Search Results (25)

Shallow gas is an unconventional natural gas resource with great potential and has received growing attention recently. Accurate estimation of gas saturation is crucial for reserves assessments and for development program formulations. However, such reservoirs are characterized by weak diagenesis, a high clay content, and low resistivity. These properties pose significant challenges for saturation evaluations. To address the challenge of insufficient accuracy in evaluating the saturation of gas-bearing reservoirs, we propose an acoustic-based saturation evaluation method. In this study, a shallow unconsolidated rock physics model is first constructed to investigate the effect of variations in the gas saturation on elastic wave velocities. The model especially considers the patchy distribution of fluids within pores. In addition, we propose an iterative algorithm based on the updated relationship between porosity and gas saturation by introducing a correction term for the saturation to the density porosity, and successfully apply it to the logging data collected from the shallow gas reservoirs in the Pearl River Mouth Basin of the South China Sea. It is evident from the results that the saturation derived from the array acoustic logs is comparable to that obtained from the resistivity logs, with a mean absolute error of less than 6%. Additionally, it is also consistent with the drill stem test (DST) data, which further verifies the validity and reliability of this method. This study provides a novel non-electrical method for estimating the saturation of shallow gas reservoirs, which is essential to promote the evaluation of unconsolidated sandstone gas reservoirs. Full article

Studies have demonstrated that heavy oil flow exhibits threshold pressure gradient (TPG) which is closely related to the permeability and viscosity of the crude oil. Also, long-term water flooding continuously alters unconsolidated sandstone reservoir permeability through water flushing. These combined effects significantly influence water flooding performance. Therefore, in this paper, a comprehensive oil–water two phase mathematical model is developed for waterflooded heavy oil unconsolidated sandstone reservoirs based on the traditional black oil model, incorporating both time-varying permeability and threshold pressure gradient. The water-flooding-dependent threshold pressure gradient is firstly proposed, accounting for time-varying permeability. Subsequently, a simulator is developed with finite volume and Newton iteration method. Good agreement is obtained with the commercial simulator based on traditional black oil model. Afterward, the influence of permeability time variation and threshold pressure gradient is analyzed in detail. Results demonstrate that the threshold pressure gradient and time-varying permeability both decrease the oil recovery. The threshold pressure gradient (TPG) reduces the oil flow region and displacement efficiency since production. The increases in permeability after long term water flooding exacerbate reservoir heterogeneity and reduce sweep efficiency. The lowest oil recovery is observed when non-Darcy flow and permeability time variation are considered simultaneously. Furthermore, the time-varying threshold pressure gradient is observed with permeability time variation. Finally, a field data history matching was successfully performed, demonstrating the practical applicability of the proposed model. This new model better aligns with reservoir development characteristics. It can provide a theoretical guide for the development of heavy oil reservoirs. Full article

One of the limitations of Cold Heavy Oil Production with Sand (CHOPS) is the low recovery factor (5–15%). To target the remaining 85–95% heavy oil resources, several enhanced oil recovery (EOR) techniques, such as cyclic solvent injection (CSI), have been proposed. Due to its potential success in Canada and elsewhere, this paper reviews the technical and efficiency requirements of CSI EOR in post-CHOPS heavy oil reservoirs. We explain the dominant driving mechanisms of CSI with a focus on the application of CO₂ as a solvent. Limitations of current thermal and non-thermal EOR methods were compared to the CSI in thin oil reservoirs. To complete the assessment, several case studies and lessons learned were included based on the latest laboratory experiments, numerical studies, and CSI pilot/field tests. Specific to thin and shallow heavy oil reservoirs with sand production (e.g., CHOPS), the key to recover incremental oil was found to re-energize depleted reservoirs in a cyclic manner with unexpensive solvents (e.g., CO₂). Regarding the solvent use, laboratory experiences have not been conclusive about what solvent stream could improve oil recovery. To this end, successful field scale CO₂ EOR applications have been reported in several post-CHOPS reservoirs indicating that highly productive wells during primary production might also outperform during a follow up CSI process. Numerical modeling still faces challenges to properly model the main CSI driving mechanisms, including fluid–solvent interaction and the deformation of subsurface reservoirs. Full article

Lithuania is a Baltic European country which shares borders with Poland, Belarus, Latvia, and Russia and has a geothermal anomaly in the southwestern region. It consists of two main geothermal complexed, i.e., Devonian and Cambrian with a temperature of up to 40 °C (at a depth of 1000 m) and 96 °C (at a depth of 2000 m), respectively. The Devonian complex is composed of an unconsolidated sandstone formation with porosity and permeability in the range of 4–31% and 200 mD–6000 mD, respectively, and these make it a favorable candidate for a low enthalpy geothermal complex because of the high water production rates. This study evaluates the geothermal potential in the Devonian complex of the selected sites for commercial development. The study utilizes the mechanistic modelling approach including uncertainty management to forecast the water production rates and estimate the power generation capacity. Lastly, the study reveals that it is feasible to produce 6 MW to 60 MW of power from the existing vertical wells for a period of 25 years. Furthermore, reactive transport modelling also proves that there is dissolution and precipitation of the minerals near and away from the wellbore, respectively, which impairs the reservoir quality and further concludes that there is an effect of time on re-injection which should be considered to enhance the reservoir quality for future operations. In addition to that, no effect of the re-injection temperature of the produced water is observed. Full article

One of the most challenging aspects of manipulating the flow of fluids in subsurfaces is to control their flow direction and flow behavior. This can be especially challenging for compressible fluids, such as CO₂, and for multiphase flow, including both water and carbon dioxide (CO₂). This research studies the ability of two crosslinked polymers, including hydrolyzed polyacrylamide and acrylic acid/hydrolyzed polyacrylamide crosslinked polymers, to reduce the permeability of both CO₂ and formation water using different salinities and permeability values and in the presence of crude oil under different injection rates. The result showed that both polymers managed to reduce the permeability of water effectively; however, their CO₂ permeability-reduction potential was much lower, with the CO₂ permeability reduction being less than 50% of the water reduction potential in the majority of the experiments. This was mainly due to the high flow rate of the CO₂ compared to the water, which resulted in significant shearing of the crosslinked polymer. The crosslinked polymers’ swelling ratios were impacted differently based on the salinity, with the maximum swelling ratio being 9.8. The HPAM polymer was negatively affected by the presence of crude oil, whereas increasing salinity improved its performance greatly. All in all, both polymers had a higher permeability reduction for the formation water compared to CO₂ under all conditions. This research can help improve the applicability of CO₂-enhanced oil recovery and CO₂ storage in depleted oil reservoirs. The ability of the crosslinked polymers to improve CO₂ storage will be a main focus of future research. Full article

Accurate estimation of in-situ stresses is a critical parameter for geo-mechanical modelling. In-situ stresses are estimated in the field from logs and frac tests. Laboratory tests are performed with cored material to estimate horizontal stress changes under defined boundary conditions to complement field data. Horizontal stress path coefficient is used to estimate a change in in-situ stresses as the reservoir undergoes depletion or injection. Uniaxial Strain boundary conditions are representative of far field stress state. The laboratory data provides the change in horizontal stress with a change in pore pressure. It is used to complement the field data acquisition of absolute stress values to predict the value of total stresses. This experimental study provides a novel method of simulating geological compaction for fabricating representative samples from unconsolidated sands. It investigates the variability of horizontal stress path coefficient as a function of changing pore pressure (depressurization and re-pressurization) in unconsolidated sandstone reservoirs. Synthetic sandstones samples were made from sand packs by consolidating them under an isostatic stress path at ambient pore pressure. After getting to initial reservoir conditions, a series of pore pressure depletion and injection tests with varying magnitudes (injection and depletion) were performed to study the effects of stress path direction and associated hysteresis. The magnitude of the stress path coefficient under depletion is lower than that under injection for the first load-unload cycle. In subsequent load-unload cycles, the stress path coefficient values remain constant until the sample is depleted to a new level of pore pressure. A Modified Cam Clay model is fit to the data to map the expansion of the yield surface and quantify the model parameters. Application of this research includes accurate prediction of changes in-situ stresses during depletion and injection stress paths for simulating unconsolidated reservoirs behavior under fluid injection or further depletion. Full article

In order to comprehensively understand the complex fracture mechanisms in thick and loose sandstone formations, we have carefully developed a coupled finite element numerical model that captures the complex interactions between fluid flow and solid deformation. This model is the cornerstone of our future exploration. Based on this model, the crack propagation problem of hydraulic fracturing under different engineering and geological conditions was studied. In addition, we conducted in-depth research on the key factors that shape the geometry of hydraulic fractures, revealing their subtle differences and complexities. It is worth noting that the sharp contrast between the stress profile and mechanical properties between the production layer and the boundary layer often leads to fascinating phenomena, such as the vertical merging of hydraulic fracture propagation. The convergence of cracks originating from adjacent layers is a recurring theme in these strata. Sensitivity analysis clarified our understanding, revealing that increased elastic modulus promotes longer crack propagation paths. As the elastic modulus increases from 12 GPa to 18 GPa, overall, the maximum crack width slightly decreases, with a less than 10% reduction rate. The increased fluid leakage rate will significantly shorten the length and width of hydraulic fractures (with a maximum decrease of over 70% in fracture width). The increase in viscosity of fracturing fluid causes a change in fracture morphology, with a reduction in length of about 32% and an increase in fracture width of about 25%. It is worth noting that as the leakage rate of fracturing fluid increases, the importance of the viscosity of fracturing fluid decreases relatively. Strategies such as increasing fluid viscosity or adding anti-filtration agents can alleviate these challenges and improve the efficiency of fracturing fluids. In summary, our research findings provide valuable insights that can provide information and optimization for hydraulic fracturing filling and fracturing strategies in loose sandstone formations, promoting more efficient and influential oil and gas extraction work. Full article

The primary factor constraining the performance of unconsolidated sandstone reservoirs is blockage from particle migration, which reduces the capacity of liquid production. By utilizing logging, seismic, core–testing, and oil–well production data, the reservoir damage induced by particle migration in the Bohai A oilfield was characterized and predicted through combined well–seismic methods. This research highlights the porosity, permeability, median grain diameter, and pore structure as the primary parameters influencing reservoir characteristics. Based on their permeability differences, reservoirs can be categorized into Type I (permeability ≥ 800 mD), Type II (400 mD < permeability < 800 mD), and Type III (permeability ≤ 400 mD). The results of the core displacement experiments revealed that, compared to their initial states, the permeability change rates for Type I and Type II reservoirs exceeded 50%, whereas the permeability change rate for Type III reservoirs surpassed 200%. Furthermore, by combining this quantitative relationship model with machine learning techniques and well–seismic methods, the distribution of permeability change rates caused by particle migration across the entire region was successfully predicted and validated against production data from three oil wells. In addition, to build a reliable deep learning model, a sensitivity analysis of the hyperparameters was conducted to determine the activation function, optimizer, learning rate, and neurons. This method enhances the prediction efficiency of reservoir permeability changes in offshore oilfields with limited coring data, providing important decision support for reservoir protection and field development. Full article

The world-class Jinding deposit in SW China has ~15 Mt of Zn and Pb metals combined, in an evaporite dome containing amounts of gypsum/anhydrite. These gypsum and anhydrite are mainly located in limestone breccias (Member I), gypsum-bearing complexes (Member III), and red mélange, with some occurring as veins in clast-free sandstone (Member IV) and as fractures/vugs of host rock. The gypsum/anhydrite and dome genesis remain equivocal. The gypsum in limestone breccias and in red mélange with flow texture contains numerous Late Triassic Sanhedong limestone fragments. The δ³⁴S (14.1%–17%), δ¹⁸O (9.7%–14.6%), and ⁸⁷Sr/⁸⁶Sr ratios (0.706913–0.708711) of these gypsum are close to the S-O-Sr isotopes of the Upper Triassic Sanhedong Formation anhydrite in the Lanping Basin (δ³⁴S = 15.2%–15.9%, δ¹⁸O = 10.9%–13.1%, ⁸⁷Sr/⁸⁶Sr = 0.707541–0.707967), and are inconsistent with the Paleocene Yunlong Formation gypsum in the Lanping Basin (⁸⁷Sr/⁸⁶Sr = 0.709406–0.709845), indicating that these gypsum were derived from the Upper Triassic Sanhedong Formation evaporite but not from the Paleocene Yunlong Formation, and formed as a result of evaporite diapirism. The δ³⁴S (14.3%–14.5%), δ¹⁸O (10.1%–10.3%), and ⁸⁷Sr/⁸⁶Sr ratios (0.709503–0.709725) of gypsum as gypsum–sand mixtures in gypsum-bearing complexes are similar to the ⁸⁷Sr/⁸⁶Sr ratios of gypsum in the Yunlong Formation of the Lanping Basin and Cenozoic basins in the northern part of the Himalayan–Tibetan orogen, suggesting that the material source of this gypsum was derived from the Yunlong Formation, and formed as a result of gypsum–sand diapirism. The gypsum veins in clast-free pillow-shaped mineralized sandstone and the gypsum in host rock fractures and vugs formed after the supergene minerals such as smithsonite. The δ³⁴S (−16.3%~−12.7%) and δ¹⁸O (−9.8%~−4.7%) of this gypsum indicate that the gypsum is of supergene origin with sulfate derived from the reoxidation of reduced sulfur. We confirmed that the Jinding dome is genetically related to diapir of the Late-Triassic Sanhedong Formation evaporite. Clast-free sandstone and gypsum-bearing complexes in the dome were produced by diapir of the Paleocene Yunlong Formation unconsolidated gypsum–sand mixtures. Full article

Hydraulic fracturing is one of the most effective stimulation methods for unconsolidated sandstone reservoirs. However, the design of hydraulic fracturing must take into account the mechanical and stress properties of different geological formations between layers. In this paper, a three-dimensional coupled fluid-solid model using the finite element method is developed to investigate multiple vertical fractures at different depths along a vertical wellbore under different geological and geomechanical conditions. The finite element model does not require further refinement of any new cracks, requiring much smaller degrees of freedom and higher computational efficiency. In addition, new elements were used to account for local pressure drop due to perforation entry friction along the vertical wellbore. Numerical simulation results indicate that hydraulic fracture connections are observed from adjacent layers. Furthermore, the low stress contrast and high Young’s modulus between the layers increases the likelihood of multiple fracture connections. Higher fluid leakage rates increase the likelihood of fracture branching, but decrease the area of fracture coverage near the wellbore. Increasing fluid viscosity is effective in improving the area of fracture coverage near the wellbore. These findings are useful for the design of hydraulic fracturing in multi-layered formations in unconsolidated sandstone formations. Full article

The Sebei gas field is in the Sanhu depression area of the Qaidam Basin, which is the main gas-producing area and a key profit pillar for the Qinghai oilfield. The Sebei gas field within the Qinghai oilfield is characterized by high mud content, poor lithology, interflow between gas and water layers, and a propensity for sand production. The reservoir rocks are predominantly argillaceous siltstone with primarily argillaceous cement. These rocks are loose and tend to produce sand, which can lead to blockage. During its development, the Sebei gas field exhibited significant issues with scale formation and sand production in gas wells. Conventional acidization technologies have proven to be slow acting and may even result in adverse effects. These methods can cause loose sandstone to disperse, exacerbating sand production. Therefore, it is necessary to elucidate the mechanisms of wellbore plugging and to develop an acidizing system for plug removal that is tailored to unconsolidated sandstone reservoirs. Such a system should not only alleviate gas well plugging damage but also maintain reservoir stability and ensure efficient and sustained stimulation from acidization treatments. In this paper, the stability of unconsolidated sandstone reservoirs and the acid dissolution plugging system, along with the technological methods for stabilizing sand bodies, are studied through mineral component analysis, acid dissolution experiments, core immersion experiments, and other laboratory tests. The principle of synergistic effects between different acids is applied to achieve “high-efficiency scale dissolution and low sandstone dissolution”. Three key indicators of dispersion, sand dissolution rate, and scale dissolution rate were created. The acid plugging solution formula of “controlled dispersion and differentiated dissolution” was developed to address these indicators. Laboratory tests have shown that the sandstone is predominantly composed of quartz and clay minerals, with the latter mainly being illite. The primary constituent of the wellbore blockage scale sample is magnesium carbonate, which exhibits nearly 100% solubility in acid. By adding a stabilizer prior to acid corrosion, the core’s corrosion can be effectively mitigated, particle dispersion and migration can be controlled, and the rock structure’s stability can be maintained. Laboratory evaluations indicate that the scale dissolution rate is greater than or equal to 95%, the sand dissolution rate is below 25%, and the system achieves a differentiated corrosion effect without dispersion for 24 h. Field tests demonstrate that the new acid solution plugging removal system enhances average well production and reduces operational costs. The system effectively mitigates the challenges of substantial sand production and reservoir dispersion, thereby furnishing a theoretical foundation and practical direction for acid plugging treatments in unconsolidated sandstone gas fields. Full article

Lithuania is located on the East of Baltic sedimentary basin and has a geothermal anomaly situated in the southwestern region of the country. There are two primary geothermal complexes within the anomaly, composed of Cambrian and Devonian aquifers. The Cambrian formation is composed of sandstones that have a reservoir temperature reaching up to 96 °C (depth > 2000 m). The Devonian aquifer is composed of unconsolidated sands of Parnu–Kemeri and has a reservoir temperature of up to 46 °C (depth > 1000 m). Historically, both formations have been investigated for geothermal energy production. In this article, we present a detailed literature review of the geothermal work carried out on both formations, including past, present, and some possible future studies. The study presented in this paper highlights the key findings of previous research work, summarizes the research gaps, and then elaborates on the possible applications of emerging technologies to bridge the research gaps and improve our understanding of geothermal complexes in Lithuania. Although it is not the main aim of this article, this article also touches upon the important need to develop 2D/3D numerical models, to quantify uncertainties, in the evaluation of the geothermal potential in Lithuania for commercial development. This study also highlights possibilities of extending geothermal development to depleted hydrocarbon reservoirs through repurposing the high-water-production wells. Moreover, from the literature review, it can be concluded that the Lithuanian geothermal aquifers are hyper-saline in nature and temperature changes lead to the deposition of salts both upstream and downstream of the reservoir. Therefore, there is a need for developing multiphysics thermo-mechanical–chemical (THMC) models for evaluation of reservoir behavior. The literature also describes the potential use and development of the THMC model as a part of future work that must be carried out. Full article

The permeability of reservoirs is a key factor affecting the exploitation and utilization of geothermal resources. This test used a core flow meter and other advanced experimental devices to investigate the evolution of the permeability characteristics of loose sandstone samples (with a diameter of 25 mm and a length of 50 mm) in the Zijiao Town area under various temperatures, confining pressures, injection rates, and cyclic loading and unloading conditions. The results show that (1) as the temperature increases, the overall trend of rock permeability decreases, which is mainly related to the thermal expansion of rock particles. In addition, the higher the temperature, the greater the gravel outflow. (2) The critical pressure for pore closure in the unconsolidated sandstone in the region is approximately 15 MPa. (3) The permeability change of loose sandstone under low injection rate conditions is relatively small and can be neglected. However, there is reason to believe that under high-flow injection conditions, the permeability of this type of rock mass will undergo significant changes. (4) Under the condition of loading and unloading, the permeability ratio curve of the unloading stage at three temperatures is almost a straight line. The higher the temperature, the smaller the slope, and the permeability at 20 °C with the highest recovery degree is only about 50% of the initial one. Full article

Multistage hydraulic fracturing has been proven to be an effective stimulation method to extract more oil from the depleted unconsolidated sandstone reservoirs in Bohai Bay, China. The offshore wellbores in this area were completed with a gravel pack screen that is much too difficult to be mechanically isolated in several stages. Hydra-jet fracturing technology has the advantages of multistage fracturing by one trip, waterjet perforation, and hydraulic isolation. The challenges of hydraulic-jet fracturing in offshore unconsolidated sandstone reservoir can be summarized as follows: the long jet distance, high filtration loss, and large pumping rate. This paper proposes full-scale experiments on the waterjet perforation of unconsolidated sandstone, waterjet penetration of screen liners and casing, and pumping pressure prediction. The results verified that multistage hydra-jet fracturing is a robust technology that can create multiple fractures in offshore unconsolidated sandstone. Lab experiments indicate that the abrasive water jet is capable to perforate the screen-casing in less than one minute with an over 10 mm diameter hole. The water jet perforates a deep and slim hole in unconsolidated sandstone by using less than 20 MPa pumping pressure. Recommended perforating parameters: maintain 7% sand concentration and perforate for 3.0 min. Reduce sand ratio to 5%, maintain 3.0 m³/min flow rate, and continue perforating for 7.0 min. The injection drop of the nozzle accounts for more than 62% of the tubing pump pressure. The recommended nozzle combinations for different fracturing flow rates are 8 × ø6 mm or 6 × ø7 mm for 2.5 m³/min and 3.0 m³/min, and 8 × ø7 mm for 3.5 m³/min and 4.0 m³/min. A one-trip-multistage hydra-jet fracturing process is recommended to be used for horizontal wells in offshore unconsolidated sandstone reservoirs. Full article

The unconsolidated sandstone is a type of rock that has poor cementation, a low strength, a high porosity, and permeability. It is highly compressible under high stress and exhibits non-linear plastic deformation during hydraulic fracturing construction in its reservoir. In this study, the mechanical properties of unconsolidated sandstone with a different permeability were studied, and a three-dimensional hydraulic fracture propagation numerical model was established based on the modified traditional Cambridge model. This model was used to simulate the fracture propagation law of unconsolidated sandstone in separate layer fracturing under different construction conditions. During hydraulic fracturing construction, the fracturing fluid slowly invades the reservoir when the displacement of the fracturing fluid is small. The unconsolidated sandstone undergoes compaction and hardening, followed by shear expansion, and then complete destruction. A larger displacement will cause the reservoir rock to directly enter the state of destruction from compaction and hardening. This study found that several critical parameters are obtained for fracturing construction. When the displacement is greater than 5 m³/min, the fracturing fluid exceeds 100 mPa·s, or when the filtration coefficient exceeds 1.2 × 10⁻³ m/$\sqrt{\mathrm{s}}$, the second and third layers will be penetrated. This study provides valuable insights into the mechanical properties of unconsolidated sandstone and reveals the critical parameters for the successful hydraulic fracturing construction in this type of reservoir. Full article