Wang, Zhuangzhuang (China University of Petroleum) | Li, Zhaomin (China University of Petroleum) | Lu, Teng (China University of Petroleum) | Yuan, Qingwang (University of Regina) | Yang, Jianping (PetroChina Liaohe Oilfield company) | Wang, Hongyuan (PetroChina Liaohe Oilfield company) | Wang, Shizhong (PetroChina Liaohe Oilfield company)
Flue gas is industrial waste gas produced by the burning of fossil fuels. Its main compositions are 10% - 15% of carbon dioxide and 80% - 85% of the nitrogen, two key components needed for gas flooding. Adding a certain amount of flue gas into steam in displacement could decrease steam partial pressure, improve the steam quality and reduce heat loss, resulting in reduction of steam injection amount and improvement of development performance. The objective of the research is to investigate the mechanism of enhanced oil recovery (EOR) of flue gas assisted steam flooding which has a dual significance of reducing greenhouse gas emissions and improving oil displacement efficiency.
In this paper, PVT measurements at high temperature and high pressure (HTHP) were firstly conducted to analyze the effect of flue gas on property of heavy oil. Then sandpack displacement experiments containing 5 sub-experiments: steam flooding, flue gas assisted steam flooding, first steam flooding then flue gas assisted steam flooding, water flooding, flue gas assisted water flooding, were operated to compare the contribution of heat and gas on recovery. In the experiment of flue gas assisted steam flooding, the production rate and composition of gas were measured and analyzed, and the form of the produced oil was also compared with steam flooding.
The PVT measurements results show that with flue gas dissolved, viscosity of heavy oil declines and volume expands. The solubility of flue gas in heavy oil decreases with temperature and increases with pressure. The greater the solubility of flue gas, the lower viscosity of heavy oil, the larger volume. At the same solubility, as the temperature increases, the viscosity reduction effect of flue gas weakens and the volume expansion effect enhances.
The displacement experiments results indicate that the addition of flue gas to steam can significantly improve oil displacement efficiency compared with steam injected alone. In the test of flue gas assisted steam flooding, the heavy oil was produced in the form of foamy oil because of dissolution of flue gas, especially CO2, which could expand oil volume and reduce the flow resistance of heavy oil to a certain extent. Besides, the cumulative volume of the produced gas was smaller than the injected gas, and in the produced gas the proportion of CO2 was less than the injected proportion. Furthermore, the contribution of flue gas to recovery when injected with steam is greater than with water because of the synergistic effect of heat and gas.
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.
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.
Chen, Hao (China University of Petroleum) | Zhang, Xiansong (CNOOC) | Li, Baozhen (CNOOC) | Mei, Yuan (China University of Petroleum) | Tang, He (China University of Petroleum) | Wang, Shuai (Changqing Oilfield Company, PetroChina)
A newly discovered offshore oilfield in QHD 29-2 block is facing the problem of selecting the appropriate developing method. It covers approximately 2300 km2 and with an average water depth of 27.6m. The depth of the exploration well is over 3600 m with thick sand layer and oil zone. Conventional waterflood cannot be implemented due to the reservoir characteristics of small pores and throats, complex lithology, strong heterogeneity and low water injectivity. Near-miscible flooding is proposed considering the wide range of CO2 content (24-90 mol%) in the production gas.
Slim tube test and slim tube simulation are conducted successively to determine the minimum miscible pressure (MMP) of the production gas and oil samples from the targeted reservoir. The relationship of displacement efficiency (DE), interfacial tension (IFT) and displacement pressure are provided and chosen as the basis for the division of the pressure interval of near-miscible flooding. The lower limit of the CO2 content in the production gas to achieve near-miscible flooding are determined for the well 29-2E-5 with the well depth of 3308-3330 m. On this basis, an adjustment measures of adding intermediate components of (C2-C6) is proposed and assessed. The amount of the adding components is calculated and provided correspondingly.
Boundaries of the pressure region of near-miscible flooding are obtained for different CO2 contents. Considering the reservoir conditions (112.1 °C, 31.96 MPa), the lower CO2 content of 64% is estimated to be able to achieve near-miscible flooding for the targeted well. Accordingly, 2.3, 6.5, and 10.3 mol% of (C2-C6) are determined to be the lowest amounts for the adding components to achieve near-miscible injection for the CO2 contents of 55%, 40%, and 24%, respectively.
Thus, the evaluation of the feasibility and optimization measures of near-miscible flooding by production gas re-injection with varying CO2 content in a newly discovered offshore reservoir was conducted. Specific regions in the vicinity of MMP for impure CO2 near-miscible flooding on the basis of comprehensive analysis of displacement efficiency and IFT from the views of both engineering and physicochemical were determined.
The selection of depleted oil and gas fields as potential CO2 geological storage sites has both positive and negative aspects that need to be considered. The positives are that the storage capacity or pore volume can be reliably estimated from field’s production history, and reservoir characterization can be performed with more readily available well, log or seismic data without additional expenses. The main drawback is the presence of wells in the field, as each well may provide a leakage pathway for injected CO2. The leakage potential of a well is a function of its proximity to injection wells, cement coverage in the potential storage zone, well abandonment conditions including cementing of the annular space, and the nature of any barriers to prevent CO2 leakage to the surface. Qualitative and quantitative risk-based approaches can be used to identify the wells that have comparatively higher leakage probabilities in comparison to other wells. The objective of this study is to use a risk-based approach to identify and categorize wells based on their leakage potential in depleted oil and gas fields. This will not only help in planning injection strategies but may also help in selection of remediation strategies. The model may be presented well by using the Fault Tree Analysis (FTA) technique. It implements screening criteria and a tier-based approach in which wells are screened and categorized into different tiers based on different well characteristics. The well characteristics include the physical distance from injection wells, the quality and portion of cement coverage of wells in the target zone, the regulations at the time of well completion, the leakage potential of sealing barriers for the targeted zone, the number of overlying shale and sand intervals and leakage of either CO2 or brine to shallower wells, the nature and quality of permanent or temporary well abandonment procedures, and the quality and length of annular space covered with cement for shallower well casings or sections. Existing models for well leakage are used to quantitatively estimate the leakage rate. The risk of leakage is presented qualitatively and quantitatively in the form of leaked CO2 volume to shallow aquifers or to the atmosphere. The approach is used for a representative depleted oil and gas field in southern Louisiana to show an example application of the process. The developed model provides a means to systemically identify the wells that are more likely to leak and have high consequences. Due to the reduced order nature of the tool, it should prove to be a useful tool in the planning and execution phase of the CO2 sequestration process.
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.
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.
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.
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 oil reservoirs such as Bakken, Niobrara, and Eagle Ford have become the main target for oil and gas investors as conventional formations started to be depleted and diminished in number. These unconventional plays have a huge oil potential; however, the predicted primary oil recovery is still low as an average of 7.5 %. Injecting carbon dioxide (CO2) to enhance oil recovery in these poor-quality formations is still a debatable issue among investigators. In this study, three steps of research have been integrated to investigate the parameters which control the success of CO2 huff-n-puff process in the field scale of shale oil reservoirs. Firstly, a numerical simulation study was conducted to upscale the reported experimental studies outcomes to the field conditions. The second step was to validate these numerical models with the field data from some of CO2-EOR pilots which were performed in Bakken formation, in North Dakota and Montana regions. Finally, statistical methods for Design of Experiments (DOE) have been used to rank the most important parameters affecting CO2-EOR performance in these unconventional reservoirs.
The Design of Experiments approved that the intensity of natural fractures (the number of natural fractures per length unit in each direction, I-direction, J direction, and K direction) and the conductivity of oil pathways (the average conductivity for the entire oil molecules path, from its storage (matrix) to the wellbore) are the two main factors controlling CO2-EOR success in shale oil reservoirs. However, the fracture intensity has a positive effect on CO2-EOR while the later has a negative effect. Furthermore, this study found that the porosity and the permeability of natural fractures in shale reservoirs are clearly changeable with the production time, which in turn, led to a clear gap between CO2 performances in the lab conditions versus to what happened in the field pilots. This work reported that the molecular diffusion mechanism is the key mechanism for CO2 to enhance oil recovery in shale oil reservoirs. However, the conditions of the candidate field and the production well criteria can enhance or downgrade this mechanism in the field scale. Accordingly, the operating parameters for managing CO2-EOR huff-n-puff process should be tuned according to the candidate reservoir and well conditions. Moreover, general guidelines have been provided from this work to perform successful CO2 projects in these complex plays.
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.