Yang, Junjie (Baker Hughes, a GE Company) | Oruganti, Yagna Deepika (Baker Hughes, a GE Company) | Karam, P. (Baker Hughes, a GE Company) | Doherty, Dan (Riley Exploration) | Doherty, Jim (Riley Exploration) | Chrisman, J. (Riley Exploration)
The San Andres is a well-known dolomitic enhanced oil recovery target with low matrix permeability in the area of interest (Yoakum County, TX). A reservoir simulation study was undertaken to investigate the feasibility of using horizontal multi-fractured wells in low permeability miscible floods. A reservoir model was developed for the area of interest and was history-matched with the primary production data from the field. The model was then used to illustrate the CO2 miscible flood potential by quantifying the incremental recovery over the primary production scenario.
Compositional modeling was used in the study to evaluate CO2 flooding feasibility and efficiency. A holistic workflow including PVT modeling, petrophysical analysis, geomodeling, and hydraulic fracture modeling, provided integrated input into the reservoir model. Continuous CO2 flooding was explored as an operating strategy. Furthermore, water alternating gas (WAG) cases were designed and run as a more realistic and cost-effective method of implementing miscible flooding. Based on the history-matched model, sensitivity analyses were conducted on hydraulic fracture geometry, well spacing, injection patterns and operating conditions for the primary production scenario, continuous CO2 flooding and WAG scenarios.
Field surveillance and observations during the history-matching process showed that the wells had undergone damage from scaling. Sensitivity analysis showed that 300ft to 400ft cluster spacing resulted in the highest oil production during the first 10 years. Interdependent parameters such as well spacing and fracture half-length were studied together; this sensitivity review showed that the differential oil recovery from 128 acres to 160 acres was larger than that from 160 acres to 213 acres, leading to the recommendation that 160 acres could be the optimized well spacing. In the optimized design, the continuous CO2 injection case showed an incremental oil recovery of 22% (compared to primary production). The CO2 utilization factor was between 7 and 8, which was consistent with the reported value from literature. WAG sensitivity analysis showed that longer hydraulic fractures did not necessarily improve WAG efficiency, but led to earlier CO2 breakthrough. This observation confirmed our early suspicion that smaller hydraulic fracturing treatment could be a more cost-effective design for miscible flooding in this reservoir. In addition, sweep efficiency and recovery were sensitive to WAG ratio, but not to injection slug size in each cycle.
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.
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.
Relative permeability of CO2 and brine is one of the fundamental parameters controlling flow related to carbon storage in saline aquifers. Core samples recovered from subsurface formations are characterized in laboratory experiments to determine effective core relative permeability curves. Typically, coreflooding experiments are conducted at high injection rates so that the resulting flow is viscous dominated. However, at lower rates, it has been shown that the effective curves may change as capillary heterogeneity effects become significant. Using relative permeability determined by conventional coreflooding in simulations with low flow rates, e.g., to model CO2 migration in aquifers, may incur significant error.
A new method for calculating low flow rate relative permeability curves is presented. The method is based on approximate analytical solutions for effective relative permeability under steady state and capillary limit flow conditions. Derivation is carried out using power law averaging, assuming log normally distributed core permeability. We validate the analytical solution by comparison to numerical solutions for a wide range of cases. An additional correction for the CO2 curves is shown to be necessary and derived by matching analytical and numerical results. Given a core which has been characterized by conventional high rate coreflooding experiments, the current method gives a fast and efficient correction for low flow rate applications. It circumvents the need for additional experiments or computationally expensive coreflooding simulations.
Alfarge, Dheiaa (Iraqi Ministry of Oil, Missouri University of Science and Technology) | Wei , Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
Shale formations in North America such as Bakken, Niobrara, and Eagle Ford have huge oil in place, 100-900 Billion barrels of 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. Although most of the previous studies in this area recommended that CO2 would be the best EOR-technique to improve oil recovery in these formations, pilot tests showed that natural gases performance clearly exceeds CO2 performance in the field scale. In this paper, two different approaches have been integrated to investigate the feasibility of three different miscible-gases which are CO2, lean gases, and rich gases. Firstly, numerical simulation methods of compositional models have been incorporated with Local Grid Refinement (LGR) of hydraulic fractures to mimic the performance of these miscible gases in shale-reservoirs conditions. Implementation of a molecular diffusion model in the LS-LR-DK (logarithmically spaced, locally refined, and dual permeability) model has been also conducted. Secondly, different molar-diffusivity rates for miscible gases have been simulated to find the diffusivity level in the field scale by matching the performance for some EOR pilot-tests which were conducted in Bakken formation of North Dakota, Montana, and South Saskatchewan.
The simulated shale-reservoirs scenarios confirmed that diffusion is the dominated flow among all flow regimes in these unconventional formations. Furthermore, the incremental oil recovery due to lean gases, rich gases, and CO2 gas injection confirms the predicted flow-regime. The effect of diffusion-implementation has been verified with both of single porosity and dual-permeability model cases. However, some of CO2 pilot-tests showed a good match with the simulated cases which have low molar-diffusivity between the injected CO2 and the formation-oil. Accordingly, the rich and lean gases have shown a better performance to enhance oil recovery in these tight formations. However, rich gases need long soaking periods, and lean gases need large volumes to be injected for more successful results. Furthermore, the number of huff-n-puff cycles has a little effect on the all injected-gases performance; however, the soaking period has a significant effect.
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.
A new method of coalbed methane (CBM) recovery is proposed wherein hot carbon dioxide at or near supercritical condition is injected into a CBM reservoir to take advantage of enhanced desorption of methane at elevated temperatures and the preferential adsorption of CO2 on coal surfaces compared to methane. The feasibility of this concept was studied by reservoir simulations using one quarter of an inverted five spot pattern using CO2 and CH4 adsorption isotherms published in the literature. The study compared CBM recovery by pressure depletion, CO2 injection and injection of CO2 that is 10°C hotter than the reservoir temperature. Results show that hot CO2 injection can significantly increase the production rate and recovery factor over and above that achievable by reservoir heating or CO2 injection alone. This new method holds promise for enhanced CBM recovery and also CO2 sequestration, especially for high-rank coals where swelling of coal by CO2 injection is minimized. Preliminary considerations suggest that this method can be economic over a range of CO2 and natural gas price if the CO2 comes from natural sources and the CBM field is located near an existing CO2 pipeline. Alternatively, if the source of CO2 is industrial, this method can be profitable if the cost of CO2 capture is offset by the trading price of CO2 and if the CBM project is located near the CO2 source.
Coalbed methane, also known as coal seam gas, is a significant source of natural gas worldwide, with sizable reserves in the United States, Australia, Russia, Canada and China. In 2015, CBM production in the US was 1.27 Tcf (35.97 Bcm), accounting for 3.9% of all US natural gas production (EIA, 2017). Commercial production of CBM occurs in ten US basins with major production coming from the San Juan, Black Warrior and the Central Appalachian. In 2015, CBM production in Australia was 270 Bcf (7.65 Bcm) accounting for 18% of Australia’s total natural gas production (Australian Government, 2016).
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.
Geological carbon sequestration represents a long-term storage of CO2, in which large-scale CO2 is injected into the subsurface geologic formations, such as the deep saline aquifers or depleted oil and gas reservoir. In the CO2 sequestration process, the injected CO2 is expected to remain in the reservoir and not to migrate to the earth surface. To better understand the CO2 movement undersurface and obtain real time information in carbon sequestration, an iridium oxide-based Severinghaus-type CO2 chemical sensor was constructed and tested in this study.
The CO2 sensor was designed and constructed based on the intersection inspiration from electrochemistry idea. The principle of the CO2 sensor design is dramatically rely on the pH detection of the electrolyte solution which generated by the hydrolysis process of CO2. The developed CO2 sensor includes a couple of Iridium-Oxide electrodes. To meet the working purpose, iridium oxide nanoparticles was prepared and electrodeposited for the thin IrO2 film generation on the surface of metal substrate. The other critical parts, such as a thin gas-permeable silicone membrane, a porous metal supporting material, and the bicarbonate-based electrolyte solution are prepared for the sensor’s preparation. The assembled sensor was tested in aqueous solution with different CO2 concentrations. Then the sensor was settled in harsh, high-pressure environments, in order to invest the performance of the CO2 sensor under reservoir conditions.
The definition of CO2 sequestration was the whole process of the CO2 capture and the CO2 long-term storage . It had been treated as a potential method to decelerate the accumulation process of greenhouse gas which generated from the fossil fuels burning and other source . While for the geologic sequestration, it means to put the captured CO2 in the geological formation for the aim of long-term storage.
Cao, Mengjing (China University of Petroleum -Beijing) | Wu, Xiaodong (China University of Petroleum -Beijing) | An, Yongsheng (China University of Petroleum -Beijing) | Zuo, Yi (China University of Petroleum -Beijing) | Wang, Ruihe (China University of Petroleum -Beijing) | Li, Peng (Shengli Oilfield, Sinopec)
Unconventional oil, such as tight oil and shale oil, has become one of the most significant contributors of oil reservoirs and production growth. Due to low porosity and ultra-low permeability, unconventional oil reservoirs require multistage hydraulic fracturing technique to maximize production. However, the primary recovery remains very low to narrow the profit margin heavily. Although CO2 huff-n-puff process holds great potential to increase oil recovery and has a chance to sequester CO2 to reduce environmental footprint, our current knowledge of the performance of this process is very limited.
With numerical simulation, we performed a series of sensitivity work to present the impacts of reservoir properties, fracture properties and operation parameters such as CO2 injection rate, injection time, soaking time, number of cycle of CO2 on enhanced oil recovery in the tight oil formation. What’s more, the method of analysis of variance (ANOVA) was used to evaluate the performance of CO2 huff-n-puff process and beneficial result from CO2 EOR technology. Simulation results showed that bottom hold pressure and injection cycles impose more significant impose on oil recovery increment than injection time, injection rate and production time per cycle. Based on the typical reservoir and fracture properties from tight oil reservoir, the numerical models were established to evaluate the performance of four EOR methods: CO2 huff-n-puff, water huff-n-puff, nanofluids huff-n-puff and water alternating gas (WAG). With the comparison of oil recovery and its increment of four EOR methods and depletion method, it is found that CO2 huff-n-puff method would lead to much more incremental oil recovery than other three methods, which reveals its huge potentials of enhancing oil recovery and improving development profit in unconventional reservoirs. The conclusion of this work has the potential to advance our understanding of the role of CO2 in developing unconventional oil reservoirs, which will benefit both energy economy and environment with CO2 geological sequestration.