Yuan, Qingwang (University of Regina) | Zhan, Jie (University of Calgary) | Wang, Jinjie (China University of Geosciences) | Zeng, Fanhua (University of Regina) | Knorr, Kelvin D. (Saskatchewan Research Council) | Imran, Muhammad (Saskatchewan Research Council)
As an efficient enhanced oil recovery (EOR) technique, carbon dioxide (CO2) miscible flooding can greatly reduce the viscosity of oil and improve its mobility, and has great potential to achieve higher oil recovery. However, the disadvantage of CO2 flooding, when compared with waterflooding, is the relatively larger viscosity ratio between CO2 and oil. Under such unfavorable conditions, frontal instabilities, or viscous fingering, can easily develop. This may affect the performance of CO2 miscible flooding and result in less sweep efficiency and oil recovery.
In the present study, nonlinear numerical simulations were conducted to model the CO2 miscible flooding in subsurface porous media. Both concentration-dependent diffusion and a varying dispersion that is closely related with flow rates were incorporated into the mathematical model. The development of frontal instabilities with time was simulated with highly accurate numerical methods. More importantly, to reduce the unstable displacement and improve sweep efficiency, a time-dependent injection rate involving periodic alternation of injection and extraction was employed. Different from the widely used constant injection rate, this time-dependent displacement rate led to different flow dynamics and sweep efficiency, although the amount of CO2 injected was the same. In particular, the effect of a cycle period on the propagation of CO2 was carefully examined. It was found that a longer period led to earlier breakthrough of CO2 and less sweep efficiency. However, a shorter period with faster alternation of injection and extraction had a stabilizing effect. In particular, a later breakthrough was achieved and higher sweep efficiency at breakthrough was obtained compared with that of a constant injection rate. This indicates that pulsed displacement through fast switching of injection and extraction has the potential to maximize oil recovery in CO2 miscible flooding.
Miscible flooding is proven as an economical EOR process and can be used for a variety of different reservoirs. In CO2 miscible flooding, one of the most promising EOR techniques, the CO2 can become miscible with the oil when the pressure is higher than the minimum miscibility pressure (MMP).
Unconventional resources have played a significant role in changing oil industry plans recently. Shale formations in North America such as Bakken, Niobrara, and Eagle Ford have huge oil in place, 100-900 Billion barrels of recoverable oil in Bakken only. However, the predicted primary recovery is still below 10%. Therefore, seeking for techniques to enhance oil recovery in these complex plays is inevitable. In this paper, two engineering-reversed approaches have been integrated to investigate the feasibility of CO2 huff-n-puff process in shale oil reservoirs. Firstly, a numerical simulation study was conducted to upscale the reported experimental-studies outcomes to the field conditions. As a result, different forward diagnostic plots have been generated from different combinations of CO2 physical mechanisms with different shale-reservoirs conditions. Secondly, different backward diagnostic plots have been produced from the history match with CO2 performances in fields’ pilots which were performed in Bakken formation of North Dakota and Montana. Finally, fitting the backward with the forward diagnostic plots was used to report and diagnose some findings regarding the injected-CO2 performance in field scale.
This study found that the porosity and permeability of natural fractures in shale reservoirs are significantly changed with production time, which in turn, led to a clear gap between CO2 performances in lab-conditions versus to what happened in field pilots. As a result, although experimental studies reported that CO2 molecular-diffusion mechanism has a significant impact on CO2 performance to extract oils from shale cores, pilot tests performances indicated a poor role for this mechanism in field conditions. Therefore, the bare upscaling process for the oil recovery improvement and the CO2-molecualr diffusion rate, which are obtained from CO2 injection in lab-cores, to the field scale via numerical simulations needs to be reconsidered. In addition, this study found that kinetics of oil recovery process in productive areas and CO2-diffusivity level are the keys to perform a successful CO2-EOR project. Furthermore, general guidelines have been produced from this work to perform successful CO2 projects in these complex plays. Finally, this paper provides a thorough idea about how CO2 performance is different in field scale of shale oil reservoirs as in lab-scale conditions.
Liu, Xiaochun (Research Institute of Oil and Gas Technology) | Ma, Liping (Research Institute of Oil and Gas Technology) | Tan, Junling (Research Institute of Oil and Gas Technology) | Yang, Tangying (Research Institute of Oil and Gas Technology) | Li, Xiaorong (Research Institute of Oil and Gas Technology) | Hou, Jirui (Research Institute of Enhanced Oil Recovery, China University of Petroleum) | Wei, Qi (Research Institute of Enhanced Oil Recovery, China University of Petroleum) | Hao, Hongda (Research Institute of Enhanced Oil Recovery, China University of Petroleum) | Song, Zhaojie (Research Institute of Enhanced Oil Recovery, China University of Petroleum) | Wang, Shitou (Research Institute of Oil and Gas Technology) | Bi, Weiyu (Research Institute of Oil and Gas Technology)
H-3 Block is an ultra-low permeability reservoir in Changqing oil field, China which had been waterflooded from 2009 and was switched to CO2 flooding in 2013 due to excess water production. However, the nature fractures in NE-SW region have resulted in early CO2 breakthrough and poor production performance. The investigation of CO2 production performance and the method to control CO2 production becomes a key to continue CO2-EOR project.
Outcrop cores are used to perform a series of CO2 flooding experiments at reservoir conditions of pressure, temperature and formation water salinity. Permeability heterogeneity and injection pressure are considered as two variables to affect gas channeling characteristics. It is figured out that producing gas-oil ratio and components analysis of effluent could be used to judge gas channeling and timing to control CO2 production for field use. Starch gel is developed to control CO2 production within nature fractures to improve CO2 swept volume in rock matrix. Ethylenediamine (EDA) is proposed to delay CO2 production within high-permeability zones, and the application boundary as a function of permeability heterogeneity is determined.
Three production stages are clearly stated based on production performance and experimental observation, including gas-free production stage, oil/gas co-production stage, and gas channeling stage. A significant new finding is that oil/gas co-production stage contributes the most to oil recovery. And oil-CO2 mass transfer zone, rather than free CO2, reaches the outlet at this stage, which is proved by color of effluent and chromatographic analysis. For field cases, producing gas-oil ratio and components analysis of effluent at wellhead could help field engineers make a decision: keep producing with caution at oil-gas co-production stage or control the CO2 production at gas channeling stage. The conformance improvement and the increase in injection pressure could remarkably enhance the oil recovery at oil/gas co-production stage. To delay gas channeling and extent oil/gas co-production stage, two-level gas channeling control is presented. A slug of starch gel is first injected to block fractures and then ethylenediamine is injected to react with in-situ CO2 within high-permeability zone. The starch gel, acting as pure viscous fluid, would not leave contamination in rock matrix. And the viscous reactant of ethylenediamine and in-situ CO2 could successfully tune injected CO2 to flood low-permeability zone when permeability ratio is less than 100.
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.
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).
A fault is a potential pathway for fluid leakage, which can contaminate underground water resources. In addition, fault leakage can affect hydrocarbon production. This study aims to develop a type-curve-based methodology to characterize a fault both laterally and vertically using pressure transient analysis. We develop an analytical model to assess the pressure perturbations corresponding to production/injection from/into a reservoir with a leaky fault. Displacement of layers during the fault displacement may cause alteration of the reservoir properties across the fault. This alteration is accounted for by considering different properties on the two sides of the fault. The reservoir is divided into two regions separated by the fault, which are in hydraulic communication with one another and with the overlying/underlying permeable layers. The governing system of differential equations and corresponding boundary conditions are solved using Fourier and Laplace transforms. At early times of the fault leakage, the recorded well pressure changes are mostly affected by the fault properties and the effects of resistance from the upper zone emerge later. In this model, we neglect the resistance to leakage flow caused by the overlying zone to focus on the pressure changes at early times of the fault leakage. We show that these assumptions are valid to arrive at correct fault characteristics. For fault characterization, type curves are presented in terms of dimensionless vertical and horizontal conductivities of the fault. A computational optimization method is used in combination with type curves to fully characterize the reservoir-fault system. Results show that the characterization method is useful to estimate the fault vertical and lateral conductivities.
Carbon dioxide flooding of oil fields around the world is proven as a successfully adopted practice in increasing oil production particularly in marginal wells with low production rates. However, the limitations of this technology lie in the limited supply of carbon dioxide, high capital cost, and infrastructure corrosion. In this work, we present an alternative CO2 flooding method which generates CO2 inside the reservoir to increase oil recovery. The process involves the injection of a concentrated CO2 producing solution of ammonium carbamate (AC). Chemical solvent CO2 capture technology was widely used for years. Carbamates were formed when aqueous amines absorbed CO2. The new proposed in situ CO2 generation EOR technique provides a way to directly apply the product of the CO2 capture technology for outstanding tertiary recovery.
Ammonium carbamate (CH6N2O2), highly water-soluble chemicals, can dissociate at reservoir temperature producing carbon dioxide and ammonia. The carbon dioxide migrates to the oil phase, causing oil phase swelling and reducing oil viscosity, and therefore increasing oil production. The ammonia dissolves in the water, and the ammonia-water solution increases the water wettability of the rock.
Flow experiments were conducted using 6" Ottawa sand packs. The experiments demonstrated that the decomposition of a 35% AC solution injected to the sand packs resulted in further lowering of the residual oil saturation following a standard water flood. The tertiary recovery in the high-pressure sand pack experiments was found to average 27%.
In the proposed process, AC can be dissolved in produced reservoir fluids or seawater and injected into the reservoir to generate CO2 in situ and increase oil production as it decomposes. The benefits of this process compared to CO2 flooding lie in the simplicity of adapting this technology to an existing waterflood, and the lack of the complicated infrastructure needed in a typical CO2 project, such as compression and gas handling facilities. An additional advantage lies in the ability to deliver the CO2 in the form of a room temperature solid, alleviating the need for a pipeline.
Mu, Lingyu (China University of Petroleum) | Liao, Xinwei (China University of Petroleum) | Zhao, Xiaoliang (China University of Petroleum) | Chen, Zhiming (China University of Petroleum) | Zhu, Langtao (China University of Petroleum) | Luo, Biao (China University of Petroleum)
The CO2 dissolved in the aquifer will increase the density of brine, which can result in the instability of the gravity and prompt the onset of the viscous finger. The viscous finger will lead to the convective mix, accelerating the process of CO2 solution in the brine. However, the gas stream in the CO2 storage usually contains the impurities such as N2, O2, and SO2, which can change the density difference in the process of solution, and affect the solubility trapping in the CO2 sequestration.
In this paper, a numerical simulation method was used to study the effect of different impurities on the solubility trapping in the process of CO2 storage. Firstly, based on the PR-HV model, this paper calculated the solubility of CO2, N2, O2, and SO2 with different temperature and salinity and analysed the variation of the solubility. Then a multi-component numerical simulation model based on a certain aquifer layer was established to compare the CO2 dissolution rate and the onset time of the instability and analyze the influence of impurities in the CO2 stream on the solubility trapping. Finally, this paper clarified the impact on the CO2 storage and suggested that the concentration of the impurities should be controlled in a rational range for the perspective of the economy and efficiency.
The results show that the solubility of CO2 is higher than N2 and O2 in the saline water, and close to that of SO2. We applied the solubility data to the numerical simulation. The results of the numerical simulation shows that with the increase of the concentration of N2 or O2, CO2 dissolution rate has a decrease, and the onset time of the instability has an increase. It meas the longer time CO2 plume keeping in the state of good flowing capability and low density. The onset of viscous finger will be postponed, leading to a negative influence on the solubility trapping and the risk of the CO2 leak through fractures and faults. On the contrary, SO2 can shorten the onset time of the instability, which accelerates the viscous finger and prompts the solubility trapping. A further conclusion is that the effect of SO2 on the viscous fingering is more significantly than N2 and O2.
This paper deepens the understanding about the effect of the impure CO2 on the solubility trapping, and clarifies the effect of different impurities.
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.
Injecting carbon dioxide (CO2) into oil reservoirs has the potential to enhance oil recovery (EOR) and mitigate climate change by storing CO2 underground. Despite successes in using CO2 to enhance oil recovery, mobility control remains a major challenge facing CO2 injection projects. The objective of this work is to investigate the potential of using surfactant and a mixture of surfactant and nanoparticles (NPs) to generate foam to reduce gas mobility and enhanced oil recovery.
A newly developed anionic surfactant and a mixture of the surfactant and surface modified silica NPs were used to assess the ability of generating a stable foam at harsh reservoir conditions: sc-CO2 and high temperature. Dynamic foam tests and coreflood experiments were conducted to evaluate foam stability and strength. To measure the mobility of injected fluids in sandstone rocks, the foam was generated by co-injection of sc-CO2 and surfactant, as well as a mixture of surfactant and NPs at 90% quality. The coreflood experiments were conducted using non-fractured and fractured sandstone cores at 1550 psi and 50°C.
Surfactant alone and mixtures of surfactant and NPs were able to generate foam in porous media and reduce CO2 mobility. The mobility reduction factor (MRF) for both cases was about 3.5 times higher than that of injecting CO2 and brine at the same conditions. The coreflood experiments in non-fractured sandstone rocks showed that both surfactant and a mixture of surfactant and NPs were able to enhance oil recovery. The baseline experiment in the absence of surfactant resulted in a total recovery of 71.50% of the original oil in place (OOIP). Using surfactant brought the oil recovery to 76% of the OOIP. The addition of NPs to surfactant resulted in a higher oil recovery still, 80% of the OOIP. In fractured rocks, oil recoveries during secondary production mechanisms for the mixture, the surfactant alone, and sc-CO2 alone were 12.62, 8.41 and 7.21% of the OOIP, respectively.