Zhan, Jie (University of Calgary) | Yuan, Qingwang (University of Regina) | Fogwill, Allan (Canadian Energy Research Institute) | Cai, Hua (CNOOC Ltd.-Shanghai) | Hejazi, Hossein (University of Calgary) | Chen, Zhangxin (University of Calgary) | Cheng, Shiqing (China University of Petroleum-Beijing)
The application of horizontal well drilling coupled with the multistage fracturing technology enables commercial development of shale gas formations, which launches the energy revolution from conventional resources to unconventional resources. With the progress of understanding the nature of shale reservoirs, we find that some shale methane is stored as an adsorbed phase on surfaces of organic carbon. Meanwhile, laboratory and theoretical calculations indicate that organic-rich shale adsorbs CO2 preferentially over CH4. Shale gas reservoirs are recently becoming the promising underground target for CO2 sequestration. In the paper, systematic numerical simulations will be implemented to investigate the feasibility of CO2 sequestration in shale gas reservoirs and quantify the associated uncertainties.
First, a multi-continua porous medium model will be set up to present the matrix, nature fractures and hydraulic fractures in shale gas reservoirs. Based on this model, we will investigate a three-stage flow mechanism which includes convective gas flow mainly in fractures, dispersive gas transport in macro pores and multi-component sorption phenomenon in micro pores. To deal with this complicated three-stage flow mechanism simultaneously, analytical apparent permeability which includes slip flow and Knudsen diffusion will be incorporated into a commercial simulator CMG-GEM. A Langmuir isotherm model is used for CH4 and the multilayer sorption gas model, a BET model, is implemented for CO2. In addition, a mixing rule is introduced to deal with the CH4-CO2 competitive adsorption phenomenon.
In the paper, an integrated methodology is provided to investigate the CO2 sequestration process. Simulation results indicate that a shale gas reservoir is an ideal target for the CO2 sequestration. Even with the reservoir pressure maintenance due to the injection of CO2, the reservoir productivity is not enhanced. Hydraulic fracking which creates freeways for gas flow is the key to improve the reservoir performance. The multicomponent desorption/adsorption is a very important feature in a shale gas reservoir, which should be fully harnessed to benefit the CO2 sequestration process. In addition, we cannot ignore the contribution of slip flow and diffusion to the reservoir performance. Based on the methodology provided in this paper, we can easily deal with the apparent permeability effect using a commercial simulator platform.
The practice of injecting CO2 for oil production was initiated in the 1950’s. Today, CO2 flooding is an established technique to enhance oil recovery (EOR), and CO2 capture and storage in deep geologic formations is being studied for mitigating carbon emissions. CO2-foam has been used to improve the sweep efficiency as a replacement for polymers to avoid formation damage. Although it is common to use surfactants to generate and stabilize foams, they tend to degrade at high temperatures (212℉), high-salinity environments, and in contact with crude oil. Adding nanoparticles is a new technique to stabilize CO2 foams. The present work evaluates new foaming solutions that incorporate nanoparticles and viscosifiers to investigate the mobility-control performance when these foams are used as EOR fluids.
This study investigates the stability of alpha olefin sulfonate (AOS) foam and the corresponding mobility-reduction factor (MRF) for different foam solutions in the presence of nanoparticles and viscosifiers. To achieve this objective, foam stability was studied for various solutions to find the optimal solution at which higher foam stability in the CO2 foam system can be reached. Coreflood tests were also conducted on different Buff Berea sandstone cores at 150˚F saturated initially with a dead crude oil. The CO2 foam was injected with 80% quality as tertiary recovery mode. The oil recovery and the pressure drop across the core were then measured for different foam solutions.
Adding silica nanoparticles (0.1 wt%) and viscoelastic surfactant (VES) (0.4 wt%) to the AOS (0.5 wt%) solution improves both foam stability and MRF. In contact with crude oil, unstable oil-in-water emulsion formed inside the foam lamella that decreased the foam stability. A weak foam was formed for AOS solutions, but the foam stability increased by adding nanoparticles and VES. The oil recovery from the conventional water flooding (as a secondary recovery before foam injection) ranged from 40 to 48% of the original oil-in-place. AOS was not able to enhance the oil recovery with an apparent viscosity similar to that for the water/gas system (with no AOS in the solution), and no more oil was recovered by AOS foam. The addition of nanoparticles and VES to the solution improved the foam MRF and allowed extra oil production (8% in presence of nanoparticles, 15% by adding nanoparticles and VES).
Storage CO2 in shale formation is considered as a promising option to reduce CO2 emissions and enhance shale gas recovery. Many simple analytical and semi-analytical techniques have been proposed to support screening analysis and performance assessment for potential carbon sequestration sites. However, these analytical techniques have ignored the effect of fracture occurrences, which are important to the carbon sequestration in shale formation.
In this paper, numerical simulation technology is applied to model different complex hydraulic fracture occurrences and evaluate the CO2 seepage rule during carbon sequestration. First, multi-component Langmuir isotherm is applied to simulate the adsorption desorption phenomenon of CO2. Combining Langmuir isotherm with the reservoir parameters of Barnett shale formation, shale reservoir simulation model is constructed to simulate the CO2 seepage law during the CO2 sequestration. Then, based on the shale reservoir simulation model, local grid refinement technology is used to characterize the five typical fracture occurrences caused by hydraulic fracturing. Subsequently, the numerical simulation cases with five different fracture occurrences are run to evaluate the performance during CO2 storage process. Finally, some critical important parameters, including engineering and geologic parameters, are evaluated through the sensitivity study. In order to identify and illustrate the performance which progressively occur over time, the log-log plot of CO2 injection rate versus time is adopted.
The simulation results indicate that the flow regimes of CO2 injection can be classified into eight flow regions. Among these flow regions, the inner boundary dominated flow regime is a unique one which can occur only when realizing strongly stimulated reservoir volume. Further, the sensitivity study indicates that the fracture topologies and the primary fracture conductivity are the two key factors dominating the early-time flow behavior during the carbon sequestration. And the final-time flow behavior is dominated by the shale reservoir parameters.
This work systematically analyzes the effect of fracture topologies on carbon sequestration and enlarges our knowledge of CO2 storage in shale gas systems.
Shale gas has become an increasingly important source of natural gas (CH4) in the United States over the last decade. Due to its unconventional characteristics, injecting carbon dioxide (CO2) to enhance shale gas recovery (CO2-EGR) is a potentially feasible method to increase gas-yield while realizing CO2 sequestration (CS). Therefore, it is more and more important to quantitatively demonstrate the influence of various reservoir and completion parameters on performance of multiply-hydraulic fractured horizontal wells (MFHW) in the process of CO2 injection.
The close proximity of large CO2 emitters and depleted oil and gas reservoirs in the Louisiana Chemical Corridor (LCC) provide unique opportunities for CO2 geological sequestration in coastal Louisiana. The identification of sites with good storage capacity and retention characteristics is of prime importance for successful CO2 storage projects. In this study, the Bayou Sorrel field area located within close proximity of some of the large CO2 emitters in the LCC, is analyzed as a potential candidate site for aquifer storage. The results of static and dynamic aquifer storage capacity estimates are presented in this study. A volumetric approach is used to estimate the static storage capacity, and reservoir simulations are performed to compute dynamic storage capacity. The field and well data from publically available data sources are compiled to characterize the sands for prospective CO2 sequestration intervals (i.e., non-productive sands), and pressure and temperature conditions.
Information of total areal extent, gross formation thickness, and total porosity are used along with a storage efficiency factor to find the pore volume available for storage. The upper depth limit for CO2 injection is dictated by the pressure and temperature conditions at which CO2 exists in a supercritical state. The Peng-Robinson (PR) equation of state is used in conjunction with subsurface pressure and temperature to determine the minimum depth at which CO2 is supercritical. Multiple geological realizations are used for a realistic site specific storage capacity estimate. The reservoir simulations capture the transient nature of the process and provide estimation of storage capacity under dynamic conditions. The sensitivity of injection location and boundaries is also evaluated in the dynamic storage capacity estimates.
The results of the dynamic storage capacity estimate for a 1,000 ft thick interval at an average depth of 7,100 ft show that reasonable values of storage efficiency factors for this region are in the range of 1.14 to 2%. The results of the dynamic model also show that the nature of the storage zone boundary type, end point saturation and injection rate play significant role in estimation of dynamic storage capacity. These factors may induce more than 30% change in estimated dynamic storage value. The calculated storage efficiency factor may be applicable to other potential sites in this region, having similar geological characteristics.
Zhao, Fenglan (China University of Petroleum) | Hao, Hongda (China University of Petroleum) | Wang, Zhixing (China University of Petroleum) | Hou, Jirui (China University of Petroleum) | Fu, Zhongfeng (China University of Petroleum) | Li, Wenfeng (China University of Petroleum) | Wang, Peng (China University of Petroleum) | Zhang, Meng (China University of Petroleum) | Lu, Guoyong (China University of Petroleum) | Lv, Guangzhong (Institute of Exploration and Development, Shengli Oil Field, SINOPEC)
CO2-EOR is an effective technology for reducing CO2 emissions while enhancing oil recovery in ultra-low permeability reservoir, which has been performed in Shengli Oil Field, China since 2013 with cumulative CO2 injection of 12588 t by 2016. However, the area heterogeneity of reservoir resulted in serious gas channeling and poor production performance. Performance control methods including sweeping area regulation, differential pressure control and real-time producing regulation were proposed to enlarge sweeping area and improve CO2 utilization in areal heterogenous reservoir. 3D physical models of areal heterogeneity and five-spot pattern were utilized in the laboratory. Conventional CO2 flooding, sweeping area regulation, differential production pressure control and real-time producing regulation were conducted respectively in the 3D models, and the flooding efficiency was evaluated through oil recovery increments and changes of performance curves. Corescale numerical modeling was also built to study the profile improvements of CO2 flooding by the performance control methods.
Experimental and numerical simulation results showed that CO2 was displaced unevenly in the areal heterogeneous reservoir, leaving plenty of oil remained in the relatively high and relatively low permeability area. The oil recovery of CO2 flooding in areal heterogenous reservoir can be doubled by performance control methods of sweeping area regulation, differential pressure control or real-time producing regulation. The remaining oil in relatively low permeability area can be effectively displaced by sweeping area regulation, while both larger sweeping area and better CO2 flooding profile can be achieved by differential pressure control and real-time producing regulation. Higher productivity of individual well can be obtained in the early and middle stage of CO2 flooding by differential pressure control, while similar oil & gas production performance and longer displacement period of CO2 injection can be achieved by real-time producing regulation. The performance improvement of CO2 flooding by performance control methods provided a feasible technical strategy for enhancing oil recovery of areal heterogeneous reservoir in the oil field under the condition of a lower oil price.
After implications of hydraulic fracturing operations, the commercial production of tight formations and shale plays were successfully achieved in past decades. Due to the rapid decline rate after primary depletion of fractured reservoirs, extracting the remaining liquid hydrocarbon from the nano-Darcy permeability matrix becomes the next step.
Previously conducted laboratory experiments demonstrated promising results by successfully recovering liquid hydrocarbon from preserved and unfractured sidewall unconventional core plugs. However, what are the driving forces behind this observed result was not well understood. In other words, is the hydrocarbon recovery associated with commonly known recovery mechanisms during CO2 EOR processes, such as viscous displacement, oil volume expansion, viscosity reduction and vaporization of lighter hydrocarbon components? Or, is it driven by other mechanisms that are frequently considered insignificant during conventional CO2 EOR processes?
This study utilizes a commercial compositional simulator to investigate the oil production mechanisms from the matrix into the fractures. The process includes constructing a fine grid 3D model to simulate the previously conducted laboratory experiment, performing systematic sensitivity analysis, and evaluating the mechanisms that could potentially contribute to the oil recovery observed during the experiments. With laboratory scale modeling, the dominating mass transfer mechanism between the matrix and fractures, which in turn translates into oil recovery mechanism, is concluded to be diffusion. The work provided in this study can be used to enhance the accuracy for upscaled field simulations. However, whether CO2 EOR will unlock the unconventional liquid reservoir potential and make significant economic impacts at field scale needs to be carefully evaluated on a case by case basis.
For the past few decades, due to the increasing demand of energy and the advancements in horizontal drilling and hydraulic fracturing technologies, the industry reallocated its resources into exploring ways to produce oil from the previously unprofitable shale plays.
Hao, Hongda (China University of Petroleum) | Hou, Jirui (China University of Petroleum) | Zhao, Fenglan (China University of Petroleum) | Wang, Zhixing (China University of Petroleum) | Fu, Zhongfeng (China University of Petroleum) | Li, Wengfeng (China University of Petroleum) | Wang, Peng (China University of Petroleum) | Zhang, Meng (China University of Petroleum) | Lu, Guoyong (China University of Petroleum) | Zhou, Jian (China University of Petroleum)
As an effective method for resource utilization, CO2 huff-n-puff can be utilized to reduce CO2 emissions and enhance oil recovery in edge-water flock-block reservoir, which was implemented in Jidong Oil Field, China since 2008 with oil production of 6.5×104 bbls by 2015. During operation period, synergetic effect was observed in adjacent wells with water cut drops and oil increments in a horizontal well group. Experimental and numerical simulations were conducted to investigate synergetic mechanisms of CO2 huff-n-puff. 3D physical models with a horizontal well group and edge-water-driving system were established in laboratory to simulate the edge-water fault-block reservoir. The formation mechanisms and influence factors of synergetic CO2 huff-n-puff were studied through laboratory experiments. Base reservoir model was also built to further discuss the synergetic types and injection allocations for CO2 huff-n-puff in horizontal well group.
Synergetic CO2 huff-n-puff is a smart gas cycling strategy for the horizontal well group to balance the formation pressure and replace the interwell oil. Experimental and numerical results showed that after CO2 injected into low tectonic position of the reservoir, synergetic effect could be observed in high position well with water cut drops and oil increments. The mechanisms of synergetic effect can be recognized as formation energy supplement, gas sweeping, gravity segregation and CO2-assisted edge-water driving. The stratigraphic dip and heterogeneity are advantages for the formation of synergetic effect. The synergetic types of CO2 huff-n-puff can be summarized as single-well synergy and multi-well synergy. For single-well synergy, edge-water invasion can be effectively controlled by energy supplement after CO2 injected into relatively low position well. For multi-well synergy, better synergetic effect and remaining oil replacement can be achieved after gas injected through different positions of the well group. The development efficiency of synergetic CO2 huff-n-puff can be enlarged with 700t CO2 injected into low position well + 100t CO2 into high position well, and about 5767.9 bbls oil of the well group could be recovered with the soaking time of 50d.
During the past 45 years, CO2 flood technology for Enhanced Oil Recovery projects evolved from a partially understood process filled with uncertainties to a process based on proven technology and experience. Many questions involved with CO2 flooding have been thoroughly analyzed and answered. This knowledge is currently being used by a limited number of companies that actually know how to design, implement, and manage a CO2 flood for long term profit. The purpose of this report is to help disseminate this knowledge to operating companies interested in EOR flooding or to CO2 Sequestration Communities interested in storing CO2 in EOR projects.
In 2015, Merchant Consulting published CMTC-440075-MS “Life beyond 80 – A look at Conventional WAG Recovery beyond 80% HCPV Injection in CO2 Tertiary Floods”. The primary objective of the report was to target all 10 CO2 Recovery Methods used today including “Conventional WAG Techniques” which have been used in over 90% of all the Enhanced Oil Recovery projects implemented to date. These include projects in the Permian Basin in Texas, Colorado, Oklahoma, and Wyoming. The paper presents answers to the question “What is life after 80% HCPV Injected?” And “What effect does life after 80% HCPV have on Tertiary Oil Recovery, CO2 Utilization and CO2 Retention in different producing formations?” Results of this study show Tertiary Oil Recovery can be as high as 26% OOIP when slug sizes exceed 190% HCPV injected.
Conventional WAG History in CO2 Tertiary Oil Projects:
To achieve CO2 Injection beyond 80% HCPV Injection requires proper CO2 WAG Management. The purpose of this report is to provide both the EOR and CO2 Sequestration Communities an understanding of the “History of Conventional WAG” and how it has changed from first introduced in the Lab in the 1950’s, to how it was implemented and developed in the 1980’s by the Major Oil Companies in the Permian Basin, and how Conventional WAG is being managed today in the field.
Carbon Dioxide (CO2) flooding is one of the most globally used EOR processes to enhance the oil recovery. However, the low gas viscosity and density result in gas channeling and gravity override which lead to poor sweep efficiency. Foam application for mobility control is a promising technology to increase the gas viscosity which leads to lower mobility and better sweep efficiency inside the reservoir. Foam is generated inside the reservoir by co-injection surfactant and gas. Although there are many surfactants that can be used for such purpose, their performance with Supercritical CO2 (ScCO2) is weak which leads to poor or loss of mobility control. This experimental study evaluates a newly developed surfactant (CNF) that was introduced for ScCO2mobility control in comparison with a common foaming agent, anionic Alpha Olefin Sulfonate (AOS) surfactant. Experimental work was divided into three stages: foam static tests, interfacial tension measurements, and foam dynamic tests. Both surfactants were investigated at different conditions. In general, results showed that both surfactants are good foaming agents to reduce the mobility of ScCO2 with better performance of CNF surfactant. Shaking tests in presence of crude oil showed that foam life for CNF extends to more than 24-hr but less than that for AOS. Moreover, CNF features lower CMC, higher adsorption and smaller area/molecule at the liquid-air interface. Furthermore, entering, spreading, and bridging coefficients interpretations indicated that CNF surfactant produces very stable foam with light crude oil in both DI and saline water, whereas AOS was stable only in DI water. At all conditions for mobility reduction evaluation, CNF exhibited stronger flow resistance, higher foam viscosity, and higher mobility reduction factor than that of AOS surfactant. In addition, CNF and ScCO2 simultaneous injection produced 8.83% higher oil recovery than that of the baseline experiment and 7.87% higher than that of AOS. Pressure drop profiles for foam flooding using CNF was slightly higher than that of AOS indicating that CNF is better in terms of foam-oil tolerance which resulted in higher oil recovery.
As the only company which owns the right for coal mines and oil and gas production in China, Yanchang Petroleum Group has the unique advantages to implement integrated CO2 capture and enhanced oil recovery (EOR) in Ordos Basin. This area is also one of the largest CO2 emission areas in China. The coal to chemicals plant was built to efficiently co-utilize coal, oil and natural gas. The energy efficiency is about 8.9% higher than the world average level. Two corresponding CO2 capture plants were built with the capacity of 50,000 and 360,000 tonnes per year. The cost for CO2 capture is as low as $17.5/tonne, much cheaper than most of the other CO2 capture project in the world. By optimizing the distance between CO2 capture plants and EOR sites, the shortest distance, the shortest distance for CO2 transportation is only 10 kilometers. It is estimated that the cost for CO2 transportation is $2.58/tonne. Meanwhile, the CO2 is used for enhanced oil recovery in Yanchang oil fields. Extensive research has been done to investigate the suitable geological conditions for CO2-EOR. Experiments have also been conducted to study the behaviors of CO2-crude oil mixture. Two pilot tests including Qiaojiawa 203 block and Wuqi Yougou are now in operation with well production being doubled or tripled. In addition, more than 87% of reservoirs in Yanchang oil field in Ordos Basin are suitable for CO2-EOR with estimated billions of CO2 storage capacity.
Greenhouse gas emissions are regarded as one of the most important factors resulting in global warming and climate change. In all the greenhouse gases, the proportion of carbon dioxide (CO2) emitted is the greatest and around 76%, according to the statistics from the Intergovernmental Panel on Climate Change (IPCC) in 2013.
The CO2 emissions are mainly from the consumption of fossil fuels such as coal, oil and natural gas which provide 85% of worldwide energy needs for human activities (BP, 2017). While in these CO2 sources from energy consumptions, the burning of coal produces more CO2 than oil or natural gas at the same equivalent electricity generated.