Underlined names are links to current or past GEG members
REFEREED PUBLICATIONS IN JOURNALS
Ezekiel, J., B.M. Adams, M.O. Saar, and A. Ebigbo, Numerical analysis and optimization of the performance of CO2-Plume Geothermal (CPG) production wells and implications for electric power generation, Geothermics, 98/102270, 2022. [Download PDF] [View Abstract]CO2-Plume Geothermal (CPG) power plants can produce heat and/or electric power. One of the most important parameters for the design of a CPG system is the CO2 mass flowrate. Firstly, the flowrate determines the power generated. Secondly, the flowrate has a significant effect on the fluid pressure drawdown in the geologic reservoir at the production well inlet. This pressure drawdown is important because it can lead to water flow in the reservoir towards and into the borehole. Thirdly, the CO2 flowrate directly affects the two-phase (CO2 and water) flow regime within the production well. An annular flow regime, dominated by the flow of the CO2 phase in the well, is favorable to increase CPG efficiency. Thus, flowrate optimizations of CPG systems need to honor all of the above processes. We investigate the effects of various operational parameters (maximum flowrate, ad- missible reservoir-pressure drawdown, borehole diameter) and reservoir parameters (permeability anisotropy and relative permeability curves) on the CO2 and water flow regime in the production well and on the power generation of a CPG system. We use a numerical modeling approach that couples the reservoir processes with the well and power plant systems. Our results show that water accumulation in the CPG vertical production well can occur. However, with proper CPG system design, it is possible to prevent such water accumulation in the pro- duction well and to maximize CPG electric power output.
Ezekiel, J., D. Kumbhat, A. Ebigbo, B.M. Adams, and M.O. Saar, Sensitivity of Reservoir and Operational Parameters on the Energy Extraction Performance of Combined CO2-EGR–CPG Systems, Energies, 14/6122, 2021. [Download PDF] [View Abstract]There is a potential for synergy effects in utilizing CO2 for both enhanced gas recovery (EGR) and geothermal energy extraction (CO2-plume geothermal, CPG) from natural gas reservoirs. In this study, we carried out reservoir simulations using TOUGH2 to evaluate the sensitivity of natural gas recovery, pressure buildup, and geothermal power generation performance of the combined CO2-EGR–CPG system to key reservoir and operational parameters. The reservoir parameters included horizontal permeability, permeability anisotropy, reservoir temperature, and pore-size- distribution index; while the operational parameters included wellbore diameter and ambient surface temperature. Using an example of a natural gas reservoir model, we also investigated the effects of different strategies of transitioning from the CO2-EGR stage to the CPG stage on the energy-recovery performance metrics and on the two-phase fluid-flow regime in the production well. The simulation results showed that overlapping the CO2-EGR and CPG stages, and having a relatively brief period of CO2 injection, but no production (which we called the CO2-plume establishment stage) achieved the best overall energy (natural gas and geothermal) recovery performance. Permeability anisotropy and reservoir temperature were the parameters that the natural gas recovery performance of the combined system was most sensitive to. The geothermal power generation performance was most sensitive to the reservoir temperature and the production wellbore diameter. The results of this study pave the way for future CPG-based geothermal power-generation optimization studies. For a CO2-EGR–CPG project, the results can be a guide in terms of the required accuracy of the reservoir parameters during exploration and data acquisition.
Ezekiel, J., A. Ebigbo, B. M. Adams, and M. O. Saar, Combining natural gas recovery and CO2-based geothermal energy extraction for electric power generation, Applied Energy, 269/115012, 2020. [Download PDF] [View Abstract]We investigate the potential for extracting heat from produced natural gas and utilizing supercritical carbon dioxide (CO2) as a working uid for the dual purpose of enhancing gas recovery (EGR) and extracting geo- thermal energy (CO2-Plume Geothermal – CPG) from deep natural gas reservoirs for electric power generation, while ultimately storing all of the subsurface-injected CO2. Thus, the approach constitutes a CO2 capture double- utilization and storage (CCUUS) system. The synergies achieved by the above combinations include shared infrastructure and subsurface working uid. We integrate the reservoir processes with the wellbore and surface power-generation systems such that the combined system’s power output can be optimized. Using the subsurface uid ow and heat transport simulation code TOUGH2, coupled to a wellbore heat-transfer model, we set up an anticlinal natural gas reservoir model and assess the technical feasibility of the proposed system. The simulations show that the injection of CO2 for natural gas recovery and for the establishment of a CO2 plume (necessary for CPG) can be conveniently combined. During the CPG stage, following EGR, a CO2-circulation mass owrate of 110 kg/s results in a maximum net power output of 2 MWe for this initial, conceptual, small system, which is scalable. After a decade, the net power decreases when thermal breakthrough occurs at the production wells. The results con rm that the combined system can improve the gas eld’s overall energy production, enable CO2 sequestration, and extend the useful lifetime of the gas eld. Hence, deep (partially depleted) natural gas re- servoirs appear to constitute ideal sites for the deployment of not only geologic CO2 storage but also CPG.
Cui, G., S. Ren, L. Zhang, J. Ezekiel, C. Enechukwu, Y. Wang, and R. Zhang, Geothermal exploitation from hot dry rocks via recycling heat transmission fluid in a horizontal well, Energy, 128, pp. 366-377, 2017. [Download PDF] [View Abstract]A new method for geothermal exploitation from hot dry rocks by recycling heat transmission fluid in a horizontal well via a closed loop is proposed, in which the costly and complex hydro-fracturing can be avoided. In this paper, numerical simulation models were established to calculate the heat mining rate for the new technology to assess its technical and economic feasibility. Sensitivity studies were performed to analyze the effects of various parameters on heat mining rate, including the injection rate, the horizontal segment length and the thermal conductivity of the tubing. The results show that a high heat mining rate over 1.7 MW can be obtained using a 3000 m long horizontal well to extract geothermal energy from a typical hot dry rock of 235 °C with a water circulation rate of 432 m3/d. For low-temperature geothermal reservoirs, higher injection rate, longer horizontal wells and better thermal insulation of tubing can be applied to increase the heat mining rate. The cost of geothermal power generation using a single horizontal well is estimated as 0.122 $/kWh, and this could be further reduced to 0.084 $/kWh when the multi-branch horizontal well pattern was adopted, slightly lower than a fractured vertical well case.
Ezekiel, J., R. Shaoran, Z. Liang, and W. Yuting, Displacement Mechanisms of Air Injection for IOR in Low Permeability Light Oil Reservoirs, International Journal of Oil, Gas and Coal Technology, 16/1, pp. 1-26, 2017. [Download PDF] [View Abstract]Air injection into light oil reservoirs has been proven to be a valuable improved oil recovery (IOR) process and is being successfully implemented worldwide in many oilfields. It specially offers unique technical and economic opportunities for tertiary or secondary oil recovery in light oil reservoirs with low permeability in which conventional water injection techniques have been unsuccessful and/or uneconomical. This paper provides a comprehensive overview on the oxidation and IOR process of air injection into low permeability light oil reservoir based on detailed analysis of some field projects and the results of laboratory testing and reservoir simulation of a typical light oil reservoir, the Q131 Block. The reaction mechanisms of low temperature oxidation (LTO) and high temperature oxidation (HTO or in-situ combustion) are particularly addressed in this study. Air flooding displacement efficiency experiment was carried out without water injection, and an oil recovery of more than 40% of hydrocarbon pore volume (HCPV) was observed. A series of high-pressure oxidation experiments using the typical light oil were conducted in the temperature range of 98Â°C to 180Â°C. The results showed high oxidation and carbon dioxide (CO2) conversion rates, which are both favourable in terms of oxygen consumption. A conceptual full field compositional reservoir simulation model of the targeted low permeability block was also used to examine the reaction schemes, thermal effect of LTO reactions and IOR mechanisms.
Li, D., B. Ren, L. Zhang, J. Ezekiel, S. Ren, and Y. Feng, CO2-sensitive foams for mobility control and channeling blocking in enhanced WAG process, Chemical Engineering Research and Design, 102, pp. 234-243, 2015. [Download PDF] [View Abstract]Mobility control is a key issue in gas and CO2 flooding process, and water-alternating-gas (CO2) injection (WAG) has been used in various field applications. The WAG process can be CO2 foam assisted in order to further improve the sweeping efficiency of the injectants. In this study, a novel foaming method for reducing CO2 mobility and blocking gas channeling is proposed, which is based on a CO2-sensitive chemical (compound with amine group) to generate foams or thicken the injected water in situ. The CO2-sensitive chemical is referred to that, in a reaction triggered by CO2, it can be converted to an effective surfactant or foam agent. The chemical can be dissolved in water and injected as a slug. In this study, the foaming behavior and the CO2-sensitivity of the chemical were tested using a visualization apparatus and a viscometer in the presence of CO2 and N2. The capability of the foams generated using the CO2-sisentive chemical for mobility control was evaluated via gas flooding experiments of sand-packs. Stable CO2 foams have been obtained at high temperature and pressure conditions (up to 140 °C and 16 MPa), and high viscosity was observed in the chemical solution when CO2 was present in comparison with that of N2, indicating the chemical's sensitivity with dissolved CO2 in water. In the sand-pack flooding experiments, a high resistance factor was achieved in a simulated WAG process using the CO2-sensitive chemical, which is attributed to the CO2 foams and viscous micelles generated in situ during CO2 injection.
Li, M., S. Fan, Y. Su, J. Ezekiel, M. Lu, and L. Zhang, Mathematical models of the heat-water dissociation of natural gas hydrates considering a moving Stefan boundary, Energy, 90/1, pp. 202-207, 2015. [Download PDF] [View Abstract]This paper presents mathematical models for radial, quasi-steady state heat transfer in a semi-infinite hydrate reservoir with a moving boundary that is related to the dissociation of natural gas hydrates. The exact solutions of the temperature in the dissociation zone and hydrate zone, using the Paterson exponential integral function, are obtained, and the dissociation frontal brim location of the hydrates is determined by combining the Deaton method with the Clausius–Claperyron equation. A sample calculation shows that the reservoir temperature falls sharply to the dissociation temperature and then drops gradually with increasing distance to the reservoir temperature. With respect to time, the temperature increases slowly to the dissociation temperature, after which, the dissociation temperature falls sharply to the temperature close to that of the injected hot-water. By increasing the temperature of injected hot-water, more hydrates participate in dissociation; with an increase in time, the radius quickly increases, but the radius of hydrate dissociation increases slowly.
Zhang, L., D. Li, and J. Ezekiel, CO2 Geological Storage into a Lateral Aquifer of an Offshore Gas Field in the South China Sea: Storage Safety and Project Design, Frontiers of Earth Science, 2015. [Download PDF] [View Abstract]The DF1-1 gas field, located in the western South China Sea, contains a high concentration of CO2, thus there is great concern about the need to reduce the CO2 emissions. Many options have been considered in recent years to dispose of the CO2 separated from the natural gas stream on the Hainan Island. In this study, the feasibility of CO2 storage in the lateral saline aquifer of the DF1-1 gas field is assessed, including aquifer selection and geological assessment, CO2 migration and storage safety, project design, and economic analysis. Six offshore aquifers have been investigated for CO2 geological storage. The lateral aquifer of the DF1-1 gas field has been selected as the best target for CO2 injection and storage because of its proven sealing ability, and the large storage capacity of the combined aquifer and hydrocarbon reservoir geological structure. The separated CO2 will be dehydrated on the Hainan Island and transported by a long-distance subsea pipeline in supercritical or liquid state to the central platform of the DF1-1 gas field for pressure adjustment. The CO2 will then be injected into the lateral aquifer via a subsea well-head through a horizontal well. Reservoir simulations suggest that the injected CO2 will migrate slowly upwards in the aquifer without disturbing the natural gas production. The scoping economic analysis shows that the unit storage cost of the project is approximately US$26-31/ton CO2 with the subsea pipeline as the main contributor to capital expenditure (CAPEX), and the dehydration system as the main factor of operating expenditure (OPEX).
Zhang, L., J. Ezekiel, D. Li, and J. Pei, Potential Assessment of CO2 Injection for Heat Mining and Geological Storage in Geothermal Reservoirs of China, Applied Energy, 122, pp. 237-246, 2014. [Download PDF] [View Abstract]Supercritical CO2 has good mobility and certain heat capacity, which can be used as an alternative of water for heat recovery from geothermal reservoirs, meanwhile trapping most of injected CO2 underground to achieve the environmental benefits. In this paper, different types of geothermal resources are assessed to screen reservoirs suitable for heat mining and geological storage by CO2 injection, in terms of geological properties, heat characteristics, storage applicability, and development prospects, etc. Hot dry rock, deep saline aquifer, and geopressured reservoir are selected as the potential sites for this study, mainly due to their relatively positive geological conditions for CO2 circulation and storage. Reservoir simulations are conducted to analyze the heat extracting capacity and storage efficiency of CO2 in the promising geothermal reservoirs. A simple calculation method is presented to estimate the potentials of heat mining and CO2 storage in the major prospective geothermal regions of China. The preliminary assessment results show that the recoverable geothermal potential by CO2 injection in China is around 1.55 × 1021 J with hot dry rocks as the main contributor. The corresponding CO2 storage capacity is up to 3.53 × 1014 kg with the deep saline aquifers accounting for more than 50%. CO2 injection for geothermal production is a more attractive option than pure CO2 storage due to its higher economic benefits in spite of that many technological and economic issues still need to be solved in the future.
Ren, J., L. Zhang, J. Ezekiel, S. Ren, and S. Meng, Reservoir Characteristics and Productivity Analysis of Tight Sand Gas in Upper Paleozoic Ordos Basin China, Journal of Natural Gas Science and Engineering, 19, pp. 244-250, 2014. [Download PDF] [View Abstract]Abundant tight sands rich in natural gas, as a kind of unconventional energy source, have been discovered in the Ordos Basin, Central-North China, which can contribute greatly to the sustainable supply of natural gas in China. In this paper, the geological and petrophysical characteristics of a typical tight sand gas reservoir in the Upper Paleozoic of the Ordos Basin were investigated and correlated to the productivity of gas wells. Several important petrophysical relationships were revealed based on data from drill cuttings, core, and well logging, including porosity versus permeability, stress sensitivity to permeability, and rock density versus porosity. Their effects on well's productivity were discussed. The productivity of the targeted reservoir was analyzed and classified using a formation capacity method (K·H factor), and was compared with the production data of similar tight sand and low permeability blocks in the region, which can provide good reference for the field development.
[back to Top of Page]
Ezekiel, J., Y. Wang, and Y. Liu, Case Study of Air Injection IOR Process for a Low Permeability Light Oil Reservoir in Eastern China, Proc. of the SPE Annual Caspian Technical Conference and Exhibition Astana, Kazakhstan, 12-14 November 2014, Proceeding SPE Annual Caspian Technical Conference and Exhibition, 2014. [Download PDF] [View Abstract] Air Injection into oil reservoirs specially offers unique technical and economic opportunities for secondary and/or tertiary oil recovery in light oil reservoirs with low permeability, in which conventional water injection techniques have been unsuccessful and/or uneconomical. 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. An average of increased oil recovery factor of more than 45% OOIP was achieved when using a maximum of 60000m3/day air injection rate and no oxygen breakthrough was observed at the production wells.
[back to Top of Page]
Ezekiel, J.C., Screening of Gas Injection Techniques for IOR in Low Permeability Reservoirs: Case Study of Q131 block in Liaohe, MSc Thesis, China University of Petroleum, 177 pp., 2014. [View Abstract]The targeted oil reservoir (Q131 block) is in Liaohe oilfield, Northeast of China, which is featured with light oil, very low permeability and sensitive to formation water, but with thick oil layers and large dip angle. The original reservoir pressure is of 33.4 MPa, reservoir temperature of 98-112 °C, and the OOIP is 2.53x106 m3. The viscosity of crude at reservoir condition is of 0.5mPa.s. Low primary production and failed water flooding experience have shown that the sweep efficiency and hence oil recovery factor in the block is very low due to lack of reservoir energy and poor water injectivity as a result of the low permeability and high heterogeneity of the reservoir block. Gravity Stabilized gas injection method has been optioned as an alternative tertiary improved oil recovery (IOR) technique to increase and/or maintain reservoir pressure, increase sweeping and displacement efficiencies to improve oil recovery. For this purpose, three different gas injection techniques, namely Air injection, Carbon dioxide (CO2) injection and Nitrogen (N2) injection are carefully selected in this study to be investigated and screened, as possible IOR methods for application in the low permeable Q131 light oil block. Real-time field data from this oil block were reviewed and summarized to evaluate feasibility of gas injection IOR technologies. The feasibility study of using these 3 gas injection methods for IOR was combined with literature review, theoretical analysis, knowledge of mechanisms of gas injection techniques, field application experiences, laboratory experimental studies, PVT analysis, history matching of the field’s production data, building a generic reservoir static model and reservoir numerical simulation of the 3 different gas injection techniques using the compositional CMG-STARS simulation software. Further work is carried out on screening the corresponding effects of the injected gases on increasing reservoir pressure, improving oil recovery, project economics, and their associated potential safety, corrosion and risk factors For the air injection process, kinetic models of low temperature oxidation (LTO) reactions for the air injection process were designed through laboratory experiments and used in the reservoir simulation study. The displacement experiments of air flooding indicate that air injection can achieve iii relatively higher oil recovery than water injection in the block and the oil recovery increased proportionally with increasing dip of the reservoir. The LTO experimental results over a temperature range of 130-170°C of a typical light oil indicate that LTO reaction is effective to completely consume O2 and have a high CO2 conversion rate of about 58%. The results of the reservoir numerical simulation study show that the cumulative produced oil increases as the gas injection rate increases, up to an optimum level and no oxygen breakthrough was observed at the production wells. For a 30 years period of injection using a base case 30000m3/day of gas injection rate (4 injectors), an incremental oil recovery factors of 35%, 36.5%, 35.5% of OOIP were achieved in air, CO2 and N2 injection simulations respectively, with CO2 having the best production performance. Early gas break-through and high GOR in producers are important factors to influence the gas injection performance. Sensitivity study indicates that shut-in of wells with high GOR can effectively reduce gas production, and a better reservoir performance of incremental oil recovery factors of about 33.5%, 36%, and 34% OOIP can be achieved for the respective gas injections in just an average period of 20 years. This is very favorable to the project economics. Preliminary economic and safety screening analyses, also confirmed that the 3 injection techniques are feasible and they all are profitable, i.e. positive net profit value, with air injection proving to be the most attractive of the three methods in terms of net profit due to its low cost of operation. Safety operations and corrosion controls of the different gas injection techniques are discussed in details and some recommendations are also provided for better IOR process in low permeability oil reservoirs.