Maintain Reservoir Pressure Research Articles

IMPROVEMENT OF THE CONDENSATE RECOVERY FACTOR BY USING THE CYCLING PROCESS TECHNOLOGY

The paper considers the cycling process as a method of gas condensate fields development by maintaining reservoir pressure through a reverse injection of gas into the productive horizon. The reservoir pressure maintenance impedes the liberation of high boiling hydrocarbons from the reservoir gas occurred due to retrograde condensation, which generate the gas condensate (which otherwise is practically lost). The experience of the cycling process realization proves its high technological and economic efficiency.

Modeling studies for production potential of Chingshui geothermal reservoir

The Chingshui geothermal power plant was decommissioned in 1993 due to a continued decline in production. Although some geothermal exploration and field investigation had been exercised, the production potential of the reservoir is still not well understood. In this paper, numerical modeling approaches for characterization of the geothermal reservoir, investigation of reservoir production performance, and evaluation of exploitation scheme design are presented. At first, a site-scale refined grid numerical model was developed for simulating the natural state of Chingshui geothermal reservoir. Through the model, the production potential of the geothermal reservoir was estimated and the availability of water resources was assessed. We further built production model to simulate the production history during 1981–1993. From the production model, we can conclude that the abnormal drop of the reservoir production capacity is mainly caused by carbonate scaling. Potential production schemes with different reinjection designs were evaluated through the model. Simulation results indicated that a sustainable hot water production capacity of Chingshui geothermal reservoir is about 200 t/h without reinjection, and 300 t/h or even higher with reinjection which is enough for a 3 MWe power plant. The simulation results indicate that reinjection provides an effective approach for maintaining reservoir pressure during hot water/steam production.

The effect of gas-condensate reservoir depletion stages on gas injection and the importance of the aerosol state of fluids in this process

As one of the primary techniques for enhanced oil recovery, the gas injection method has been investigated widely. However, introducing “dry gas” into a gas-condensate reservoir is more than miscible flooding that maintains reservoir pressure and improves oil displacement. This method is associated with complex thermodynamic processes or phase transitions, such as the re-vaporization of heavy hydrocarbon ends and connate water, the reduction of the condensate/gas ratio and retrograde dew point (RDP) pressure, etc. In this paper, a laboratory study was conducted to estimate the effectiveness of the gas injection process during gas-condensate reservoir development. Specific laboratory equipment was constructed to conduct an experimental investigation by modelling the gas injection and reservoir depletion process.Detailed analysis of experimental investigations suggests the gas injection process might be more effective when the “reservoir” pressure is below the initial RDP pressure of the fluid. Thermodynamically, this pressure stage could be conducive for gas injection, by decreasing the condensate/gas ratio, re-vaporizing the liquid phase that dropped out and maintaining the system in a single gas phase.To further examine the process of the liquid or fog formation phase in the gas-condensate mixture, the fluid was investigated as a colloidal structure. Theoretical findings confirm that the fog condition is a well-matched feature of gas-condensate fluids with the properties of aerosol-colloidal systems. The correlation between fog up (FU), RDP pressures and temperature was investigated experimentally. The rationale for increasing the difference between the FU and RDP pressures with the increase of temperature and other physical and thermodynamic properties of gas-condensate systems is explained according to the fundamentals of colloidal systems.Based on these obtained results, conclusions were reached about the physical nature of the condensation under reservoir conditions. The results show that condensation in the reservoir condition can occur when the pressure in the interval creates the formation of liquid phase micro-embryos or aerosols. Thus, the fluid condenses due to surface forces between the sub-micron-sized condensate particles and the rock granules. This phenomenon can cause condensate blockage or condensate banking in the early stage of reservoir development when even the reservoir pressure is greater than the RDP pressure identified in the PVT cell. These results were used to explain the dynamic processes occurring within and influencing the operating characteristics of the gas-condensate wells. Because these colloidal features of fluid can play a significant role in reservoir development, we recommended considering these aspects when planning gas injection methods.

Characterizing interwell connectivity in waterflooded reservoirs using data-driven and reduced-physics models: a comparative study

Waterflooding is a significantly important process in the life of an oil field to sweep previously unrecovered oil between injection and production wells and maintain reservoir pressure at levels above the bubble-point pressure to prevent gas evolution from the oil phase. This is a critical reservoir management practice for optimum recovery from oil reservoirs. Optimizing water injection volumes and optimizing well locations are both critical reservoir engineering problems to address since water injection capacities may be limited depending on the geographic location and facility limits. Characterization of the reservoir connectivity between injection and production wells can greatly contribute to the optimization process. In this study, it is proposed to use computationally efficient methods to have a better understanding of reservoir flow dynamics in a waterflooding operation by characterizing the reservoir connectivity between injection and production wells. First, as an important class of artificial intelligence methods, artificial neural networks are used as a fully data-driven modeling approach. As an additional powerful method that draws analogy between source/sink terms in oil reservoirs and electrical conductors, capacitance---resistance models are also used as a reduced-physics-driven modeling approach. After understanding each method's applicability to characterize the interwell connectivity, a comparative study is carried out to determine strengths and weaknesses of each approach in terms of accuracy, data requirements, expertise requirements, training algorithm and processing times.

Oil Recovery From Gas-Over-Bitumen Reservoirs: Results From the AIDROH Pilot Project in Alberta

Summary Producing from bitumen reservoirs overlain by gas caps can be a challenging task. The gas cap acts as a thief zone to the injected steam used during oil-recovery operations and hinders the effectiveness of processes such as steam-assisted gravity drainage (SAGD). Moreover, gas production from the gas cap can accentuate the problem even more by further depressurization of the gas zone. Following a September 2003 ruling by the Alberta Energy Regulator (AER), the oil and gas industry in the province of Alberta, Canada, had approximately 130 million scf/D of sweet gas shut-in to maintain pressure in gas zones in communication with bitumen reservoirs. This decision led to the development of EnCAID (Cenovus' air-injection and -displacement process), a process in which air is injected into a gas-over-bitumen (GOB) zone, and combustion gases are used to displace the remaining formation gas while maintaining the required formation pressure. An EnCAID pilot was started in June 2006, and preliminary results were reported in 2008. After 8 years of operations, the EnCAID project has not only proved to be effective at recovering natural gas and maintaining reservoir pressure, it has also shown it can heat up the bitumen zone and make the oil more mobile and amenable for production. This led to the development of the air-injection and -displacement for recovery with oil horizontal (AIDROH) process. The AIDROH process is the second of two distinct stages. First, an air-injection well is drilled and perforated in the gas cap. The well is ignited and air injection is performed to sustain in-situ combustion in the gas zone. This phase is characterized by a radially expanding combustion front, accompanied by conduction heating into the bitumen below. The second stage begins when horizontal wells are drilled in the bitumen zone. The pressure sink caused by drawing down the wells alters the dynamics of the process and creates a pressure drive for the combustion front to push toward the producers in a top-down fashion, taking advantage of the combustion-front displacement and gravity drainage. In light of the temperature increases observed in the bitumen overlain by the EnCAID project, a horizontal production well was drilled in late 2011 and commenced producing in early 2012. This paper provides an update of the EnCAID pilot results and presents a summary of the technical aspects of the AIDROH project, pilot results, and interpretation of the data gathered to date, such as observation-well temperatures, pre- and post-burn cores, and temperatures along the horizontal producer. Results indicate that the AIDROH process has the potential to maximize oil production from GOB reservoirs, and efforts continue to be made to optimize its design and operation.

Геодезические измерения в регионах интенсивного движения земной коры

Abstract: Reviewed studies on the oil fields, calculated the volume of crude oil performed and the volume of injected water produced to maintain reservoir pressure. These data were compared with the results of repeated leveling measurements. Numerous repetitive instrumental geodetic measurements in the oil fields in different regions have shown that the area where the oil is extractedisnot bearing recent vertical crustal movements manmade. On the basis of numerous repeated leveling measurements in a seismically active region established pattern of recent vertical crustal movements during the catastrophic earthquake.

FORMALIZATION TASK OF OPTIMIZING RESERVOIR PRESSURE MAINTENANCE SYSTEM

This article discusses aspects of the development of methods for the automated optimization of reservoir pressure maintenance through the use of models for the variation of performance control devices: throttling valves and characteristic group pumping station (SPS). In the operation of hydraulic systems to maintain reservoir pressure (PAP), there are a number of operational tasks which no systematic approach to the analysis of the state of the hydraulic system may not be adequate to the requirements of good governance. For the most effective management of structurally complex systems requires the use of the model system that mimics the behavior of real or projected hydraulic systems with arbitrary structure and indicators that make up their items. The complex is to be achieved with optimum joint compliance with the terms of minimizing the mean relative deviation from the optimal current pickups - and maximize efficiency system - a need to maximize the efficiency factor - reflecting the joint fulfillment of the conditions of technology and technical optimization. In addition to controlling the flow of fluid parameters, the model allows modifying the properties of the individual elements of the track projected costs and the fluid pressure in the system variable Selecting the optimum condition or just a way to optimize the resources we mean to achieve the goal of optimization: a set of technological parameters, which change in the real system, will change the complex hydraulic regime, in line with its optimal state.

Pilot to Full-Field Polymer Application in One of India’s Largest Onshore Fields

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 169146, “Pilot to Full-Field Polymer Application in One of the Largest Onshore Fields in India,” by Dhruva Prasad, Amitabh Pandey, SPE, M. Suresh Kumar, and Nitish Koduru, SPE, Cairn India, prepared for the 2014 SPE Improved Oil Recovery Symposium, Tulsa, 12–16 April. The paper has not been peer reviewed. A normal five-spot polymer-flooding pilot has been conducted at the Mangala field, one of the largest onshore fields in India, and results are encouraging in terms of additional oil recovery and reduction of water cut. Polymer flooding has the potential to improve sweep efficiency in the field significantly and to increase expected ultimate recovery (EUR). The project is one of the largest in the world in terms of scale, polymer usage, and related facility and logistics. Introduction The main reservoir unit in Mangala field is the Fatehgarh group. Five reservoir units (FM1–FM5) have been named from the top down. Mangala contains waxy sweet crude oil with gravity ranging from 20 °API near the oil/water contact to 28 °API higher in the oil column. The crude has an in-situ oil viscosity of 9–22 cp, with live-oil wax-appearance temperature approximately 6°C lower than the average reservoir temperature of 65°C. The oil also has a high pour point of 40–45°C, which had a great influence on all aspects of the project and process design. The development plan involved implementing a hot waterflood from production startup to maintain reservoir pressure and sweep reserves effectively. On the basis of appraisal data, it was realized from the start that Mangala was a candidate for an enhanced-oil-recovery (EOR) process. Detailed laboratory evaluations and simulation studies suggested chemical flooding as the appropriate EOR process for the field. A polymer-flood pilot was conceived on the basis of laboratory and simulation results. The pilot has been successful in terms of reducing water cut and increasing oil rate. Full-field implementation is now planned for Mangala.

Multidimensional Fuzzy Control System Development of Oil Transportation and Treatment Technological Processes Based on the Input/Output Parameters Model in the Precise Terms Set Form

As pumps and pumping stations of oil collecting, maintaining reservoir pressure, transportation and treatment processes account for over 50 % of oil and gas enterprises estimated total cost of electricity, relevant issue is the development and application of intelligent control systems for energy efficiency of these processes. For the booster pump station as a multivariable nonlinear control object are proposed: a structure in which the function of regulating valves transferred to the pumps with frequency speed control; conceptual model with seven inputs and five outputs (adjustable) variables, which is the basis for constructing three-dimensional fuzzy controller with not-fuzzy terms to stabilize and improve the energy efficiency of oil transportation and treatment processes and minimize energy losses. In this paper we propose a control system of pumping station on the basis of multidimensional fuzzy logic controller with compensation of the mutual influence of control loops in the form of an additional system of production rules that helped to stabilize the liquid level at 2.5 m given level with an absolute error of ± 0.2 m and thus improve quality oil emulsion on the installation of oil and gas refining central collection point.

Gas Injection for Enhancement of Condensate Recovery in a Gas Condensate Reservoir

Gas condensate reservoirs suffer losses in well productivity due to near wellbore condensate dropout when the flowing bottom-hole pressure declines below the dew point pressure. Pressure maintenance and gas cycling are the common practices used in the oil and gas field to alleviate this problem and develop gas condensate reservoirs. The injection of dry gas into a retrograde gas condensate reservoir helps in vaporizing the condensate and increases its dew point. This article investigates the situation of one of the reservoirs located in southern Iran in Zagros area. First, based on the reservoir composition, the phase diagram has been plotted. Peng–Robinson equation of state for the equilibrium calculations and Lee–Kesler characterization of heavy fractions are used in this software. After that the effect of nitrogen, pure methane, a composition of ethane and methane, and carbon dioxide injections on reservoir recovery has been investigated and compared to a natural depletion scheme. The full system, including two separators and a stock tank, are simulated simultaneously and the effect of each type of injection on the liquid and gas production is investigated. Full mixing has been assumed in all of the injections studied. By comparing between the results it is concluded that in an injection process, required injection rate to maintain reservoir pressure above dew point pressure and avoid liquid formation in the reservoir for pure methane, a composition of ethane and methane, pure nitrogen and carbon dioxide, and liquid recovery in all cases are investigated. According to the results, with increasing ethane mole percent in the injecting gas a lower injecting rate for the same liquid recovery is needed. Because with increasing heavy components mole percent in injecting gas, average molecular weight of injecting gas, and reservoir gas becomes closer and there will be a better mixing between them and, therefore, liquid recovery will be improved. Thus, a composition of ethane and methane with more ethane mole percent is better than others.

Numerical simulation of surface-downhole geoelectrical measurements in order to detect brine plumes

A large amount of hydrocarbon reservoirs in the world are in the secondary recovery stage and improving this step in the exploitation of these reservoirs would greatly benefit the oil industry. Secondary recovery involves injecting brine in some wells in order to maintain reservoir pressure. The injected water moves mainly through the channels with higher permeability of the reservoir rock. The identification of these channels would allow the development of technical strategies to close them. In this context, the ability to detect brine flow pathways after injection is a goal of this work. Given the high electrical conductivity of brine, the use of geoelectrical methods can be useful to detect and monitor flow evolution. The limitations in the application of this method are due to the characteristics of the target: a very conductive fluid is usually contained in paths with dimensions that are much smaller than the depth at which it is located. Therefore, our objective is to overcome these constraints in order to find the strategies required to successfully detect and eventually monitor the movement of brine flowing from injection wells.In this work, we studied the feasibility of detecting brine in an oil reservoir with surface-downhole electrical measurements. To achieve this, we designed an electrical model of the reservoir from well data and numerically simulated the forward geoelectrical response to determine the conditions under which the anomaly, i.e., the accumulation of brine, can be identified. Our results show that once the initial location of the brine is known, by installing potential electrodes in a single well the direction of brine migration can be determined, even in unfavorable conditions with relatively few surface measurements. In the case of a well equipped with permanent electrodes, this could be an efficient method to monitor the evolution of the brine plume.

Análisis mediante simulación numérica de la inyección de baches surfactante/polímero para el campo yariguí-cantagallo operado por Ecopetrol S.A.

El Campo Yariguí-Cantagallo fue descubierto a mediados de los años 40’s, y adquirido por ECOPETROL S.Aen el año de 1975. En el mes de Noviembre de 2008, y debido a la disminución de la presión del yacimiento, Ecopetrol decide intervenirlo iniciando la implementación de métodos de recobro secundario. Se realizaría mediante la incorporación de un proceso de inyección de agua, con el fin de mantener la presión del yacimiento y que la producción de hidrocarburos aumente considerablemente. En el año 2010 el Instituto Colombiano del Petróleo de ECOPETROL S.A. inicia una evaluación de la viabilidad del recobro mejorado mediante inyección de químicos en el campo, con el fin de incrementar la producción de petróleo y el factor de recobro. A su vez, disminuir la producción de agua en los pozos productores.Dicha evaluación será hecha mediante el uso de la simulación numérica de yacimientos. Los beneficios del proceso EOR serán analizados a partir de la producción de agua y petróleo, así como de los posibles beneficios económicos que este puede generar.

Numerical simulation of produced water reinjection technology for water-soluble gas recovery

Water-soluble gas reservoir refers to those unconventional reservoirs composed of methane mostly, which dissolved in over-pressure and high-temperature groundwater. The Paleogene Wenchang and Enping Formations of the Huizhou Sag are major source rocks that generate significant quantities of gas and the sandstone reservoirs are varying from weakly overpressured to overpressured on the whole. According to the 3D geologic model using geostatistics method, the volume of water-soluble gas in the resource is about 1791.5 × 108 m3 and 2688.5 × 108 m3, 1.19 and 3.46 times of the conventional gas, respectively. The water-soluble gas is an unconventional resource with great potential, and can provide substantial gas source for conventional pools through degasification. In this paper, a new feasible technology is proposed for the development of water-soluble gas reservoirs. Produced water reinjection, when combined with water-soluble gas recovery, not only enhances the relatively gas production by maintaining reservoir pressure, but also contributes to the output of water treatment, especially under marine production conditions that faces the tough situation of the high cost and large number of water output. It has a significant meaning to alleviate the bottleneck problem of the resource shortage in Pearl River delta industrial base of China. A 3D injection–production model is developed using the TOUGH2/EOS7C program. Numerical results show that under the condition of constant bottom hole pressure 30 MPa, water injection can increase the plateau of the production period from 36.68 years to 70.53 years, and enhance the cumulative gas production effectively. Relative parameters are also analyzed, and the following conclusions can be drawn: producer–injector spacing and perforation intervals of producing well have considerable influences on the gas recovery, comparing with the rate of water-injection and perforation interval of injection well. In addition, it is necessary to find the optimal value of these parameters. In general, produced water reinjection is a potential choice for water-soluble gas recovery.

Long core physical simulation for CO<SUB align="right">2 flooding in low permeability reservoir

CO 2 flooding is a proven great method to be used for enhancing injection capacity and increasing oil production in low permeability reservoir. In this paper, based on the natural cores and crude oil of Jilin oilfield, three sets of long core tests were conducted to study oil recovery, GOR and pressure variations during water flooding and CO 2 flooding. The performance of advanced CO 2 injection, simultaneous CO 2 injection and water injection were compared to optimise injection opportunity and injection pattern for low permeability reservoir. Results indicate that advanced CO 2 injection is better in maintaining reservoir pressure and improving displacement efficiency. It is considered that advanced CO 2 injection before oil production supply valuable opportunity for CO 2 to fully contact with oil which could help decrease oil viscosity and interfacial tension, swell oil volume and increase injection rate effectively.

Энергосберегающий частотно-регулируемый электропривод кустовой насосной станции

Main task, standing before every enterprises in modern conditions, is to maximize profits for their shareholders and owners. To solve it, you can go two ways: to increase sales volume or to reduce costs. In this case, the increase in sales often require additional financing of production and may cause difficulties with the implementation of the finished product due to limited demand, while management of expenses is not associated with the above problems. Economic effect, which can be obtained from effective cost management, exceeds the effect that can be achieved by increasing sales. Currently, there is a constant increase in the cost of electricity, as well as rising prices for construction of new facilities. In addition, there is a tendency of transition to independent sources of supply process units in oil and gas industry. Application of regulated electric-powered gas power plants becomes economically and technically feasible. Today, most electric group pumping stations are powered by power lines suitable unified energy systems and are unregulated, which does not provide a rational mode of power consumption. The possibility of use as a fuel to power the local power supply (gas turbine generating set) of associated gas, burned in flares, is discussed in this article. To prove that, the calculation, showing a sufficient volume of associated gas and as a result of technical and economic effect on the example of cluster pump station for pumping waste water into the reservoir of Krasnoyaro-Kuedinsky oil field to maintain reservoir pressure, is represented. From the calculations you can see, that the volume of gas that can be used to operate the gas turbine electric plant consisting of two such units (Capstone C800) is sufficient, hence the use of gas-fired power plant on the territory of the oil and gas is possible. The remainder of the associated gas in order to meet the requirements of "Regulation on measures to stimulate the reduction of air pollution combustion products of associated gas flaring" is proposed for use in the boiler room for heating industrial premises shop, or furnaces, heating oil, according to the technology of oil treatment. That is why, priority access to the wholesale market for electricity produced by means of associated gas or products can be achieved. Additional technical effect when using the gas, provided by eliminating flare, is significant enough and allows to realize the full use of the whole volume.

Integrating Well, Reservoir, and Facility Management Improves Field's Production

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 16523, ’Oman's Large-Carbonate-Field Production Improvement Through Integrated Well, Reservoir, and Facility Management,’ by S.M. Al-Khadhuri, M.M. Al-Harthi, and A. Alkalbani, Petroleum Development Oman, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. A carbonate field developed by Petroleum Development Oman is one of the largest fields in the Sultanate of Oman and has been running for more than 4 decades. An integrated wells, reservoir, and facility management approach has been implemented to create more focus and discipline with the aim of achieving an efficiently monitored and controlled asset and highly synchronized multiteam actions. Introduction The field is located in the north of the Sultanate of Oman, and it is one of Oman’s largest fields. The reservoir layers dip uniformly at 15° to the northeast (Fig. 1). The field is a highly complex carbonate reservoir of the Natih formation and is subdivided into seven units, Natih A through Natih G, and the Shuabia reservoir. It has been running since 1967 and continues to contribute significantly. The development strategy began with natural depletion with vertical wells and followed with two mechanisms, gas/oil gravity drainage (GOGD) and waterflood. The GOGD process concentrates more on fractured reservoir rock, while the waterflood process targets the layers with a relatively low degree of fracturing. The GOGD development consists of five crestal gas-injection wells and rows of down-flank producers that tap oil from a fractured oil rim. The reservoir pressure is managed by gas injection. The gas-injection rates are set to replace voidage and to maintain reservoir pressure. For the matrix wells, the reservoir pressure is managed by waterflood (water injection). This combination of different drive mechanisms in a highly fractured reservoir that yields to interference and gas/water short-circuiting makes the management of the field very challenging. To overcome these challenges, an integrated well, reservoir, and facility management strategy has been established in a way that ensures integration with multiple disciplines and uses many tools. As a result, an improvement in production has been seen that reflects successful implementation of the strategy. Wells and Reservoir Reviews Wells are reviewed on a yearly basis in order to have a systematic approach for reviewing wells. Approximately 26 sectors (more than 450 wells) from different reservoirs have been reviewed collaboratively. Multidisciplinary involvement from the well and reservoir management (WRM) team, the development and planning (DP) team, and the new oil (NO) team, and alignment to mature identified activities, played a crucial role in effectively sharing ideas and lessons learned and implementing activities.

Technology Focus: Water Management (December 2013)

Technology Focus Produced water is an inextricable part of the oil- and gas-recovery process, and it is by far the largest-volume waste stream associated with oil and gas recovery. More than 20 billion bbl of water is produced each year in the United States, and more than 90 billion bbl of water is produced annually worldwide. The management of these large volumes of water is an increasing challenge for the oil and gas industry, not only from a technical and economical point of view but also for all environmental issues related to its management. A substantial part of these volumes is directly reinjected into hydrocarbon reservoirs to maintain reservoir pressure and to displace oil to producing wells. The remaining water is treated for disposal or reuse, which includes injection for enhanced oil recovery and fracture stimulation. Produced-water handling and treatment represents an estimated USD 18 billion cost to the US oil and gas industry. It is estimated that each 1% reduction in water production in the US would save USD 50 million to 100 million. The treatment of produced water can be challenging because of variability in both quality and quantity of the produced-water stream. The quantity of produced water varies significantly over the lifetime of a field. Early on, the water-production rate can be a small fraction of the hydrocarbon-production rate, but it can increase with time to tens of times the rate of hydrocarbon produced. In terms of composition, the changes are complex and reservoir-specific because they are a function of the formation lithology, the oil and water (both in-situ and injected) chemistry, rock/fluid interactions, production type, and required additives for oil-production-related activities. Many different types of technologies are available to treat produced water; however, the types of constituents removed by each technology and the degree of removal must be considered to identify potential treatment technologies for a given application. For some types of produced water, more than one type of treatment technology may be capable of meeting the contaminant-removal target, and a set of selection criteria must be established to narrow down multiple treatment options. The papers featured this month deal with produced-water-treating systems, produced-water-reinjection design, and water management. I hope you enjoy reading the selected papers and will search for additional papers in the OnePetro online library. Recommended additional reading at OnePetro: www.onepetro.org. OTC 24199 Water Management for EOR Applications—Sourcing, Treating, Reuse, and Recycle by Lisa Henthorne, Water Standard, et al. SPE 165356 Water Management in Mature Oil Fields Using Preformed Particle Gels by Ali Goudarzi, The University of Texas at Austin, et al. SPE 165693 Maximizing Flowback Reuse and Reducing Freshwater Demand: Case Studies From the Challenging Marcellus Shale by Kushal Seth, Baker Hughes, et al. SPE 163803 Aeration and Microfiltration for Solids Removal of Produced Water From the Barnett Shale by Tor H. Palmgren, M-I Swaco, et al.

A new solvent-based enhanced heavy oil recovery method: Cyclic production with continuous solvent injection

This paper presents a new enhanced heavy oil recovery (EHOR) process, Cyclic Production with Continuous Solvent Injection (CPCSI). In this process, a vapourized solvent near its dew point is continuously injected into the reservoir to maintain reservoir pressure and also supply extra gas drive to flush the diluted oil out through an injector that is located on the top of the reservoir; while a producer, which is located at the bottom of the reservoir, is operated in a shut-in/open cyclic way. A series of experiments have been conducted to evaluate the CPCSI performance. The recovery factors (RFs) are up to 85% of original oil in place (OOIP) in 1-D tests, and the RF is improved by 11% by using the 2-D lateral CPCSI, compared with the traditional 2-D lateral VAPEX. Well configurations and the producer shut-in/open scenarios are key optimization factors that affect the CPCSI performance. Experimental results show that the foamy oil flow and solvent trap are the two major EHOR mechanisms for enhancing the oil production rate during the production period. In comparison with continuous injection process, such as vapour extraction (VAPEX), and cyclic injection process, such as cyclic solvent injection (CSI), CPCSI offers free gas driving, and the reservoir pressure is maintained during the producer opening period so that the diluted oil viscosity is kept low. This work shows that CPCSI could be an alternative optimization production scenario for applying solvent based in situ EHOR techniques for heavy oil reservoirs in Western Canada.

Reservoir Sensitivity Analysis of L Oilfield

L Oilfield construct as a whole for a wide and gentle anticline, the constructor East steep west slow in constructing the eastern part of the main part of the fault development of the western fault is relatively small, types of traps are faulted anticlines. Type of reservoir rock, siltstone and fine sandstone, sandstone and conglomerate, fine-grained sandstone and siltstone; deposition rhythm is rhythm, including a counter-rhythm, uniform rhythm; Cretaceous reservoir deposition mainly delta plain distributaries channel, the deposition of the Jurassic reservoir delta front, subaqueous distributaries channel and mouth bar; cretaceous reservoir average porosity of 19.3%, average permeability of 30 × 10 - 3μm2, in holes, low permeability reservoir sand body has a more serious layer, flat heterogeneity; Jurassic reservoir average porosity 26%, average permeability of 323 × 10-3μm2 to belong to the hole. in permeability reservoir. Water injection to maintain reservoir pressure development, research to determine the reservoir formation pressure to maintain the level of 0.83 times the original pressure, the initial development technology boundaries with more than 1.2 compensates water injection system pressure of 35MPa.

A Method to Determine the Optimal Water Injection Intensity Based on Oil Production Rate and Water Cut

Water injection is one of the important ways to maintain reservoir pressure and improving the oilfield development effect. And separate zone water injection is the main technology in water flooding oilfield. The optimal water intensity which has been allocated plays an important role in all kinds of reservoir. This paper proposed a method to optimize the water injection intensity based on oil production rate and water cut. Conceptual model was constructed on the basis of real reservoir. By numerical simulation, a chart board was derived which describes the relationship of water injection intensity versus oil production rate and water cut. Using this chart, we can determine the optimal water injection intensity on different oil production rate and water cut.