraging results reported in laboratory studies. Vapex basically is a solvent analog of the SAGD process. Two parallel horizontal wells are drilled one on top of the other in the same configuration as in SAGD. A solvent or a mixture of solvents is injected into the top well near its dewpoint. The solvent-selection criteria depend on reservoir pressure and temperature. A carrier gas usually accompanies the solvent to raise the dewpoint and keep it in vapor form at the prevailing reservoir pressure. Ethane, propane, and butane are considered good solvent candidates. Nitrogen, methane, or CO2 can be used as the carrier gas. The injected solvent vapor displaces the oil and begins to form a vapor chamber around the wells, which then propagates later-ally toward the formation boundaries. The oil production is a result of the dissolution and diffusion of the solvent into the oil zone. The diluted oil moves down to the bottom well through a thin layer near the edge of the oil/solvent interface. In this process, the driving force for the fluid flow primarily is gravity, and the wells are kept at equal pressures. Molecular diffusion and mechanical dispersion are believed to be the controlling mass-transfer mechanisms responsible for the solvent mixing with the oil. The solvent can be extracted at the surface and reinjected to the reservoir. The process continues until the economic limits are exceeded for the oil-production rate when the chamber drainage height decreases.

A case history of time-lapse 3D seismic surveys at Cold Lake, Alberta, Canada

Time-lapse 3D seismic surveys were acquired across a bitumen field at Cold Lake, Alberta, Canada, during a production cycle (1990) and a steam-injection cycle (1992) of a thermal-enhanced oil recovery (EOR) program. We observed changes in interval traveltime and amplitude distributions between the processed surveys. We interpret the increased traveltimes observed over most of the injection survey to be a result of lowered interval velocities in the reservoir, caused primarily by higher temperature and lower effective pressure. Reflection-strength variations within the reservoir are present in each data set and change spatially between the surveys. In general, we interpret the amplitude anomalies seen only on the production survey to be caused by local free gas and the amplitude anomalies seen only on the injection survey, which are close to the perforation depths, to be caused by thin, vertically restricted steamed zones.

Evaluation of Operational Performance of Gas Turbine Cogeneration Plants Using an Optimization Tool: OPS-Operation

To attain the highest performance of gas turbine cogeneration plants, it is necessary to rationally select the numbers and capacities of gas turbines and auxiliary equipment in consideration of their operational strategies corresponding to energy demands which change with season and time. It is also important to rationally select the options such as the variable heat to power by the steam injection or combined cycle, and the inlet air cooling by the ice storage combined with electric compression refrigeration or steam absorption refrigeration. The evaluation of the effects of these alternatives on the performance is an important work for designers. However, it takes much time to conduct the work thoroughly. The authors have developed an optimization tool named “OPS-Operation” to assess the operational strategies for given configurations and specifications of energy supply plants. This tool has a user-friendly interface for the functions of data registration, graphical flowsheet editing, automatic programming and optimization calculation, and graphical representation of results. In this paper, the effects of the aforementioned alternatives on the operational performance of gas turbine cogeneration plants are evaluated using the optimization tool in terms of many criteria including operational cost, energy consumption, and CO2 emission. It is demonstrated that the tool is very effective to evaluate the performance rationally, flexibly, and easily.

Humidified gas turbines—a review of proposed and implemented cycles

Gas turbines with air–water mixtures as the working fluid promise high electrical efficiencies and high specific power outputs to specific investment costs below that of combined cycles. Different humidified gas turbine cycles have been proposed, for example direct water-injected cycles, steam-injected cycles and evaporative cycles with humidification towers. However, only a few of these cycles have been implemented and even fewer are available commercially. This paper comprehensively reviews the literature on research and development on humidified gas turbines and identifies the cycles with the largest potential for the future. In addition, the remaining development work required for implementing the various humidified gas turbine cycles is discussed. This paper can also be used as a reference source that summarizes the research and development activities on humidified gas turbines in the last three decades.

A laboratory study of single-well steam-assisted gravity drainage process

An investigation of the optimization of startup procedure for single-well steam-assisted gravity drainage (SW-SAGD) was made as the project economics are influenced significantly by the early production response. An experimental investigation of two early-time processes namely cyclic steam injection and steam circulation to improve reservoir heating is discussed and compared to continuous steam injection as well as other well configurations like vertical injector–horizontal producer and horizontal injector–horizontal producer. Crushed limestone saturated with heavy oil (12.8° API) and water was packed in a laboratory model for the experiments. The effectiveness of the methods is compared within themselves and to conventional steam-assisted gravity drainage (SAGD) by measuring the size of the steam chamber as a function of time. The steam chamber area for cyclic steam injection is slightly greater than that of steam circulation case. Furthermore, numerical simulation studies of different early-time processes were conducted and compared to the experimental data using a commercial simulator. It was observed that the numerical model results underestimated the cumulative oil recovery and the steam chamber size. Results from this study, including cumulative recoveries, temperature distributions, and production rates display the differences between the methods.