Jia, Ying (Petroleum Exploration and Production Research Institute, SINOPEC) | Shi, Yunqing (Petroleum Exploration and Production Research Institute, SINOPEC) | Huang, Lei (Research Institute of Petroleum Exploration and Development, Petrochina) | Yan, Jin (Petroleum Exploration and Production Research Institute, SINOPEC) | Sun, Lei (SouthWest Petroleum University)
The YKL condensate gas reservoir is one of the biggest condensate gas reservoirs in China and has been developed more than 10years. At present, the combination of subdivision layer, production speed optimization and horizontal well drilling has been the key to economically unlocking the vast reserves of the YKL condensate gas. The primary recovery factor, however, remains rather low due to high capillary trapping and water invasion. While primary depletion could result in low gas recovery, CO2 flooding provides a promising option for increasing the recovery factor.
The objective of this work is to verify and evaluate the effect supercritical CO2 on enhancing gas recovery and analyze the feasibility of CO2 enhance gas recovery (CO2 EGR) of condensate gas reservoir.
Firstly, novel phase behavior experimental procedures and phase equilibrium evaluation methodology for gas-condensate phase system mixed with supercritical CO2 with high temperature were presented. A unique phase behavior phenomena was also reported. Then, CO2 floodingmechanism in condensate gas reservoir was analyzed and clarified based on experiments. Finally, a series of numerical simulation work were conducted as an effective and economical means to maximize natural gas recovery with the lowest CO2 breakthrough by varying strategies, including CO2 injection rate, injection composition, andinjection timing. Meanwhile the CO2 storage volumes of different strategies were calculated.
The results show that higher gas recovery factor can be achieved with CO2 injection through appearing interphase between two fluids, maintaining reservoir pressure, driving gas like "cushion" and controlling water invasion. All strategies have moderate to significant effects on gas production. The control of injection and production ratio needs to be balanced between pressure transient and CO2 breakthrough over the producer to obtain the maximum gas production. The varying injection pressure shows a positive effect of enhancing gas production. Numerical simulation indicated that the recovery of gas reservoir was improved by around 10 percent. The total CO2 storage would be around 30-40% HCPV.
The research showed that CO2 flooding presents a technically promising method for recovering the vast condensate gas while extensively reducing greenhouse gas emissions.
Xiang, Wentao (China National Offshore Oil Corp.) | Zhou, Wei (China National Offshore Oil Corp.) | Zhang, Jian (China National Offshore Oil Corp.) | Yang, Guang (China National Offshore Oil Corp.) | Jiang, Wei (Southwest Petroleum Inst.) | Sun, Lei (Southwest Petroleum Inst.) | Li, Jian
In South China Sea, the geological reserve of CO2 is huge. With the unanimous agreement of a series of problems caused by CO2 emissions, as an effective method to consume CO2, CO2 injection for enhanced oil recovery (EOR) has been investigated and reported by many researchers.
An extensive review of previous reported CO2-EOR projects is provided in this paper. According to exploring and analyzing the factors influencing CO2-EOR, and combined with the specialty of offshore conditions, reservoir evaluation of China offshore CO2-EOR is suggested in this paper. Based on the evaluation suggestion, the Chinese offshore oilfields were screened and the South China offshore oilfield close to CO2 reserve was conformable. This paper also describes the feasibility of CO2-EOR in the South China offshore oilfield from fundamental studies. The relationship of reservoir oil and CO2 showed that reservoir oil had good dissolving capacity to CO2. CO2 could effectively dissolve in and displace residual oil. The experimental results show that under reservoir conditions, CO2 could be in the one-contact miscible at 20 MPa, a slight higher than the formation pressure of 17.27 MPa. CO2 and oil could be in near miscible under formation conditions. The lab research work funded a further investigation on application of CO2-EOR in China offshore oilfield.
Based on high pressure physical property experiments, such as swelling experiment, multi-contact experiment and asphaltene precipitation experiment et al, thermodynamic characteristics of asphaltene precipitation during CO2 injection have been analyzed comprehensively with numerical simulation, which make up the deficiency of analyzing physical and chemical parameters with experiments; adsorption and plugging of asphaltene on rocks and rheology characteristic of oil containing precipitated asphaltene have been studied; the influence of asphaltene deposition on reservoir have been researched; Found on above-mentioned study, the mathematic flow model considering asphaltene deposition has been established. Take one oil field in our country as example, the influence of asphaltene deposition on production dynamics during CO2 injection has been researched. The results were in agreement with field observation and history data, which can be efficient for the further production prediction.
Gas injection, especially CO2 injection, is regarded as one of the most efficient methods of oil development because CO2 can obviously enhance oil recovery by decreasing viscosity of crude oil, reducing interfacial tension, and swelling oil. However, CO2 injection, steam injection and N2 injection etc. may cause asphaltene deposit, which seriously influences production. Oil production indicates that gas injection can easily trigger heavy organic matters deposit, which can result in plugging of the formation, wellbore and production facilities. Many domestic and oversea oil fields have reported this phenomenon. Thus, it is necessary to propose a predictive model to describe asphaltene physical chemisty property, exactly predict asphaltene precipitation and quantify the influence of asphaltene deposition on oil development.
In this paper, through the investigation of comprehensive literatures, first of all, multiphase equilibrium thermodynamic model for asphaltic oil gas system is proposed based on the theory of fluid thermodynamics; and then, taken example for some case reservoir fluid in China, asphaltene precipitation values are calculated, and the variation trends of thermodynamic parameters of alphaltene with injected CO2 are analyzed; Next, based on the phase behavior characteristic research of asphaltic oil, compositional model considering asphaltene deposition, adsorption, plugging and non-Newton characteristic under low pressure gradient during gas injection is proposed; Subsequently, long core flooding experiment is simulated in order to discuss dynamic characteristic of asphaltene deposition, distribution rules of asphaltene deposition and adsorption, and receptance factors of asphaltene deposition. Finally, single injection and single production model is constructed to research the influence of oil rheological property and asphaltene deposition and adsorption on oil recovery.
Multiplashe Equilibrium Research on Asphatic Oil System during CO2 Injection
Organic solid precipitation during gas injection is complicated physical chemistry process induced by phase transition in oil and gas system. However, even though a lot of experiments and theory researches have been conducted since the sixties of the twentieth century, the true mechanism of asphaltene precipitation in oil system is not explored clearly.
Especially, during CO2 injection, phase behavior characteristic is very intricate. The contact of injected CO2 and formation oil may induce multiple phase coexistence. However, only equipments with very high precision can distinguish multiple phase characteristic such as two liquid phases. In addition, because precipitated asphaltene is black or dark brown and opaque, which is not be clearly identified with the interphase between asphaltene and oil, the equipments can not accurately determine asphaltene precipitation onset point and asphaltene precipitation quantity.
Thus, it is necessary to propose multiphase equilibrium thermodynamic model for asphaltic oil and CO2 system to research on the asphaltene precipitation. With this model, thermodynamic characteristics of asphaltene precipitation during CO2 injection can be analyzed comprehensively, which may make up the deficiency of analyzing physical and chemical parameters with experiments.
Guo, Xiao (Southwest Petroleum Inst.) | Du, Zhimin (Southwest Petroleum Inst.) | Sun, Lei (Southwest Petroleum Inst.) | Huang, Wanxia (PetroChina Jinlin Oilfield Company) | Zhang, Cai (PetroChina Southwest Oil & Gasfield Company)
Most of the low permeability oil reservoirs in Jilin oil field of China have reached their economic limit of production by waterflooding and even many wells have been abandoned due to low productivity. Interest in recovery enhanced technology of tertiary miscible or immiscible CO2 flooding is increasing in these low permeable reservoirs. In this paper, a laboratory study using a high-pressure PVT cell and a simulation study using full-field fully equation-of-state (EOS) compositional reservoir modeling were undertaken to optimize the design of a miscible or immiscible CO2 flood pilot project for the Xinli Unit in Jilin oil field. The laboratory study includes phase behavior analysis, asphaltene deposition assessment, and minimum miscibility pressure (MMP) determination in the CO2 corefloods. Based on building a full-field 3D geologic model and history matching waterflood performance, a preliminary CO2 flood reservoir modeling has been used to distinguish displacement mechanisms and reservoir performance of natural depletion, continued waterflooding, continuous CO2 and water-alternate-CO2. The simulation study and the pilot test showed water-alternate-CO2 after waterflooding is an effective method of improved oil recovery for the low permeability reservoir and it can appreciably reduce water production and enhance oil recovery. Simulation studies has also been completed to determine an optimal water-CO2 ratio, optimal CO2 slugs and optimal CO2 injection rate. The pilot operation is now well implementing according to above-mentioned study achievements. Future plans for water-alternate-CO2 optimization include continuation of performance monitoring to help optimize tapering strategy in order to enhance further oil recovery in the low permeability oil reservoir.
Guo, Xiao (Southwest Petroleum Inst.) | Du, Zhimin (Southwest Petroleum Inst.) | Jiang, Yiwei (Zhongyuan Oilfield) | Sun, Lei (Southwest Petroleum Inst.) | Bi, Jianxia (Zhongyuan Oilfield) | Liu, Xueli (Southwest Petroleum Inst.)
The development of complex, deep gas condensate fields with oil ring was once a difficult and uneconomical task to perform. The optimization of conceptual design has now become cost efficient through the use of integrated simulation. This presentation focuses on the integrated study of Qiaokou oil-rim gas condensate field , located in Zhongyuan oil field. The reservoir is of low permeability, low porosity, deep pay and has three fault-isolated produced zones, named Qiao14, Qiao69 and Qiao58 blocks. In 2002, 28 infills were drilled on the basis of adding incremental reservoirs. With the advent of widely available high-accuracy reservoir predicting technology, under-balanced drilling technology and large-scale fracturing technology in Zhongyuan oil field, encouraging factors and results led to a desire to further field-scale development plans. An detailed integrated study of Qiaokou oil-rim gas condensate reservoirs was proposed.
This study involved building a highly detailed earth model to accurately define the geologic framework, and a scaled-up simulation model to optimize the field demonstration project. Based on well log, geologic, and core data, individual-layer data and the faulted structure were mapped. Reservoir behavior of oil-rim gas condensate reservoir is modeled using a 3-D reservoir simulator. The model incorporates a description of the phase behavior of gas and oil rim, well stimulation and compaction in the reservoirs.
The multi-disciplinary demonstration of reservoir evaluation, gas engineering, PVT analysis, numerical simulation, gas production practice, fracture acidizing on Qiaokou oil-rim gas condensate reservoirs has been accomplished by earth scientists, field engineers, and reservoir engineers. An integrated simulation incorporating the demonstrated results of these engineers has been presented to make decisions in Qiaokou oil-rim gas condensate field development.
The study showed the integrated numerical modeling of Qiaokou oil-rim gas condensate reservoirs can be cost effective and SINOPEC has already ratified the further development plan in light of the results of this study. Our conclusions and recommendations will help improve future management and development of Qiaokou oil-rim gas condensate field.
Mei, Haiyan (University of Science and Technology of China) | Kong, Xiangyan (University of Science and Technology of China) | Zhang, Maolin (University of Science and Technology of China) | Sun, Lei (Southwest Petroleum Institute, China) | Li, Shilun (Southwest Petroleum Institute, China) | Sun, Liangtian (Southwest Petroleum Institute, China)
A gas and oil system contains a certain amount of heavy organic substances, such as wax, resin and asphaltene which precipitate as a solid phase, causing serious problems to production for oil and gas fields, when thermodynamic conditions are changed.
In this paper, a thermodynamic model of the gas-liquid-solid three-phase equilibrium for an oil and gas hydrocarbon system is presented, based on the regular solution theory, an equation of state and the phase equilibrium principle of fluid thermodynamics. A flash calculation model for the gas, liquid and solid three phases is developed, being combined with a material conservative equation. An equation of state is used to describe both gas and liquid phases, and a regular solution theory is only used to account for the non-ideality of the solid mixture, which can reflect the effects of temperature, pressure and composition of system on solid precipitation. The influence of the heat capacity difference between the liquid and the solid on the solid precipitation is taken into consideration. Some adjustable parameters and a tuning function are introduced in this model because of uncertainty of heavy component properties. It is shown that the model has a good convergency and stability, and the calculated values by this model are in good agreement with the experimental data.
The condensate-gas mixture flowing process takes place in the porous media of deep strata. Owing to their giant specific area, the porous media are of a relatively strong adsorption capacity and the fluid exists as two states, i.e. adsorption state and free state. According to the basic theories of multiphase flow and the acting mechanisms of porous medium adsorption, a research approach of percolation law which contains the effect of the mixed gas, which is adsorbed on the surface of porous media under formation conditions, is proposed. A corresponding mathematical model is set up too. Through an example calculation, the effect of porous medium adsorption on percolation law is analyzed. It is concluded that the effect of porous medium adsorption on the flowing process of condensate-gas mixture is of objective reality and can't be neglected.