Search Results (10)

Flue gas is an industrial waste gas produced by the combustion of fossil fuels. Its application in reservoir development can increase oil recovery factor and achieve underground storage of CO₂. Flue gas gravity flooding experiments were conducted to clarify the displacement and storage characteristics of flue gas gravity flooding. The results show that the experiment can be divided into three stages based on the output characteristics, and the oil recovery factor curve exhibits a stepwise increase. During the pure oil production stage, the crude oil output is approximately half of the total output. When the experimental pressure is 18 MPa, the oil recovery factor is 11.53%. As the experimental pressure increases, the extraction and viscosity reduction effects of the flue gas are enhanced. Therefore, the oil recovery factor gradually increases and the crude oil in the micropores and small pores is better displaced. The storage rate of flue gas is 8.42% at a pressure of 18 MPa. When the experimental pressure increases to 25 MPa, the storage rate of flue gas reaches 19.70%. The increase in permeability and the extension of displacement time can effectively improve the oil recovery factor. The research results provide a new approach for the resource utilization of flue gas and offer theoretical support for flue gas flooding in tight reservoirs. Full article

CO₂ flooding technology for tight oil reservoirs not only effectively addresses the challenge of low recovery rates, but also facilitates geological CO₂ sequestration, thereby achieving the dual objective of enhanced CO₂ utilization and secure storage. However, in the development of continental sedimentary tight oil reservoirs, the high content of heavy hydrocarbons in crude oil leads to an elevated minimum miscibility pressure (MMP) between crude oil and CO₂, thereby limiting the process to non-miscible flooding. Conventional physical and chemical methods, although effective in reducing MMP, are often associated with high costs, environmental concerns, and limited efficacy. To address these challenges, we propose a novel approach utilizing petroleum hydrocarbon-degrading bacteria (PHDB) to biodegrade heavy hydrocarbons in crude oil. This method alters the composition of crude oil, thereby lowering the MMP during CO₂ flooding, facilitating the transition from non-miscible to miscible flooding, and enhancing oil recovery. Results demonstrated that, after 7 days of cultivation, the selected PHDB achieved a degradation efficiency of 56.4% in crude oil, significantly reducing the heavy hydrocarbon content. The relative content of light-saturated hydrocarbons increased by 15.6%, and the carbon atom molar percentage in crude oil decreased from C8 to C6. Following the biodegradation process, the MMP of the lightened crude oil was reduced by 20.9%. Core flood experiments indicated that CO₂ flooding enhanced by PHDB improved oil recovery by 17.7% compared to conventional CO₂ flooding. This research provides a novel technical approach for the green and cost-effective development of tight oil reservoirs with CO₂ immiscible flooding. Full article

Global tight-oil reserves are abundant, but the depletion development of numerous tight-oil reservoirs remains unsatisfactory. CO₂ injection development represents a significant method of reservoir production, potentially facilitating enhanced oil recovery (EOR) alongside CO₂ storage. Currently, limited research exists on advanced CO₂ injection and well pattern adjustment aimed at improving the oil recovery and CO₂ storage within tight-oil reservoirs. This paper focuses on the examination of tight oil within the Ordos Basin. Through the employment of slim-tube experiments, long-core displacement experiments, and reservoir numerical simulations, the near-miscible pressure range and minimum miscible pressure (MMP) for the target block were ascertained. The viability of EOR and CO₂ sequestration via advanced CO₂ injection was elucidated, establishing well pattern adjustment methodologies to ameliorate CO₂ storage and enhance oil recovery. Simultaneously, the impacts of the injection volume and bottom-hole pressure on the development of advanced CO₂ injection were explored in further detail. The experimental results indicate that the near-miscible pressure range of the CO₂–crude oil in the study area is from 15.33 to 18.47 MPa, with an MMP of 18.47 MPa, achievable under reservoir pressure conditions. Compared to continuous CO₂ injection, advanced CO₂ injection can more effectively facilitate EOR and achieve CO₂ sequestration, with the recovery and CO₂ sequestration rates increasing by 4.83% and 2.29%, respectively. Through numerical simulation, the optimal injection volume for advanced CO₂ injection was determined to be 0.04 PV, and the most favorable bottom-hole flowing pressure was identified as 10 MPa. By transitioning from a square well pattern to either a five-point well pattern or a row well pattern, the CO₂ storage ratio significantly improved, and the gas–oil ratio of the production wells also decreased. Well pattern adjustment effectively supplements the formation energy, extends the stable production lives of production wells, and increases both the sweep efficiency and oil recovery. This study provides theoretical support and serves as a reference for CO₂ injection development in tight-oil reservoirs. Full article

Tight sandstone reservoirs are ideal locations for CO₂ storage. To evaluate the oil displacement efficiency and storage potential of CO₂ in the tight sandstone reservoir in the Huang 3 area of the Changqing Oilfield, four kinds of displacement experiments were conducted on core samples from the Chang 8 Formation in the Huang 3 area. These experiments were performed using micro-displacement equipment, digital core technology, and an online CT scanning system; the different oil displacement processes were recorded as three-dimensional images. The results show that the CO₂ flooding alternated with water scheme can improve crude oil recovery the most. Comparing the cores before and after the displacement shows that the amount of crude oil in pores with larger sizes decreases more. The remaining oil is mainly in thin films or is dispersed and star-shaped, indicating that the crude oil in the medium and large pores is swept and recovered. The CO₂ displacement efficiency is 41.67~55.08%, and the CO₂ storage rate is 38.16~46.89%. The proportion of remaining oil in the throat of the small and medium-sized pores is still high, which is the key to oil recovery in the later stages. Full article

Good tightness is one of the necessary conditions for an anhydrite mine-out space to be used for underground crude oil storage. Combining engineering geological surveys, laboratory tests, and numerical simulations, this paper quantitatively analyses the tightness of the Anhui Hengtai anhydrite mine-out under different working conditions and discusses its suitability for underground crude oil storage. Triaxial compression tests of anhydrite rock considering seepage were carried out to study its hydraulic and mechanical characteristics during failure. The permeability coefficient–strain empirical formula of anhydrite was constructed. A numerical simulation was carried out on the basis of the finite difference method to study the tightness of the rock surrounding the mine-out after excavation and under 0.2 MPa, 0.6 MPa, and 1.0 MPa storage pressures, respectively. The results showed that the permeability coefficient increased with increasing storage pressure, and the growth rate gradually slowed after the storage pressure reached a certain value. Overall, the mine-out had good tightness, and the permeability coefficient of the surrounding rock was small. This study demonstrated the feasibility of using the anhydrite mine-out for crude oil storage and provides a scientific basis for the site selection of underground crude oil storage. Full article

As the demands of tight-oil Enhanced Oil Recovery (EOR) and the controlling of anthropogenic carbon emission have become global challenges, Carbon Capture Utilization and Sequestration (CCUS) has been recognized as an effective solution to resolve both needs. However, the influential factors of carbon dioxide (CO₂) geological storage in low permeability reservoirs have not been fully studied. Based on core samples from the Huang-3 area of the Ordos Basin, the feasibility and influential factors of geological CO₂ sequestration in the Huang-3 area are analyzed through caprock breakthrough tests and a CO₂ storage factor experiment. The results indicate that capillary trapping is the key mechanism of the sealing effect by the caprock. With the increase of caprock permeability, the breakthrough pressure and pressure difference decreased rapidly. A good exponential relationship between caprock breakthrough pressure and permeability can be summarized. The minimum breakthrough pressure of CO₂ in the caprock of the Huang-3 area is 22 MPa, and the breakthrough pressure gradient is greater than 100 MPa/m. Huang-3 area is suitable for the geological sequestration of CO₂, and the risk of CO₂ breakthrough in the caprock is small. At the same storage percentage, the recovery factor of crude oil in larger permeability core is higher, and the storage percentage decreases with the increase of recovery factor. It turned out that a low permeability reservoir is easier to store CO₂, and the storage percentage of carbon dioxide in the miscible phase is greater than that in the immiscible phase. This study can provide empirical reference for caprock selection and safety evaluation of CO₂ geological storage in low permeability reservoirs within Ordos Basin. Full article

CO₂ enhanced oil recovery (EOR) has proven its capability to explore unconventional tight oil reservoirs and the potential for geological carbon storage. Meanwhile, the extremely low permeability pores increase the difficulty of CO₂ EOR and geological storage processing in the actual field. This paper initiates the ultrasonic-assisted approach to facilitate oil–gas miscibility development and finally contributes to excavating more tight oils. Firstly, the physical properties of crude oil with and without ultrasonic treatments were experimentally analyzed through gas chromatography (GC), Fourier-transform infrared spectroscopy (FTIR) and viscometer. Secondly, the oil–gas minimum miscibility pressures (MMPs) were measured from the slim-tube test and the miscibility developments with and without ultrasonic treatments were interpreted from the mixing-cell method. Thirdly, the nuclear-magnetic resonance (NMR) assisted coreflood tests were conducted to physically model the recovery process in porous media and directly obtain the recovery factor. Basically, the ultrasonic treatment (40 KHz and 200 W for 8 h) was found to substantially change the oil properties, with viscosity (at 60 °C) reduced from 4.1 to 2.8 mPa·s, contents of resin and asphaltene decreased from 27.94% and 6.03% to 14.2% and 3.79%, respectively. The FTIR spectrum showed that the unsaturated C-H bond, C-O bond and C≡C bond in macromolecules were broken from the ultrasonic, which caused the macromolecules (e.g., resin and asphaltenes) to be decomposed into smaller carbon-number molecules. Accordingly, the MMP was determined to be reduced from 15.8 to 14.9 MPa from the slim-tube test and the oil recovery factor increased by an additional 11.7%. This study reveals the mechanisms of ultrasonic-assisted CO₂ miscible EOR in producing tight oils. Full article

Using salt caverns for an underground strategic petroleum reserve (SPR) is considered as an ideal approach due to the excellent characteristics of low porosity, low permeability, self-healing of damage, and strong plastic deformation ability of rock salt. Salt deposits in China are mostly layered rock salt structures, with the characteristics of many interlayers, bringing great challenges for the construction of SPR facilities. Studying the microscopic pore characteristics of the rock surrounding SPR salt caverns in different environments (with brine and crude oil erosion) is necessary because the essence of mechanical and permeability characteristics is the macroscopic embodiment of the microscopic pore structure. In this paper, XRD tests and SEM tests are carried out to determine the physical properties of storage media and surrounding rock. Gas adsorption tests and mercury intrusion tests are carried out to analyze the microscopic pore structure, specific surface area variation and total aperture distribution characteristics of SPR salt cavern host rock. Results show that: (1) Large numbers of cores in interlayer and caprock may provide favorable channels for the leakage of high-pressure crude oil and brine. (2) The blockage of pores by macromolecular organic matter (colloid and asphaltene) in crude oil will not significantly change the structural characteristics of the rock skeleton, which is beneficial to the long-term operation of the SPR salt cavern. (3) The water–rock interaction will bring obvious changes in the micro-pore structure of rock and increase the leakage risk of the storage medium. The results can provide theoretical bases and methods for the tightness analysis of China’s first underground SPR salt cavern. Full article

The state of Oklahoma has experienced a dramatic increase in the amount of measurable seismic activities over the last decade. The needs of a petroleum-driven world have led to increased production utilizing various technologies to reach energy reserves locked in tight formations and stimulate end-of-life wells, creating significant amounts of undesirable wastewater ultimately injected underground for disposal. Using Phased Array L-band Synthetic Aperture Radar (PALSAR) data, we performed a differential Synthetic Aperture Radar Interferometry (InSAR) technique referred to as the Small BAseline Subset (SBAS)-based analysis over east central Oklahoma to identify ground surface deformation with respect to the location of wastewater injection wells for the period of December 2006 to January 2011. Our results show broad spatial correlation between SBAS-derived deformation and the locations of injection wells. We also observed significant uplift over Cushing, Oklahoma, the largest above ground crude oil storage facility in the world, and a key hub of the Keystone Pipeline. This finding has significant implications for the oil and gas industry due to its close proximity to the zones of increased seismicity attributed to wastewater injection. Results southeast of Drumright, Oklahoma represent an excellent example of the potential of InSAR, identifying a fault bordered by an area of subduction to the west and uplift to the east. This differentiated movement along the fault may help explain the lack of any seismic activity in this area, despite the large number of wells and high volume of fluid injected. Full article

American U.S. crude oil prices have dropped significantly of late down to a low of less than $30 a barrel in early 2016. At the same time price volatility has increased and crude in storage has reached record amounts in the U.S. America. Low oil prices in particular pose quite a challenge for the survival of U.S. America’s tight-oil industry. In this paper we assess the current profitability and future prospects of this industry. The question could be broadly stated as: should producers stop operation immediately or continue in the hope that prices will rise in the medium term? Our assessment is based on a stochastic volatility model with three risk factors, namely the oil spot price, the long-term oil price, and the spot price volatility; we allow for these sources of risk to be correlated and display mean reversion. We then use information from spot and futures West Texas Intermediate (WTI) oil prices to estimate this model. Our aim is to show how the development of the oil price in the future may affect the prospective revenues of firms and hence their operation decisions at present. With the numerical estimates of the model’s parameters we can compute the value of an operating tight-oil field over a certain time horizon. Thus, the present value (PV) of the prospective revenues up to ten years from now is $37.07/bbl in the base case. Consequently, provided that the cost of producing a barrel of oil is less than $37.07 production from an operating field would make economic sense. Obviously this is just a point estimate. We further perform a Monte Carlo (MC) simulation to derive the risk profile of this activity and calculate two standard measures of risk, namely the value at risk (VaR) and the expected shortfall (ES) (for a given confidence level). In this sense, the PV of the prospective revenues will fall below $22.22/bbl in the worst 5% of the cases; and the average value across these worst scenarios is $19.77/bbl. Last we undertake two sensitivity analyses with respect to the spot price and the long-term price. The former is shown to have a stronger impact on the field’s value than the latter. This bodes well with the usual time profile of tight oil production: intense depletion initially, followed by steep decline thereafter. Full article