Khamees, Tariq K. (Missouri University of Science & Technology) | Flori, Ralph E. (Missouri University of Science & Technology) | Alsubaih, Ahmed A. (Basra Oil Company) | Alhuraishawy, Ali K. (Missan Oil Company)
In-depth gel treatment is a chemical EOR process used to improve the sweep efficiency from heterogeneous reservoirs with crossflow. However, if these reservoirs are saturated with viscous oil, polymer and surfactant flooding should be combined with in-depth gel treatment. Thus, in this study, a 3D model using the UTGEL simulator was built to model in-depth gel treatment combined with surfactant slug and polymer solution. The model was represented by one quarter of the five-spot pattern with eight layers where two thief zones are located in the middle of the model. The thief zones had a permeability of 1500 md with a total thickness of 20 ft, while the rest of the layers had a permeability of 100 md with a total thickness of 200 ft.
The gel system consisted of a polyacrylamide/Cr(VI)/thiourea solution, which is considered an in-situ gelation system. Gelant solution was injected for 60 days when the water cut in the model reached 65%, followed by surfactant slug for 2 years, polymer solution for 3 years, and then post-water injection for the rest of the simulation time. The concentrations of the surfactant ranged from 0.01 to 0.2 wt.%, while the polymer concentration was 1,000 ppm. The injection rate was 1,070 bbl/day during all flooding and treatment processes.
The results showed that it is imperative to implement surfactant with gel treatment to reduce the interfacial tension between water and oil phases and to alter the wettability of the reservoir rocks. Thus, gel treatment alone or gel followed by polymer was not as efficient as the injection of a surfactant slug. The results also showed that as the reservoir temperature increased, the overall performance of gel, polymer, and surfactant decreased. Therefore, the higher the temperature, the lower the recovery factor. The results also revealed the importance of viscoelastic behavior of the HPAM polymer solution where higher results for both water-wet and oil-wet conditions were obtained compared to shear-thinning behavior only. Moreover, the results revealed interesting behavior regarding the concentration of the surfactant, where the recovery factor increased as the concentration of the surfactant increased in oil-wet conditions. However, in water-wet conditions, the results were unpromising and unfavorable. Furthermore, the injection of surfactant directly after the gel treatment was more effective in improving the sweep efficiency than the injection of polymer directly after the gel treatment. Finally, as the salinity of makeup water and/or reservoir brine increased, the recovery factor decreased for both water and oil-wet systems. This is because, as salinity increased, the adsorption of both polymer and surfactant increased and the polymer viscosity decreased. Furthermore, the presence of divalent cations such as Ca+2 and Mg+2, would have a negative impact on overall treatment.
The presence of oxygen and carbon dioxide in the injection and production streams of any high-pressure-air-injection (HPAI) project or the high oxygen partial pressures associated with enriched-air-/oxygen-injection projects may create serious safety concerns such as the potential for explosion or corrosion. Compilation of field problems and reported solutions from such projects indicate that no insurmountable problems exist in the implementation of HPAI projects. Generally, the operators have implemented safe operations successfully when injecting at pressures as high as 6,000 psi. The long-term successes of the HPAI projects in the Williston basin, which were initiated in 1978 by Koch Industries and continue to be operated today by Continental Resources, have confirmed that HPAI is a viable and safe process for recovering light oils.
A number of oilfield oxygen-injection projects have also been undertaken since the early 1980s, when Greenwich Oil operated the first oxygen-injection project at Forest Hills, Texas. In Canada during the 1980s, oxygen was injected by BP/AOSTRA at Marguerite Lake, by Dome Petroleum at Lindberg, by Husky Energy at Golden Lake, by Mobil Oil at Fosterton, and by Gulf Canada at Pelican. In the US, oxygen-injection pilots were operated by Arco in the Holt Sand Unit (HSU), Texas, and more recently by NiMin Energy at Pleito Creek, California.
With increased oxygen partial pressure, there is a greater chance of safety or corrosion problems. In fact, the high oxygen content associated with the HSU project in west Texas caused a severe energy release that resulted in test termination. The reported data on this field are scarce, and the nature of the energy release has not been discussed in detail.
This paper will first review the operational aspects of some key air-injection field tests. Then, some important details on the HSU oxygen-injection pilot test will be discussed as a case study. The reasons behind the energy release in the HSU project will be discussed by use of the surveillance data, as well as combustion-tube-test and numerical-modeling results. Finally, best practices for future operation of HPAI tests will be reviewed. This paper is intended to provide a better understanding of the safety aspects of air/oxygen handling and proper practices in such operations.
Ezekiel, Justin (China University of Petroleum) | Wang, Yuting (China University of Petroleum) | Liu, Yanmin (China University of Petroleum) | Zhang, Liang (China University of Petroleum) | Deng, Junyu (China University of Petroleum) | Ren, Shaoran (China University of Petroleum)
This paper provides a comprehensive overview on the oxidation reactions and improved oil recovery (IOR) processes of air injection into low permeability light oil reservoir based on detailed analysis of some field projects and reservoir simulation case study carried out on a largely dipping, low permeability light oil reservoir, the Q131 oil block located in Eastern China to analyze the characteristics and processes of air injection. Kinetic models of low temperature oxidation (LTO) reactions were designed and used in the reservoir simulation study to predict oxygen consumption in the reservoir, examine the reaction schemes, IOR mechanisms, and the thermal effect of oxidation reactions occurring during the air injection process. The results of the study including temperature effects, oxygen concentration, oil saturation, gas breakthrough, GOR, and cumulative oil produced were outlined and discussed in details.
Evseeva, Margarita (Gazpromneft NTC) | Ushakova, A. S. (Salym Petroleum Development) | Volokitin, Y. E. (Salym Petroleum Development) | Brusilovsky, A. I. (Gazpromneft NTC) | Shaymardanov, M. M. (Gazpromneft NTC)
Presently, the problem of enhancing the efficiency of the oil recovery becomes of the high priority. The procedure described in this paper is the analytical basis for accetability appraisal of the high pressure air injection (HPAI) on the light oil fields for enhancing the oil recovery.
The objective of this paper is the physical basis of the HPAI method, i.e. the air injection into a light oil bearing formation and the in-situ oil oxidation under high temperatureres with production of combustion gases - carbon mono- and dioxides, hydrocarboneous gases.
For evaluation of the technological parameters and the applicability of the HPAI method on the West-Salymskoe oil field of the Salym Petroleum Development Company the results of experimental studies of oil properties, the efficiency of the oil displacement by the injected and the combustion gases and the oxidation kinetics were analysed. The phase behavior of the oil and gases under high temperature conditions was modeled using the developed PVT model based on the equation of state. The experimental results of the linear oil displacement by gaseous agents on the core (lab) scale were simulated. The relative permeabilities have been obtained as saturation functions. The kinetics of oil oxidation reactions obtained by calorithmetic experimenta on the light oil on core was also simulated on the linear models. The developed linear models are the basis for the transition to the 3D modeling of the HPAI method.
Introduction, the Physical Basis
The air injection into a light oil bearing formation with high reservoir temperature (HPAI) is a relatively well studied EOR method. It is applied as the secondary oil recovery method after the natural drive regime mainly in the carbonate low permeable oil wetting well stratified rocks, where the water flooding for some reasons is inefficient [1-5], as well as the ternary recovery method for highly watered deposits [6,7]. There are a number of successful applications of the in-situ combustion in the light oil bearing formations described in the literature.
The first large project of the air injection into the light oil formation has been realized at the Sloss oil field . One of the largest oil fields, where the HPAI technology is applied, is located in the South Dakota, USA [1-5, 9-10]. In 2001-2003 seven neighbouring oil fields with similar geological-physical characteristics were brought into development with application of the air injection (Medicine Pole Hill, South Medicine Pole Hill et al.) .
Jia, Hu (Southwest Petroleum University) | Yuan, Cheng-dong (Southwest Petroleum University) | Zhang, Yuchuan (Southwest Petroleum University) | Peng, Huan (Southwest Petroleum University) | Zhong, Dong (Southwest Petroleum University) | Zhao, Jinzhou (Southwest Petroleum University)
High-Pressure Air Injection (HPAI) in light oil reservoirs has been proven to be a valuable IOR (Improved Oil Recovery) process and caused more attention worldwide. In this paper, we give an overview of the recent progress of HPAI technique, based on a review of some representative HPAI projects including completed and ongoing projects. Some most important aspects for HPAI field application are discussed in depth, including reservoir screening criterion, recognition of recovery mechanism, laboratory study, numerical simulation, gas breakthrough control, tubing corrosion consideration and safety monitoring. With the successful HPAI application in Zhong Yuan Oil Field in China, it is estimated that foam or polymer gel assisted air injection should continue to grow in the next decade as a derived technology of HPAI for application in high-temperature high-heterogeneity reservoirs. The purpose of this paper is to investigate the ranges of some key parameters, new understanding based on laboratory test and successful field application, thus to provide lessons learnt and best practices for the guideline to achieve high-performance HPAI project.
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the Eighteenth SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 14-18 April 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract In oil producing regions like the US Mid-Continent, there are a large number of mature conventional oil fields that have reached or are approaching their production limit by conventional techniques, however, current strong oil prices and security issues justify additional EOR/IOR efforts. Air injection-based techniques (fireflooding or in situ combustion) have been demonstrated to provide commercially successful recovery from medium and light oils reservoirs. While the history of air injection-based EOR is littered with the perception of failed projects, many of the failures were associated with low oil prices. In other cases, failures were due to compressor problems, or incorrect concepts of how air injection processes operate. Ineffective ignitions, failure to inject enough air, and applications in reservoirs that had no hope of success explain the trouble with many past projects. This paper reviews some of the successful air injection projects in higher gravity oil reservoirs and discusses the elements that are critical for success.
The heat may be supplied externally by injecting a hot fluid such as steam or hot water into the formations, or it may be generated internally by combustion. In combustion, the fuel is supplied by the oil in place and the oxidant is injected into the formations in the form of air or other oxygen-containing fluids. In principle, any hot fluid can be injected into the formations to supply the heat. The fluids used most extensively are steam or hot water because of the general availability and abundance of water. Hot water injection has been found to be less efficient than steam injection and will not be discussed here.
Hou, Shengming (China U. of Petroleum East) | Ren, Shaoran (China U. of Petroleum Beijing) | Wang, Wei (China U. of Petroleum) | Niu, baolun (SINOPEC) | Yu, Hongmin (Xinjiang Oilfield Company) | Qian, Genbao (Xinjiang Petr. Admin. Bureau) | Gu, Hongjun (Xinjiang Oilfield Company) | Liu, Baozhen
XinJiang oilfield is located in the Northwest of China, in which large oil reserves have been discovered in reservoirs with very low permeability (<14×10-3µm2). These reservoirs are featured with light oil in moderate depth, high reservoir pressure, but relatively low reservoir temperature (65~78oC) and low oil viscosity (<10mPa•s). Primary production and limited water flooding experience have shown that the recovery factor in these reservoirs is very low due to lack of reservoir energy and poor water injectivity. Gas injection has been optioned as an alternative secondary or tertiary technique to maintain reservoir pressure and/or increase sweeping and displacement efficiency. In this study, the feasibility of air injection via a low temperature oxidation (LTO) process has been studied. Laboratory experiments were focused on LTO characteristics of oil samples at low temperature range and core flooding using air at various reservoir conditions. Reservoir simulation studies were conducted in order to predict the reservoir performance under the air injection scheme and to optimize the operational parameters. The oxygen consumption rates at reservoir temperature and IOR potentials at different reservoir conditions were assessed for a number of selected reservoirs in the region. A pilot project has been designed based on experimental data, reservoir simulation results and field experience of air injection gained in other regions of China. Issues related to safety and corrosion control during air injection and the project economics were also addressed in the paper.
High Pressure Air Injection (HPAI) is a potentially attractive enhanced recovery method for deep, high-pressure light oil reservoirs. The clear advantage of air over other injectants, like hydrocarbon gas, carbon dioxide, nitrogen, or flue gas is its availability at any location. Although, the process has successfully been applied in the Williston Basin for more than two decades, the potential risks associated with the presence of oxygen in air are a significant hurdle for implementation in other locations.
Thermal simulations that include combustion are required to quantify the incremental oil, the oxygen consumption and resulting oxygen distribution from the application of HPAI in a given field. Once such a simulation model is available, it can be used to optimize the injection strategy: strategies that have a good incremental recovery while reducing the amount of gas injected are key to a successful project. The injection rate is bounded by a technical lower limit and an economic upper limit: there is a minimum rate required to maintain the combustion and high rates require larger compressors that are more expensive.
This paper focuses on the optimization of the injection strategy for HPAI in a 3D model with realistic geological features. Numerical simulations with a thermal model that includes combustion were conducted for continuous versus alternating air injection. A critical assumption for alternating air injection in that the remaining oil spontaneously re-ignites.
This study shows that water alternating air injection has a great potential to improve HPAI projects: project life can be extended and incremental recovery is improved when compared with continuous air injection. In addition, the variation in distribution of oxygen between different cycles is presented. This also illustrates that the numerical model can be used as an oxygen management tool. The effects of alternating air injection are comparable to the effects of alternating gas injection: the saturation in the swept areas changes due to the alternating (re-) invasion of gas, oil and water.
This paper illustrates that modeling oxygen consumption is essential for the evaluation of potential risks and optimization of the HPAI process.