Search Results (14)

Several methods are currently used to test offshore tight reservoirs. However, the effectiveness of these applications varies among wells, and some exhibit unclear reservoir classifications. These issues lead to difficulties in decision-making during tests and result in higher testing costs. Therefore, to address this issue, this study used reservoirs in the Liushagang Formation of the Beibu Basin as the research object and employed core data to apply the multi-stage FZI method. This method computes the FZI and its cumulative probability, classifying the target reservoir into seven distinct types. According to the Winland R₃₅ method, the target reservoir was classified into five distinct types. Seven characteristic parameters were selected based on the mercury injection experimental data. The K-means clustering method was then used to classify the target reservoirs into two types. The conclusions were that, in this formation, there is predominantly low to extra-low porosity and extra-low to ultra-low permeability. According to relationship models, logged porosity can be used to calculate effective permeability. Combining the multi-stage FZI method with the K-means clustering method for reservoir classification is recommended. This integrated approach facilitates a more comprehensive analysis of the characteristics of offshore low-permeability tight reservoirs at both macro and micro scales after classification. This research provides key insights for enhancing offshore well production. Full article

Carbon Capture, Utilization, and Storage (CCUS) stands as one of the effective means to reduce carbon emissions and serves as a crucial technical pillar for achieving experimental carbon neutrality. CO₂-enhanced oil recovery (CO₂-EOR) represents the foremost method for CO₂ utilization. CO₂-EOR represents a favorable technical means of efficiently developing extra-low-permeability reservoirs. Nevertheless, the process known as the direct injection of CO₂ is highly susceptible to gas scrambling, which reduces the exposure time and contact area between CO₂ and the extra-low-permeability oil matrix, making it challenging to utilize CO₂ molecular diffusion effectively. In this paper, a comprehensive study involving the application of a CO₂ nanobubble system in extra-low-permeability reservoirs is presented. A modified nano-SiO₂ particle with pro-CO₂ properties was designed using the Pickering emulsion template method and employed as a CO₂ nanobubble stabilizer. The suitability of the CO₂ nanobubbles for use in extra-low-permeability reservoirs was evaluated in terms of their temperature resistance, oil resistance, dimensional stability, interfacial properties, and wetting-reversal properties. The enhanced oil recovery (EOR) effect of the CO₂ nanobubble system was evaluated through core experiments. The results indicate that the CO₂ nanobubble system can suppress the phenomena of channeling and gravity overlap in the formation. Additionally, the system can alter the wettability, thereby improving interfacial activity. Furthermore, the system can reduce the interfacial tension, thus expanding the wave efficiency of the repellent phase fluids. The system can also improve the ability of CO₂ to displace the crude oil or water in the pore space. The CO₂ nanobubble system can take advantage of its size and high mass transfer efficiency, among other advantages. Injection of the gas into the extra-low-permeability reservoir can be used to block high-gas-capacity channels. The injected gas is forced to enter the low-permeability layer or matrix, with the results of core simulation experiments indicating a recovery rate of 66.28%. Nanobubble technology, the subject of this paper, has significant practical implications for enhancing the efficiency of CO₂-EOR and geologic sequestration, as well as providing an environmentally friendly method as part of larger CCUS-EOR. Full article

The Lunnan oilfield, nestled within the Tarim Basin, represents a prototypical extra-low-permeability sandstone reservoir, distinguished by high-quality crude oil characterised by a low viscosity, density, and gel content. The effective exploitation of such reservoirs hinges on the implementation of carbon dioxide (CO₂) flooding techniques. This study, focusing on the sandstone reservoirs of Lunnan, delves into the mechanisms of CO₂-assisted oil displacement under diverse operational parameters: injection pressures, CO₂ concentration levels, and variations in crude oil properties. It integrates analyses on the high-pressure, high-temperature behaviour of CO₂, the dynamics of CO₂ injection and expansion, prolonged core flood characteristics, and the governing principles of minimum miscible pressure transitions. The findings reveal a nuanced interplay between variables: CO₂’s density and viscosity initially surge with escalating injection pressures before stabilising, whereas they experience a gradual decline with increasing temperature. Enhanced CO₂ injection correlates with a heightened expansion coefficient, yet the density increment of degassed crude oil remains marginal. Notably, CO₂ viscosity undergoes a substantial reduction under stratigraphic pressures. The sequential application of water alternating gas (WAG) followed by continuous CO₂ flooding attains oil recovery efficiency surpassing 90%, emphasising the superiority of uninterrupted CO₂ injection over processes lacking profiling. The presence of non-miscible hydrocarbon gases in segmented plug drives impedes the oil displacement efficiency, underscoring the importance of CO₂ purity in the displacement medium. Furthermore, a marked trend emerges in crude oil recovery rates as the replacement pressure escalates, exhibiting an initial rapid enhancement succeeded by a gradual rise. Collectively, these insights offer a robust theoretical foundation endorsing the deployment of CO₂ flooding strategies for enhancing oil recovery from sandstone reservoirs, thereby contributing valuable data to the advancement of enhanced oil recovery (EOR) technologies in challenging, low-permeability environments. Full article

Bohai X oilfield has reached the extra-high water cut stage of more than 95%, dominated by the bottom water reservoir. The oilfield mainly adopts horizontal-well exploitation, with the characteristics of high difficulty and low success rate for well water plugging. To solve the above problem, the segmented production technology of horizontal wells was developed to guide oilfield applications and tap their potential. In the segmented design stage, the horizontal section is objectively segmented by drilling condition analysis, optimally based on drilling through interlayers or permeability discrepancy formation, simultaneously combined with the numerical simulation method. When implementing measures, annulus chemical packer materials are squeezed between segments to effectively inhibit the fluid flow between the open hole and the sand-packing screen pipe. Moreover, the packers are used to seal between segments to effectively restrain the flow between the screen and the central tube, achieving the establishment of compartments. In the production process, the valve switch on the central tube can be independently controlled by a remotely adjustable method to achieve optimal production. This segmented production technology was successfully tested for the first time in Bohai oilfield. Up to now, a total of six compartment measures have been implemented, remarkably decreasing water cut and increasing oil production for horizontal wells in the bottom water reservoir. This method does not require water testing, and the optimal production section can be chosen through segmented independent production, greatly improving the success rate of water-plugging measures for horizontal wells. This technology opens up a new mode for the efficient development of horizontal wells in bottom water reservoirs and is planned to be widely promoted and applied in similar oilfields. Full article

Extralow-permeability reservoirs have emerged as a significant area of focus for CO₂ geological sequestration due to their stable subterranean structure and expansive storage capacity, offering substantial potential in addressing global climate change. However, the full extent of CO₂ geological sequestration potential within these extralow-permeability reservoirs remains largely unexplored. To address this gap, this paper utilizes the Shahejie Formation (Es1 member) of the Shuang 229 block in the Liaohe oilfield, Bohai Bay Basin, as a case study. This section is characterized by its abundant oil-gas reserves and serves as an exemplar for conducting experimental research on CO₂ storage within extralow-permeability reservoirs. The results demonstrate that the reservoir lithology of the Es1 member is fine sandstone and siltstone, with high compositional and structural maturity. Moreover, the average porosity is 14.8%, the average permeability is 1.48 mD, and the coefficient of variation of the reservoir is approximately 0.5, which indicates a low- to extralow-permeability homogeneous reservoir. In addition, the overburden pressure is >2.0 MPa, the fault can withstand a maximum gas column height of >200 m, and the reservoir exhibits favorable overburden and fault sealing characteristics. Notably, stepwise increasing gas injection in the Shuang 229-36-62 well reveals that the injected liquid CO₂ near the wellhead exhibits a relatively high density, close to 1.0 g/cm³, which gradually decreases to approximately 0.78 g/cm³ near a depth of 2000 m underground. The injected fluid changes into a supercritical state upon entering the formation, and the CO₂ injection speed is optimal, at 0.08 HCPV/a. According to these findings, it is predicted that the highest burial CO₂ volume via the injection of 1.5 HCPVs in the Wa 128 block area is 1.11 × 10⁵ t/year, and the cumulative burial volume reaches approximately 2.16 × 10⁶ t. This shows that the CO₂ sequestration potential of extralow-permeability reservoirs is considerable, providing confidence for similar instances worldwide. Full article

Core analysis is an accurate and direct method for finding the physical properties of oil and natural gas reservoirs. However, in some cases coring is time consuming and difficult, and only cuttings with the drilling fluid can be obtained. It is important to determine whether cuttings can adequately represent formation properties such as porosity, permeability, and pore size distribution (PSD). In this study, seven limestone samples with different sizes were selected (Cubes: 4 × 4 × 4 cm, 4 × 4 × 2 cm, 4 × 2 × 2 cm and 2 × 2 × 2 cm, Core: diameter of 2.5 cm and a length of 5 cm, Cuttings: 1–1.7 mm and 4.7–6.75 mm in diameter), and low-field nuclear magnetic resonance (NMR) measurements were performed on these samples to obtain porosity, PSD, and permeability. The results showed that the porosity of cubes and cuttings with different sizes are consistent with cores, which is about 1%. Whereas the PSDs and permeabilities of the two cutting samples (less than in size 6.75 mm) differ significantly within cores. It is suggested that interparticle voids and mechanical pulverization during sample preparation have a negligible effect on porosity and a larger effect on PSD and permeability. Combined with factors such as wellbore collapse and mud contamination suffered in the field, it is not recommended to use cuttings with a particle size of less than 6.75 mm to characterize actual extra-low porosity and extra-low permeability formation properties. Full article

The micro distribution of residual oil in low-permeability sandstone reservoirs is closely related to pore structure, and the differences in pore structure often determine the reservoir’s productivity and development effectiveness from a macro perspective. On the basis of in-depth research, this paper analyzes the distribution law of the remaining microscopic oil, establishes the digital core multi-stage pore network modeling of the strongly sorted heterogeneous conglomerate reservoir in the Lower Wuerhe Formation of Block 8 of the Karamay Oilfield, the three-phase seepage simulation method considering the release of dissolved gas, and the three-phase permeability curve test. The research results are as follows: (1) Conventional physical property analysis shows that the permeability of core samples exhibits an inverse rhythmic distribution with layer depth. (2) CT core analysis and mercury injection experiments indicate that the area with porosity ranging from 9% to 21% accounts for 79% and is the main seepage channel area. Larger pores play an important role in seepage. (3) Through comparative experiments on cores with different permeability, it was found that the degassing phenomenon of low-permeability rock samples is more severe. In the actual process of reservoir development, it is necessary to reasonably handle the impact of water injection on development effectiveness, select appropriate water injection methods and cycles, and avoid premature water breakthrough in ultra low-permeability reservoirs. Full article

Conventional numerical solutions and empirical formulae for predicting the initial productivity of oil wells in low-permeability reservoirs are limited to specific reservoirs and relatively simple scenarios. Moreover, the few influencing factors are less considered and the application model is more ideal. A productivity prediction method based on machine learning algorithms is established to improve the lack of application performance and incomplete coverage of traditional mathematical modelling for productivity prediction. A comprehensive analysis was conducted on the JY extra-low-permeability oilfield, considering its geological structure and various factors that may impact its extraction and production. The study collected 13 factors that influence the initial productivity of 181 wells. The Spearman correlation coefficient, ReliefF feature selection algorithm, and random forest selection algorithm were used in combination to rank the importance of these factors. The screening of seven main controlling factors was completed. The particle swarm optimization–extreme learning machine algorithm was adopted to construct the initial-productivity model. The primary control factors and the known initial productivity of 127 wells were used to train the model, which was then used to verify the initial productivity of the remaining 54 wells. In the particle swarm optimization–extreme learning machine (PSO-ELM) algorithm model, the root-mean-square error (RMSE) is 0.035 and the correlation factor (R²) is 0.905. Therefore, the PSO-ELM algorithm has a high accuracy and a fast computing speed in predicting the initial productivity. This approach will provide new insights into the development of initial-productivity predictions and contribute to the efficient production of low-permeability 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

Natural gas hydrate is considered as a potential energy resource. To develop technologies for the exploitation of natural gas hydrate, several field gas production tests have been carried out in permafrost and continental slope sediments. However, the gas production rates in these tests were still limited, and the low permeability of the hydrate-bearing sediments is identified as one of the crucial factors. Artificial fracturing is proposed to promote gas production rate by improving reservoir permeability. In this research, numerical studies about the effect of fracture length and fluid conductivity on production performance were carried out on an artificially fractured Class 3 hydrate reservoir (where the single hydrate zone is surrounded by an overlaying and underlying hydrate-free zone), in which the equivalent conductivity method was applied to depict the artificial fracture. The results show that artificial fracture can enhance gas production by offering an extra fluid flow channel for the migration of gas released from hydrate dissociation. The effect of fracture length on production is closely related to the time frame of production, and gas production improvement by enlarging the fracture length is observed after a certain production duration. Through the production process, secondary hydrate formation is absent in the fracture, and the high conductivity in the fracture is maintained. The results indicate that the increase in fracture conductivity has a limited effect on enhancing gas production. Full article

The Upper Jurassic, shallow marine Corallian sandstones of the Weald Basin, UK, are significant onshore reservoirs due to their future potential for carbon capture and storage (CCS) and hydrogen storage. These reservoir rocks, buried to no deeper than 1700 m before uplift to 850 to 900 m at the present time, also provide an opportunity to study the pivotal role of shallow marine sandstone eodiagenesis. With little evidence of compaction, these rocks show low to moderate porosity for their relatively shallow burial depths. Their porosity ranges from 0.8 to 30% with an average of 12.6% and permeability range from 0.01 to 887 mD with an average of 31 mD. The Corallian sandstones of the Weald Basin are relatively poorly studied; consequently, there is a paucity of data on their reservoir quality which limits any ability to predict porosity and permeability away from wells. This study presents a potential first in the examination of diagenetic controls of reservoir quality of the Corallian sandstones, of the Weald Basin’s Palmers Wood and Bletchingley oil fields, using a combination of core analysis, sedimentary core logs, petrography, wireline analysis, SEM-EDS analysis and geochemical analysis to understand the extent of diagenetic evolution of the sandstones and its effects on reservoir quality. The analyses show a dominant quartz arenite lithology with minor feldspars, bioclasts, Fe-ooids and extra-basinal lithic grains. We conclude that little compactional porosity-loss occurred with cementation being the main process that caused porosity-loss. Early calcite cement, from neomorphism of contemporaneously deposited bioclasts, represents the majority of the early cement, which subsequently prevented mechanical compaction. Calcite cement is also interpreted to have formed during burial from decarboxylation-derived CO₂ during source rock maturation. Other cements include the Fe-clay berthierine, apatite, pyrite, dolomite, siderite, quartz, illite and kaolinite. Reservoir quality in the Corallian sandstones show no significant depositional textural controls; it was reduced by dominant calcite cementation, locally preserved by berthierine grain coats that inhibited quartz cement and enhanced by detrital grain dissolution as well as cement dissolution. Reservoir quality in the Corallian sandstones can therefore be predicted by considering abundance of calcite cement from bioclasts, organically derived CO₂ and Fe-clay coats. Full article

In order to effectively evaluate shale gas reservoirs with low porosity, extra-low permeability, and no natural productivity, dipole array acoustic logging, which can provide various types of information including P-wave slowness (DTC) and S-wave slowness (DTS), is widely used. As the dipole array acoustic logging tool has a larger investigation depth and is suitable for complex borehole environments, such as those with a high wellbore temperature, high drilling fluid column pressure, or irregular borehole wall, it has been mainly applied to the evaluation of lithology, gas potential, fractures, and stimulation potential in shale gas reservoirs. The findings from a case study of the Sichuan Basin in China reveal that the acoustic slowness, S-P wave slowness ratio (RMSC), and S-wave anisotropy of the dipole array acoustic logging can be used to qualitatively identify reservoir lithology, gas potential, and fractures. Using the relationship between DTC and the total porosity of shale gas reservoirs, and combined with the compensated neutron (CNL) and shale content (V_sh) of the reservoir, a mathematical model for accurately calculating the total porosity of the shale gas reservoir can be established. By using the relationship between the RMSC and gas saturation in shale gas reservoirs and tied with density log (DEN), a mathematical model of gas saturation can be established, and the determination of gas saturation by the non-resistivity method can be achieved, delivering a solution to the issue that the electric model is not applicable under low resistivity conditions. The DTS, DTC, and DEN of shale can be used to calculate rock mechanic parameters such as the Poisson’s ratio (POIS) and Young’s modulus (YMOD), which can be used to evaluate the shale stimulation potential. Full article

CO₂ and N₂ injection is an effective enhanced oil recovery technology in the oilfield especially for low-permeability and extra low-permeability reservoirs. However, these processes can induce an asphaltene deposition during oil production. Asphaltene-deposition-induced formation damage is a fairly severe problem. Therefore, predicting the likelihood of asphaltene deposition in reservoir conditions is crucial. This paper presents the results of flash separation experiments used to investigate the composition of crude oil in shallow and buried-hill reservoirs. Then, PVTsim Nova is used to simulate the composition change and asphaltene deposition of crude oil. Simulation tests indicate that the content of light components C₁-C₄ and heavy components C₃₆₊ decrease with increasing CO₂ and N₂ injection volumes. However, the extraction of CO₂ is significantly stronger than that of N₂. In shallow reservoirs, as the CO₂ injection volume increases, the deposition pressure range decreases and asphaltenes are easily deposited. Conversely, the asphaltene deposition pressure of crude oil injected with N₂ is higher and will not cause serious asphaltene deposition. When the CO₂-N₂ injection ratio reaches 1:1, the deposition pressure range shows a significant transition. In buried-hill reservoirs, asphaltene deposition is unlikely to occur with CO₂, N₂, and a gas mixture injection. Full article

The development effect of water flooding in an ultra-low permeability reservoir is poor due to its poor physical properties and high shale content, so an experimental study of air flooding which helps to complement energy production was carried out. Based on the Accelerating Rate Calorimeter experimental results, the crude oil of N block in L oilfield can undergo low-temperature oxidation reactions, which are the basic condition for air flooding. Three groups of experimental natural cylinder cores designed for oil displacement, water flooding and air flooding were used respectively, and the relationship between differential pressure, oil recovery, injection capacity with injection volume was investigated. It is observed that the recovery efficiency increased 2.58%, the injection-production pressure difference dropped 60% and the injection capability increased 60% in the experiment of shifting air flooding after water flooding to 75% moisture content, compared with water flooding alone. It has been shown in the results that the recovery efficiency improved sharply more than water flooding, the effect of depressurization and augmented injection was obvious, and the air displacement was thus validated. We suggest that other science and technology workers should perform further tests and verify this result through numerical simulation. Full article