Reservoir Scale Research Articles

Evaluation of the Compatibility Between Formation and Injection Water in Ultra-Low Permeability Reservoirs

This study focuses on the reservoir scaling and the under-injection issues of the water injection well during the water injection development of an ultra-low permeability reservoir in Xinjiang due to the complex composition of injected water. Microfluidic experiments were applied to visualize the flow channel changes during water flooding, indoor core flooding experiments were employed to analyze the permeability and ion concentration, and nuclear magnetic resonance (NMR) was used to evaluate the pore structure damage. Together, these experiments were used to clarify the scaling and precipitation characteristics as the injected water met the formation water in porous media and the effects on reservoir damage. The research results showed that the poor compatibility of the injected water with the formation water could easily produce calcium carbonate scaling. The scaling products exhibited a unique network structure of blocks and a radial distribution, mainly composed of calcium carbonate and aluminosilicate. The scaling in the porous media exhibited the characteristics of unstable crystal precipitation, migration, and repeated scaling following water mixing, while the scale crystal growth occurred in the pores and the throats. According to the scaling characteristics, the damage to the reservoir permeability by scaling can be divided into the induction, damage, and stabilization stages. The filling and clogging of the scale crystals enhanced the pore structure heterogeneity, with the median pore radius reduced by 21.61% and the permeability reduced by 50%.

Research on the Blocking Mechanism of Stagnant Water and the Prediction of Scaling Trend in Fractured Reservoirs in Keshen Gas Field

In this paper, well Keshen 221 was taken as the research object. The stagnant water–rock static experiment showed that, after 8 weeks of the residual water–rock static reaction, the pore size of the inner profile of the rock slice increased from 5 μm to 90 μm, and calcium carbonate crystals were deposited in the hole. Combined with the microscopic visualization model, it is observed that the reservoir blockage mostly occurs at the pore throat diameter, and the small fracture (30 μm) is blocked first, then the large fracture (50 μm). So, it is inferred that the blockage of the reservoir flow channel is caused by the migration of the crystals precipitated by the interaction between the stagnant water and the reservoir rock. On this basis, the TOUGHREACT reservoir model was further constructed to simulate the scaling of the stagnant water in the reservoir matrix and used to compare the scaling of the fractures with 7% and 30% porosity and the retained water at 0.658 m and 768 m. The pre-results of reservoir scaling show that the scaling is more serious when the fractures occur in the far well zone than when the fractures occur in the well entry zone. At the same location, the deposition of large fractures is six times that of small fractures, and the scaling is more severe in large fractures.

Geothermal modeling in complex geological systems with ComPASS

In deep geothermal reservoirs, faults and fractures play a major role, serving as regulators of fluid flow and heat transfer while also providing feed zones for production wells. To accurately model the operation of geothermal fields, it is necessary to explicitly consider objects of varying spatial scales, from the reservoir scale itself, to that of faults and fractures, down to the scale of the injection and production wells.Our main objective in developing the ComPASS geothermal flow simulator, was to take into account all of these geometric constraints in a flow and heat transfer numerical model using generic unstructured meshes. In its current state, the code provides a parallel implementation of a spatio-temporal discretization of the non-linear equations driving compositional multi-phase thermal flows in porous fractured media on unstructured meshes. It allows an explicit discretization of faults and fractures as 2D hybrid objects, embedded in a 3D matrix. Similarly, wells are modeled as one dimensional graphs discretized by edges of the 3D mesh which allows arbitrary multi-branch wells. The resulting approach is particularly flexible and robust in terms of modeling.Its practical interest is demonstrated by two case studies in high-energy geothermal contexts.

Sedimentary characteristics and reservoir architecture of a lacustrine mixed carbonate/siliciclastic system: the lower member of the ShangGanchaigou Formation, Neogene, in the western Qaidam Basin, China

Lacustrine mixed carbonate/siliciclastic sediment is an important type of oil and gas reservoir with significant potential. Although previous studies have investigated the sedimentary characteristics of the mixed depositional system in numerous oil and gas-bearing basins worldwide, a detailed sedimentary architecture model is still lacking for guiding reservoir characterization at the hydrocarbon reservoir scale. In this paper, a typical lacustrine mixed carbonate/siliciclastic sedimentary system, preserved in the lower member of the ShangGanchaigou Formation, Neogene, in the western Qaidam Basin, Western China, was deeply investigated based on well logging data from 640 wells, 438 m of cores from 3 core wells, and outcrop studies. The results demonstrate that 1) seven types of architecture elements, namely, distributary channel, channel mouth bar, distal bar, sheet-like sand, shallow water mud, algal mound, and marl flat characterized by different lithofacies associations, were recognized based on core and well logging data. 2) The lacustrine mixed carbonate/siliciclastic depositional system can be divided into three facies belts. Along the lakeward direction, the proximal facies belt is dominated by delta front deposits and characterized by gradually downstream bifurcating distributary channels and associated lateral amalgamated delta lobes. The middle facies belt is characterized by isolated and small-scale delta lobes and inter-lobe deposits, including sheet-like sand, small-scale algal mounds, and marl flats, and the distal facies belt is a combination of large-scale algal mounds and marl flats. 3) Within a depression, short-term base-level cycles controlled the facies belt transition, and the proximal, middle, and distal facies belts formed under relatively low, middle, and high base-level conditions, respectively. 4) The scale and connectivity of reservoirs gradually decreased from the proximal to the distal belt.

The Identification and Quantification of Hidden Hazards in Small Scale Reservoir Engineering Based on Deep Learning: Intelligent Perception for Safety of Small Reservoir Projects in Jiangxi Province

This study aims to enhance the detection and assessment of safety hazards in small-scale reservoir engineering using advanced image processing and deep learning techniques. Given the critical importance of small reservoirs in flood management, water supply, and ecological balance, the effective monitoring of their structural integrity is crucial. This paper developed a fully convolutional semantic segmentation method for hidden danger images of small reservoirs using an encoding–decoding structure, utilizing a deep learning framework of convolutional neural networks (CNNs) to process and analyze high-resolution images captured by unmanned aerial vehicles (UAVs). The method incorporated data augmentation and adaptive learning techniques to improve model accuracy under diverse environmental conditions. Finally, the quantification data of hidden dangers (length, width, area, etc.) were obtained by converting the image pixels to the actual size. Results demonstrate significant improvements in detecting structural deficiencies, such as cracks and seepage areas, with increased precision and recall rates compared to conventional methods, and the HHSN-25 network (Hidden Hazard Segmentation Network with 25 layers) proposed in this paper outperforms other methods. The main evaluation indicator, mIoU of HHSN-25, is higher than other methods, reaching 87.00%, and the Unet is 85.50%, and the Unet++ is 85.55%. The proposed model achieves reliable real-time performance, allowing for early warning and effective management of potential risks. This study contributes to the development of more efficient monitoring systems for small-scale reservoirs, enhancing their safety and operational sustainability.

Seafloor alkalinity enhancement as a carbon dioxide removal strategy in the Baltic Sea

Carbon dioxide removal from the atmosphere and storage over long times scales in terrestrial and marine reservoirs is urgently needed to limit global warming and for sustainable management of the global carbon cycle. Ocean alkalinity enhancement by the artificial addition of carbonate minerals to the seafloor has been proposed as a method to sequester atmospheric CO2 and store it in the ocean as dissolved bicarbonate. Here, a reaction-transport model is used to scrutinize the efficacy of calcite addition and dissolution at a well-studied site in the southwestern Baltic Sea – a brackish coastal water body in northern Europe. We find that most calcite is simply buried without dissolution under moderate addition rates. Applying the model to other sites in the Baltic Sea suggests that dissolution rates and efficiencies are higher in areas with low salinity and undersaturated bottom waters. A simple box model predicts a tentative net CO2 uptake rate from the atmosphere of 3.2 megatonnes of carbon dioxide per year for the wider Baltic Sea after continually adding calcite to muddy sediments for 10 years. More robust estimates now require validation by field studies.

Scaling-up dynamic elastic logs to pseudo-static elastic moduli of rocks using a wellbore stability analysis approach in the Marun oilfield, SW Iran

Wellbore stability analysis is a critical component of petroleum engineering, evaluating the risks of sanding, reservoir compaction, and casing failures. Laboratory rock mechanical measurements must be scaled up to reservoir scales to achieve accurate results. One challenge lies in upscaling dynamic measurements from petrophysical logs to pseudo-static elastic properties, which has significant implications for oil and gas operations. We present a novel approach that combines laboratory rock mechanical measurements with well-log data to develop a mechanical earth model (MEM) for an Iranian oilfield with over 350 wells. We conducted static elastic property measurements on 40 core samples from various layers and depths of carbonate and sandstone rocks, demonstrating the practical application of our approach. By integrating these measurements with dynamic log data and static-dynamic correlations, we established a framework for evaluating the mechanical properties of different layers. Our findings indicate that the safe mud weight window ranges from 41.5 to 118.59 pcf, while the stable mud weight window ranges from 41.5 to 156 pcf. We demonstrate the importance of conducting parallel rock mechanical studies on cores and logs to reduce uncertainties, costs, and risks during oil and gas operations. We also propose a novel methodology combining lithological characteristics, abnormally high pressure, and borehole instability mechanisms to evaluate the stability of borehole walls. This framework provides a fresh perspective on wellbore stability analysis and offers practical solutions for the industry. Essential novel techniques include developing a geomechanical model that integrates laboratory rock mechanical measurements with well-log data to evaluate mechanical properties and calculate safe and stable mud-weight windows. Our study advances wellbore stability analysis by providing a new method for addressing this long-standing challenge. It offers valuable insights for petroleum engineers working in the oil and gas industry.

Countercurrent Imbibition in Porous Media with Dense and Parallel Microfractures: Numerical and Analytical Study

Summary Countercurrent imbibition is the process in which the wetting fluid spontaneously displaces the nonwetting fluid, while the nonwetting fluid is recovered at the wetting fluid inlet. It is a major mechanism for the recovery of shale oil, shale gas, and tight oil. In shale and tight formations, microfractures are highly developed. Specifically, some typical formations, such as continental shales, consist of dense and parallel microfractures (DPFs). In DPF systems, microfractures are segregated by low-permeability matrix layers, while the very close distance betwen neighboring microfractures results in strong capillary correlation. The underlying assumptions of the classical dual-porosity (DP) model break down. Despite extensive studies on layered media, there is still no suitable model to describe imbibition in the DPF system at the representative elementary volume (REV) scale. In this study, we first numerically simulate countercurrent imbibition in DPF systems with fine grids, adopting typical continental shale parameters. For imbibition parallel to microfractures, two distinct stages are identified: an early stage where fractures are not correlated and a late stage where neighboring fractures are strongly correlated by capillarity. In both stages, cumulative oil production (Q) is proportional to the square root of imbibition time (t1/2), while the prefactors are very different. The late stage is the dominant stage in oil recovery. We note that the matrix permeability rarely contributes to imbibition parallel to microfractures at the late time, indicating that the matrix’s role here is to store fluid rather than to provide flow resistance. In addition, we rationalize the failure of the classical DP model, as it significantly overestimates fracture-matrix fluid exchange near the displacement front. Similarly, for imbibition perpendicular to microfractures, Q is also proportional to t1/2 in the late stage. After elucidating the mechanisms of fracture-fracture capillary interaction, we successfully derive analytical solutions for uni-directional countercurrent imbibition kinetics in DPF systems at the late stage, for imbibition parrallel and perpendicular to microfractures, respectively. We accordingly propose an equivalent REV scale model and examine it with fine-grid simulations. We highlight the importance of adopting anisotropic relative permeability in this DPF system at REV scale for reservoir simulation rather than simply adopting anisotropic absolute permeability. This presents a new challenge for numerical simulations at reservoir scale.

Pore pressure-minimum horizontal stress coupling estimation in Tunu Field, Lower Kutai Basin, Indonesia

Quantifying the change of minimum horizontal stress (Shmin) in response to pore pressure is vital, particularly at the development stage of a hydrocarbon field. However, estimates of the coupling ratio between these parameters, either at basin or reservoir scales, are not well defined in Indonesia’s sedimentary basin, such as Lower Kutai Basin. This study investigates the coupling ratio between Shmin and pore pressure in one of the gas fields within the basin, Tunu Field, using available evidence from an extensive data set of direct pressure measurement, leak-off test, extended LOT, Mini-Frac, and lost circulation. Previous studies have reported overpressured and depleted reservoirs. Nevertheless, the evolution of Shmin due to the change in pore pressure has yet to be well established. This study reveals a Shmin and vertical stress ratio of 0.87 which may relate to the stiffening of the shales via clay diagenesis/cementation. Coupling ratios between Shmin and pore pressure are 0.3 for the overpressured zone at the basin scale and 0.42 for the depletion at the reservoir scale. The approach used has been shown to produce similar coupling ratio (or stress path) results to other basins globally, thus providing a useful estimate of the Shmin and pore pressure relationship for the Tunu Field, and potentially other fields in the Lower Kutai Basin. For the application to infill drillings within the field, this study indicates Shmin decreases in response to pore pressure depletion due to production, ranging from 1.7 to 2.3 ppg within the hydrostatic zone and from 2.5 to 3.7 within the overpressured zone, equivalent to a Pore Pressure (PP)-Shmin window decrease of approximately 28% to 37% and approximately 40% to 88%, respectively. In addition, strike-slip faulting is suggested as the likely in situ stress regime in the Tunu Field.

Analysis of the sediment deposition characteristics in the Three Gorges Reservoir and its influence factors

Affected by climatic factors and human activities, the conditions of the sediment deposition of the Three Gorges Reservoir (TGR) in the upper Yangtze River have undergone significant changes, the understandings of the sedimentation in TGR and its factors remain unclear. In this paper, the regime for sediment deposition in TGR from 2003 to 2017 is analyzed based on field data, its influence factors are discussed, and the empirical formulas governing the relationships are presented. The results show that the sedimentation pattern of the TGR is discontinuous and that the perennial inundated area is the key sedimentation area, while the reaches of Xiangxizhen, Wushan, Fengjie, Wanxian, Huanghuacheng, Lanzhuba, and Tunaozi are the main deposition reaches in the reservoir, with the same characteristics of wider cross-sections. Sediment deposition in the TGR is affected by the incoming water and sediment, the operation rule of the reservoir, and by the characteristics of different reaches. Compared with the factors influencing the total sediment trapping ratio of the reservoir, local reach conditions are also the main factors influencing the sediment trapping ratio of the reaches due to the difference of sediment carrying capacity between wider reach and narrow reach. The sediment trapping ratios for reservoir scale and reach scale can be good indicators that reflect sedimentation in the TGR; the calculated sediment trapping ratios agree well with field observations. With the continuous construction and operation of the main and tributary reservoirs in the upper Yangtze River, the existing sedimentation regime of the TGR will persist for many years.

Optimization method of fracturing fluid volume intensity for SRV fracturing technique in shale oil reservoir based on forced imbibition: A case study of well X-1 in Biyang Sag of Nanxiang Basin, China

An optimization method of fracturing fluid volume strength was introduced taking well X-1 in Biyang Sag of Nanxiang Basin as an example. The characteristic curves of capillary pressure and relative permeability were obtained from history matching between forced imbibition experimental data and core-scale reservoir simulation results and taken into a large scale reservoir model to mimic the forced imbibition behavior during the well shut-in period after fracturing. The optimization of the stimulated reservoir volume (SRV) fracturing fluid volume strength should meet the requirements of estimated ultimate recovery (EUR), increased oil recovery by forced imbibition and enhancement of formation pressure and the fluid volume strength of fracturing fluid should be controlled around a critical value to avoid either insufficiency of imbibition displacement caused by insufficient fluid amount or increase of costs and potential formation damage caused by excessive fluid amount. Reservoir simulation results showed that SRV fracturing fluid volume strength positively correlated with single-well EUR and an optimal fluid volume strength existed, above which the single-well EUR increase rate kept decreasing. An optimized increase of SRV fracturing fluid volume and shut-in time would effectively increase the formation pressure and enhance well production. Field test results of well X-1 proved the practicality of established optimization method of SRV fracturing fluid volume strength on significant enhancement of shale oil well production.

A new workflow for warning and controlling the water invasion

Warning and controlling the water invasion in water-driving reservoirs is significant because water invasion will seriously hamper well productivity and gas recovery. Unfortunately, there are few comprehensive methods to control water invasion. First, we establish and verify a water invasion model of reservoir scale. Then, a new workflow for warning and controlling the water invasion is proposed using the numerical simulation method. The workflow first judges the water invasion characteristics, determines the water invasion index based on the production data, and then controls the water invasion by finding and closing the perforation layer of serious water production. Finally, the optimal water control scheme is obtained by comparing water and gas production. The results show that the accuracy of the geological reserves of the established water invasion model is 99% and has a good pressure fitting result. The early warning chart for the gas reservoir in the west of Amu Darya B area is drawn, including the early warning pressure and the level 1, level 2, and level 3 early warning water–gas ratio, which is convenient for field application. For the water-driving wells west of area B, the early warning value of the water–gas ratio increases with the increase of gas production rate during fixed production and decreases with the increase of bottom hole pressure during constant pressure production. Closing the harmful perforation from the water-finding study will significantly reduce the water while retaining the gas production. After water control technology, water production decreased by 90.9%, while gas production decreased by only 9.7%.

Experimental Study on Low-Temperature-Oxidation Parameters and Simulations of Exothermic Process during Air Injection in Light Oil Reservoirs

Summary The thermal development process for light oil reservoirs using air injection technology is to release heat through low-temperature oxidation (LTO) between the injected air and crude oil and gradually increase the reaction zone’s temperature to displace crude oil. However, existing LTO experimental methods for air injection do not adequately capture the characteristics of LTO and struggle to directly obtain LTO kinetic parameters at low temperatures. In this paper, we used light oil samples from the Huabei Oilfield, China, as the studied objects and proposed innovative methods for obtaining and calculating LTO kinetic parameters. Further, we validated the feasibility of the proposed methods through experimental and numerical simulations. The results indicate that the lower limit temperature at which oxidation parameters can be directly measured through the accelerating rate calorimeter (ARC) experiments is 124°C. We matched the calculations from the ARC experiment curve-extension method for kinetic parameters with the results from both the high-pressure thermogravimetric analyzers (HP-TGA) experiment and the ramped thermal oxidizer (RTO) experiment. The fit between these results indicates that three methods are suitable for obtaining LTO parameters and can be used to derive chemical equations for LTO reactions in numerical simulation models. The simulation results from the reservoir scale indicate that, following air injection into the light oil reservoir, the peak temperature at the leading edge of the high-temperature zone reaches 370.9°C. The interaction between crude oil and air remains in the LTO phase, facilitating a sustained thermal accumulation within the reservoir. This study can provide a reference for reservoir development under similar conditions.

Shading solutions for sustainable water management: impact of colors and intensities on evaporation and water quality

This study investigated the effectiveness of suspended shade covers in reducing evaporation rates and improving evaporation suppression efficiency. The experiment tested different shading colors (black, white, and green) and intensities (50, 70, and 90%) while considering ecological and economical aspects. Evaporation was determined using class-A evaporation pans, and various microclimatic variables were measured below the shade covers. Additionally, water quality parameters such as EC, phosphate, nitrate, and chloride concentrations were monitored. The results showed that black covers had the highest evaporation suppression efficiency with values of 56.8, 53.6, and 51.7% observed under 90% shading intensity for the black, green, and white covers, respectively. Despite variations in water quality parameters which all met Jordanian and FAO standards for irrigation water, the economic feasibility of installing these covers was found to be viable due to the resulting benefits in water conservation and crop production. However, selecting the best shading cover should consider the multipurpose use of agricultural reservoirs, including aquaculture, and further studies are recommended to investigate other overlapping aspects on a reservoir scale.

Macroscale Modeling of Geochemistry Influence on Polymer and Low-Salinity Waterflooding in Carbonate Oil Reservoirs.

The enhancement of oil recovery (EOR) through low-salinity waterflooding (LSWF) and the emerging hybrid with a polymer (LSP) has proven to be effective at microscale investigations and cost-effective with ease of operation at field-scale tests. Their application in carbonate oil reservoirs, which typically occur oil-wet, presents a particularly essential capacity given that over half of the global oil reserves are hosted in carbonate formation. However, modeling the mechanisms involved to predict and evaluate the performance of low salinity-based EOR at a large scale is complex and requires the integration of geochemistry in reservoir simulation to upscale the interfacial interactions of crude oil, brine, and rock observed at the micrometer scale. This study presents an integrated approach that combines MRST's polymer model with PHREEQC geochemical modeling to simulate LSWF at the reservoir scale. Using single-phase and multiphase experimental flooding data for validation, the coupled model was shown to accurately predict effluent ionic and oil recovery profiles. The simulation of LSWF and LSP both exhibited additional tertiary oil recovery, with LSWF and LSP showing 3 and 2%, respectively, which are consistent with previously reported field and core flooding results. Furthermore, the sequential application of formation water (FW), LSWF, and LSP flooding in secondary mode showed a high increase in oil recovery, with oil recovery percentages of 61, 20, and 19%, respectively. However, the FW results were 50% lower compared to regular core flooding due to upscaling limitations. The modeling of vertical and anisotropic permeability heterogeneity effects showed a positive synergy with low-salinity floodings, resulting in a 4% drop and 3 and 1% increase in FW, LSWF, and LSP, respectively. These findings demonstrate the potential of the coupled MRST-PHREEQC model in accurately simulating hydrogeochemical interactions during LSWF/LSP at the reservoir scale, providing valuable insights for the optimization of low salinity-based EOR strategies in carbonate reservoirs.

Experimental observations and modeling of the effect of wettability on immiscible viscous fingers at the Darcy scale

In this work, we present a Darcy-scale study of immiscible unstable displacement in large (15 × 15 × 1 cm3) slabs of Bentheimer sandstone. Oil is displaced by water under two wetting conditions, a weakly water-wet system and a weakly oil-wet system (at two initial water saturations), with a viscosity ratio of μo/μw = 100. The system is directly visualized using x rays and the fluid distribution monitored throughout the displacement. Following a period of water flooding, the injection water is viscosified with glycerol to act as a pseudo tertiary polymer flood. The experiments are then modeled directly using numerical simulation applying a recently developed fractional flow approach, which has been shown to reproduce experimental immiscible fingering, before upscaling the results to the reservoir scale. From the observed results, we can conclude that typical wettability modification using crude oil aging may generate a wettability similar to that found in oil reservoirs, but this may still result in an exaggerated capillary dampening of the viscous fingers. However, as the system is scaled up in size to the field dimensions, viscous forces will dominate, and fingering will re-emerge due to the increase in the viscous/capillary force balance. But if the input relative permeabilities are constructed from an excessively capillary stabilized experiment, the shock front mobility of the fractional flow will still overestimate the stability of the system. Indeed, we derive the same water saturation above Swi for the three floods, but with different shock front mobilities.

Real-time imaging of oil shale pyrolysis dynamics at nanoscale via environmental scanning electron microscopy

Pyrolysis is a promising technology to increase pore and fracture connectivity in oil shale and thereby accomplish commercial recovery of unconventional hydrocarbons. Herein, real-time oil shale pyrolysis dynamics are imaged at nanoscale via environmental scanning electron microscopy (imaging resolution of 58 nm/pixel, imaging speed of 1 frame per second, and heating temperature up to 750 °C). It is counterintuitively observed that 1) inorganic nano-fractures started to appear below 100 °C; 2) inorganic nano-fracture width had a non-monotonous relationship with temperature; and 3) organic kerogen areas decreased monotonously with increasing temperature. These findings will establish a standard benchmark for unconventional resource recovery, promote fundamental understanding of oil shale pyrolysis dynamics at nanoscale and provide key guidance on oil shale extraction at reservoir scale.

Risk assessment on the impact of Non-Darcy flow on unconventional well performance.

Nano-pores in unconventional reservoirs can cause deviations from Darcy's law where permeability becomes a strong function of pore size and pore pressure. As pores become smaller, the interaction of gas molecules with the pore walls becomes increasingly dominant compared to interactions between gas molecules. This increases gas mobility leading permeabilities measured in the lab not to be accurate at reservoir conditions. Thus, corrections to Darcy flow may be needed when analyzing well production behavior. This paper demonstrates a novel workflow for modeling the impact of non-Darcy flow regimes (i.e., gas slippage, transition flow and Knudsen diffusion) from pore scale characterization to reservoir scale flow simulation. A stochastic approach is used for uncertainty assessment on non-Darcy corrections needed for methane mobility as pore pressure depletes based on reservoir properties, pore sizes, rock compressibility and compaction. Flow simulations are conducted for a range of scenarios to test the impact on the recovery of an unconventional well. Study is conducted using a commercial simulator since workflow modifies the input to the simulator and does not need a new code development. The workflow is demonstrated using field data and shows that non-Darcy flow regimes can have significant impact by increasing gas mobility at low pore pressures near hydraulic fractures. For the field under study, ignoring non-Darcy flow risks up to 20% lower estimations in cumulative gas production under certain scenarios.

Pore-scale modeling of preformed particle gel (PPG) extrusion in porous media

Preformed particle gel (PPG) is a promising profile control agent for enhanced oil recovery in heterogeneous reservoirs. For an improved sweep, the remigration behavior of PPG once blocked by pore throats is of crucial importance. In this paper, the process of a hyper-elastic particle passing through a pore throat is simulated, allowing investigation of the extrusion mechanism of PPG with deformation under a certain hydraulic pressure. The results reveal that PPG is subjected to a varying resistance during the process of entering, penetrating and leaving the throat. The maximal radial resistance occurs when the particle center arrives at the narrowest throat, whereas the maximal axial resistance occurs before that. In the meantime, it is shown that the particle gel bears over 80% body strain during the extrusion process through frictional pore throat. The hydraulic pressure needed for the PPG extrusion through the pore throat depends on the mechanical behaviors (hyper-elasticity of PPG, and friction coefficient of the PPG-throat interface) and geometrical properties (the particle size, and the shape of throat wall) of the PPG-throat system. Based on the simulation results, an empirical model is finally established to predict the required driving pressure. Eventually, the pore-scale model is upscaled and employed to attain effective pressure windows for profile-control in a reservoir scale formation with 10 times permeability heterogeneity.

Prediction of Oil Production in a Tight Sandstone Reservoir: Triassic Chang 9 Member, Jiyuan Area, Ordos Basin, NW China

Tight sandstone oil reservoirs in the Upper Triassic Yanchang Formation of the Ordos Basin are the most promising exploration and development fields owing to their huge production potential. Even though they have received considerable attention in recent years, common productivity prediction methods were not well applied during pre-development owing to their strong internal heterogeneity. In this study, the factors influencing oil production of the Chang 9 Member in the Jiyuan area were investigated and summarized based on drill cores, such as sediment characteristic analysis, lithofacies analysis, other analytical tests, and conventional logging curves. The findings show that fine-sandstone reservoirs with smooth sand body architectures are the main types of tight sandstone commercial oil reservoirs. Furthermore, having high porosity and oil content are prerequisites for commercial oil reservoirs, and the cumulative thickness of effective reservoirs serves as a crucial resource base for them. Through the analysis of logging curves, the relative center of gravity, deviation root of variance, petrophysical index, effective reservoir thickness, and evaluation indicator were used to predict daily oil production, thereby establishing the identification criteria for the ranking of tight sandstone oil reservoirs using logging. Then, the productivity of each reservoir in a single well was predicted by processing the log data from each well using the proposed method, and the productivity prediction results agreed well with the tested results of the perforated interval. This approach highlights the integrated influence of geological factors, physical properties, and the thickness scale of an effective reservoir, thereby improving the predictive capacity of logging curves. Additionally, the proposed methods significantly reduce the need for reservoir parameters better than previous ones, streamline operations, and improve practical applications.