Reservoir Production Research Articles

Study on the Mechanical Parameters and Permeability of Coal Reservoirs at Different Temperatures.

Deep coal reservoirs, as opposed to their shallower counterparts, exhibit characteristics of higher temperatures and pressures. These conditions affect the fracture structure and mechanical properties of coal, which in turn controls permeability. Substantial studies have been conducted to determine the effects of overburden pressure on permeability, but the correlation between the temperature and mechanical parameters/permeability of coal remains unclear. This study focused on low-rank bituminous coal from the southern edge of the Junggar Basin in Xinjiang. Using experiments conducted on seepage and mechanics at different depths (considering effective stress and temperature), the study investigated how temperature affects the mechanical parameters and permeability of coal column samples. A permeability prediction model was established incorporating temperature, mechanical parameters, and effective stress. The results show that from 20 to 80 °C, the elastic modulus of coal column samples decreases by 31.0%, and the Poisson ratio increases by 72.0%. Permeability decreases between 48.37 and 90.12% under different depths. The stress sensitivity coefficient under various temperature conditions decreased exponentially as the effective stress increased, and the temperature sensitivity coefficient under various effective stress conditions decreased with increasing temperature. The permeability was more sensitive to a temperature below 40 °C. In the permeability prediction model, the fracture compressibility coefficient is bifurcated into two coefficients, each controlled by temperature and effective stress. The permeability prediction error of the model was 12.7% under constant effective stress and 17.2% under varying effective stress and temperature conditions. The study could provide guidance for fracturing and coalbed methane production in deep coal reservoirs.

A Study on Three-Dimensional Multi-Cluster Fracturing Simulation under the Influence of Natural Fractures

Multi-cluster fracturing has emerged as an effective technique for enhancing the productivity of deep shale reservoirs. The presence of natural bedding planes in these reservoirs plays a significant role in shaping the evolution and development of multi-cluster hydraulic fractures. Therefore, conducting detailed research on the propagation mechanisms of multi-cluster hydraulic fractures in deep shale formations is crucial for optimizing reservoir transformation efficiency and achieving effective development outcomes. This study employs the finite discrete element method (FDEM) to construct a comprehensive three-dimensional simulation model of multi-cluster fracturing, considering the number of natural fractures present and the geo-mechanical characteristics of a target block. The propagation of hydraulic fractures is investigated in response to the number of natural fractures and the design of the multi-cluster fracturing operations. The simulation results show that, consistent with previous research on fracturing in shale oil and gas reservoirs, an increase in the number of fracturing clusters and natural fractures leads to a larger total area covered by artificial fractures and the development of more intricate fracture patterns. Furthermore, the present study highlights that an escalation in the number of fracturing clusters results in a notable reduction in the balanced expansion of the double wings of the main fracture within the reservoir. Instead, the effects of natural fractures, geo-stress, and other factors contribute to enhanced phenomena such as single-wing expansion, bifurcation, and the bending of different main fractures, facilitating the creation of complex artificial fracture networks. It is important to note that the presence of natural fractures can also significantly alter the failure mode of artificial fractures, potentially resulting in the formation of small opening shear fractures that necessitate careful evaluation of the overall renovation impact. Moreover, this study demonstrates that even in comparison to single-cluster fracturing, the presence of 40 natural main fractures in the region can lead to the development of multiple branching main fractures. This finding underscores the importance of considering natural fractures in deep reservoir fracturing operations. In conclusion, the findings of this study offer valuable insights for optimizing deep reservoir fracturing processes in scenarios where natural fractures play a vital role in shaping fracture development.

A Productivity Prediction Method of Fracture-Vuggy Reservoirs Based on the PSO-BP Neural Network

Reservoir productivity prediction is a key component of oil and gas field development, and the rapid and accurate evaluation of reservoir productivity plays an important role in evaluating oil field development potential and improving oil field development efficiency. Fracture-vuggy reservoirs are characterized by strong heterogeneity, complex distribution, and irregular development, causing great difficulties in the efficient prediction of fracture-vuggy reservoirs’ productivity. Therefore, a PSO-BP fracture-vuggy reservoir productivity prediction model optimized by feature optimization was proposed in this paper. The Chatterjee correlation coefficient was used to select the appropriate combination of seismic attributes as the input of the prediction model, and we applied the PSO-BP model to predict oil wells’ production in a typical fracture-vuggy reservoir area of Tahe Oilfield, China, with the selected seismic attributes and compared the accuracy with that provided by the BP neural network, linear support vector machine, and multiple linear regression. The prediction results using the four models based on the test set showed that compared with the other three models, the MSE of the PSO-BP model increased by 23% to 62%, the RMSE increased by 12 to 38 percent, the MAE increased by 18 to 44 percent, the SSE increased by 23 to 62 percent, and the R-square value increased by 2 to 13 percent. This comparison proves that the PSO-BP neural network model proposed in this paper is suitable for the productivity prediction of fracture-vuggy reservoirs and has better performance, which is of guiding significance for the development and production of fracture-vuggy reservoirs.

A granular thermodynamic constitutive model considering THMC coupling effect for hydrate-bearing sediment

The interaction among mechanical, hydraulic, and temperature fields plays a crucial role in determining gas production efficiency and reservoir mechanical response. Considering particle rearrangement and cementation degradation effect, this study establishes a thermodynamic model that couples thermal, hydraulic, mechanical, and chemical fields (THMC) for hydrate-bearing sediments. For the proposed model, the mechanical field incorporates pore pressure and cementation terms, the hydraulic field considers the porosity, volumetric strain, and thermal driving effect, and the thermal field couples heat conduction, heat convection, and energy dissipation from hydrate dissociation. Furthermore, gas/liquid seepage rate and temperature conservation equation are not introduced as assumptions but are inferred from thermodynamic identities. Numerical simulations are conducted to investigate the physical significance of the three coupling elements and the mechanism of crucial parameters influencing gas production efficiency and reservoir mechanical response. The proposed model is simulated and validated at varying hydrate saturation levels and depressurization pressures. The modeling outcomes indicate that the theoretical model can accurately anticipate mechanical responses, gas production efficiency, and temperature variations during the hydrate consolidation and dissociation process.

Production optimization in a fractured carbonate reservoir with high producing GOR

The Gas-Oil Ratio (GOR) is a crucial production parameter in oil reservoirs. An increase in GOR results in higher gas production and lower oil production, potentially leading to well shut-ins due to economic infeasibility. This study focuses on a real fractured oil field that requires urgent production operations to reduce the producing GOR. In this study, the static model for the field was developed using commercial software, involving steps such as data collection, fault modeling, meshing, and statistical analysis to prepare for dynamic simulation. The dynamic model incorporates geometry, gridding, and rock properties from the static model, utilizing a dual-porosity approach for the naturally fractured reservoir and the Peng-Robinson equation for fluid phase behavior. Initial reservoir conditions, production history, and rock-fluid interactions were defined, with relative permeability curves indicating a water-wet reservoir and low critical gas saturation affecting the GOR. To better understand the relationship between reservoir and production parameters, a detailed sensitivity analysis was performed using the Response Surface Methodology (RSM). Following the sensitivity analysis, a history matching process was conducted using the Designed Exploration and Controlled Evolution (DECE) optimizer to validate the model for future forecasts. Six operational scenarios were defined to decrease the production GOR and enhance final recovery from the field. The results indicate that the water injection scenario is effective in preventing the GOR increase by maintaining reservoir pressure, thereby sustaining production over a longer period. This scenario also improves oil recovery by approximately 6% compared to the base case. Finally, optimization was carried out using the DECE optimizer for each scenario to fine-tune the operational parameters. The goal was to maximize oil revenue for each scenario during the optimization process. This study stands out as one of the few that provides a comprehensive analysis of production behavior and development planning for a real fractured reservoir with high producing GOR.

Numerical simulation of residual oil distribution characteristic of carbonate reservoir after water flooding

Carbonate reservoirs are characterized by abundant reserves and are currently focal points for development in oil and gas producing regions such as the Ahdab oilfield, Tarim Basin, Sichuan Basin, and Ordos Basin. The primary method for exploiting carbonate reservoirs is waterflooding. However, due to the complex pore structure and pronounced heterogeneity of carbonate rocks, the waterflooding process often leads to an unclear distribution of remaining oil and low waterflooding recovery efficiency, significantly impacting the stable and high production of carbonate reservoirs. This paper presents a two-phase flow model of oil and water in distinct pore structures by integrating fluid flow equations and interface tracking equations. It visually represents the waterflooding process at the pore scale, elucidates the distribution and formation mechanism of remaining oil, and discusses the mechanism of microscopic displacement efficiency change. The study reveals that: 1) After waterflooding, the distribution patterns of remaining oil can be categorized into dead-end remaining oil, pressure balance remaining oil, wall-bound remaining oil, Jamin effect remaining oil, and water-encapsulating remaining oil, which are governed by microscopic pore structure, wettability, and preferential flow paths; 2) From the perspective of actual reservoir displacement efficiency, intergranular pores > intergranular dissolved pores > visceral foramen > mould pore, with this trend being more pronounced under hydrophilic wetting conditions; 3) Given the oil-wet to strong oil-wet wettability characteristics of these carbonate rocks, capillary forces pose significant resistance during waterflooding. The conclusion underscores the importance of leveraging the reservoir’s microscopic pore structure and wettability characteristics for actual oil wells, elucidating the evolutionary law of the mechanical mechanism of oil-water interface advancement, clarifying oil-water percolation characteristics at the pore scale, and understanding the microscopic displacement physical mechanism, all of which are crucial for guiding the design of schemes aimed at enhancing reservoir recovery efficiency.

The geomechanical response of the Gulf of Mexico Green Canyon 955 reservoir to gas hydrate dissociation: A model based on sediment properties with and without gas hydrate

Gas hydrate is commonly found concentrated in sand- and silt-rich reservoirs and these are thought to have great potential as an energy resource. To evaluate this potential, it is critical to understand their in-situ stress state and their behavior during production. We explore the geomechanical behavior of sandy silt sediments from a hydrate reservoir at Green Canyon GC 955, deep-water Gulf of Mexico without hydrate and compare these results to previous work on the same sandy silty sediments with hydrate present. Previous results from hydrate-bearing sediments at GC 955 using intact specimens show that the ratio of lateral to axial effective stress under uniaxial strain (K0) is strongly time-dependent and over long timescales approaches 1 (isostatic stress state). New results from sediments without hydrate using reconstituted specimens reveal that K0 is 0.51 and independent of time and stress. The reservoir without hydrate is approximately three times more compressible than with hydrate. In addition, we find that hydrate-free sediments have a normalized creep rate of Cα/Cc of about 0.028 at all stress levels, whereas hydrate bearing sediments exhibit a decrease in Cα/Cc with stress. We use these observations to present a new geomechanical model that describes how stress and porosity evolve during production of the hydrate reservoir. The key insight in our proposed model is that the sediment skeleton and gas hydrate phases share any applied external load in proportion to their relative stiffnesses. The model results predict that hydrate-bearing sediments are stiffer than gas hydrate-free sediments and that K0 reduces dramatically after gas hydrate dissociation, as is observed. At GC 955, a 5 MPa depressurization is needed to cause gas hydrate dissociation. This change in pore pressure increases the vertical and horizontal effective stresses from 3.8 to 8.8 MPa and 3.8–4.4 MPa, respectively. The dramatic vertical effective stress increase will cause significant compaction (7%) and perturb stresses near the wellbore. These experimental observations and the load-sharing model presented have the potential to underpin a new generation of hydrate reservoir simulation models, which may drive more effective production approaches.

Numerical simulation of geothermal reservoir thermal recovery of heterogeneous discrete fracture network-rock matrix system

In contrast to previous methodologies utilizing smooth fractures for predicting production in fractured geothermal reservoirs, this study introduces a novel approach employing a non-uniform rough discrete fracture network model characterized by heterogeneous apertures. Partial differential equations governing dual porosity flow and heat transfer are formulated, followed by a multi-physical field coupling simulation for the reservoir-scale formation model. The investigation focuses on the 50-year production performance of an enhanced geothermal system (EGS) under various parameters. Findings indicate a 15 % increase in production temperature with a 10-degree rise in injection temperature and a 10 % increase when well spacing is halved. Conversely, doubling the injection velocity or increasing the fracture aperture from 2 mm to 5 mm results in a 20 % and 25 % decrease in production temperature, respectively. These results highlight the negative impacts of faster fluid movement and larger fracture apertures on thermal retention. Conventional smooth fracture networks tend to underestimate both production temperature and the operational lifespan of EGS. An effective flow rate is defined, and an empirical prediction model for thermal recovery is established. This study provides valuable insights into the interplay of parameters affecting EGS production performance, serving as a pertinent reference for analyzing the influence of heterogeneous apertures on geothermal reservoirs.

Experimental study and prediction method of solid destabilization and production in deep carbonate reservoir during mining

Wellbore instability is one of the significant challenges in the drilling engineering and during the development of carbonate reservoirs, especially with open-hole completion. The problems of wellbore instability such as downhole collapse and silt deposit in the fractured carbonate reservoir of Tarim Basin (Ordovician) are severe. Solid destabilization and production (SDP) was proposed to describe this engineering problem of carbonate reservoirs. To clarify the mechanism and mitigate potential borehole instability problems, we conducted particle size distribution (PSD) analysis, X-ray diffraction (XRD) analysis, triaxial compression tests, and micro-scale sand production tests based on data analysis. We found that the rock fragments and silt in the wellbore came from two sources: one from the wellbore collapse in the upper unplugged layers and the other from the production of sand particles carried by the fluid in the productive layers. Based on the experimental study, a novel method combining a geomechanical model and microscopic sand production model was proposed to predict wellbore instability and analyze its influencing factors. The critical condition and failure zone predicted by the prediction model fit well with the field observations. According to the prediction results, the management and prevention measures of wellbore instability in carbonate reservoirs were proposed. It is suggested to optimize the well track in new drilling wells while upgrading the production system in old wells. This study is of great guiding significance for the optimization of carbonate solid control and it improves the understanding of the sand production problems in carbonate reservoirs.

Lattice Boltzmann simulation of cross-linked polymer gel injection in porous media

This study addresses the critical challenge of excessive water production in mature oil and gas reservoirs. It focuses on the effectiveness of polymer gel injection into porous media as a solution, with an emphasis on understanding its impact at the pore scale. A step-wise Lattice Boltzmann Method (LBM) is employed to simulate polymer gel injection into a 2D Berea sample, representing a realistic porous media. The non-Newtonian, time-dependent characteristics of polymer gel fluid necessitate this detailed pore-scale analysis. Validation of the simulation results is conducted at each procedural step. The study reveals that the methodology is successful in predicting the effect of polymer gel on reducing permeability as the gel was mainly formed in relatively larger pores, as it is desirable for controlling water cut. Mathematical model presented in this study accurately predicts permeability reductions up to 100% (complete blockage). In addition, simulations conducted over a wide range of gelation parameters, TD_factor from 1 to 1.14 and Threshold between 0.55 and 0.95, revealed a quadratic relationship between permeability reduction and these parameters. The result of this research indicates LBM can be considered as promising tool for investigating time-dependant fluids on porous media.

Numerical simulation study on propagation mechanism of fractures in tight oil vertical wells with multi-stage temporary plugging at the fracture mouth

The multi-stage temporary plugging and diverting fracturing technique stands as a pivotal method for enhancing production in tight oil reservoirs. At present, fracture propagation models in temporary plugging and diverting fracturing primarily focus on single-stage temporary plugging, disregarding intricate mechanisms influenced by multi-stage temporary plugging and inter-fracture interference on the redirection and propagation of artificial fractures. To address this gap, this study employs the extended finite element method and establishes a mechanical model for the propagation of multi-stage temporary plugging fractures in tight oil reservoirs based on the maximum circumferential stress criterion. Relevant numerical simulations are conducted, considering key factors such as horizontal stress differences, fracturing fluid viscosity, injection rate, and initial fracture angle, all of which influence the morphology of diversion fracture propagation. The study rigorously analyzes and compares characteristics such as the radius of diversion fractures, diversion angle, and fracture width profile corresponding to different numbers of temporary plugging stages. Numerical simulations reveal that the primary controlling factor influencing the extension of fractures is the horizontal stress difference. A smaller horizontal stress difference makes fracture diversion easier, resulting in larger redirection radii. The impact of fracturing fluid viscosity on the diversion radius and diversion angle of fractures can be deemed negligible. Larger injection rates during construction facilitate easier diversion, leading to larger diversion radii. Furthermore, when the initial fracture angle exceeds 90°, the diversion radius of fractures is significantly larger compared to cases where the initial fracture angle is less than 90°, indicating a more facile diversion of fractures.

Modelling of mixed-mechanism stimulation for the enhancement of geothermal reservoirs.

Hydraulic stimulation is a critical process for increasing the permeability of fractured geothermal reservoirs. This technique relies on coupled hydromechanical processes induced through pressurized fluid injection into the rock formation. The injection of fluids causes poromechanical stress changes that can lead to fracture slip and shear dilation, as well as tensile fracture opening and propagation, so-called mixed-mechanism stimulation. The effective permeability of the rock is particularly enhanced when new fractures connect with pre-existing fractures. While hydraulic stimulation can significantly improve the productivity of fractured geothermal reservoirs, the process is also related to induced seismicity. Hence, understanding the coupled physics is central, for both reservoir engineering and seismic risk mitigation. This article presents a modelling approach for simulating the deformation, propagation and coalescence of fractures in porous media under the influence of anisotropic stress and fluid injection. It uses a coupled hydromechanical model for poroelastic, fractured media. Fractures are governed by contact mechanics and a fracture propagation model. For numerical solutions, we employ a two-level approach, combining a finite volume method for poroelasticity with a finite element method for fracture propagation. The study investigates the impact of injection rate, matrix permeability and stress anisotropy on stimulation outcomes.This article is part of the theme issue 'Induced seismicity in coupled subsurface systems'.

Evaluation of the combined influence of geological layer property and in-situ stresses on fracture height growth for layered formations

Fracture geometry is important when stimulating low-permeability reservoirs for natural gas or oil production. The geological layer (GL) properties and contrasts in in-situ stress are the two most important parameters for determination of the vertical fracture growth extent and containment in layered rocks. However, the method for assessing the cumulative impact on growth in height remains ambiguous. In this research, a 3D model based on the cohesive zone method is used to simulate the evolution of hydraulic fracture (HF) height in layered reservoirs. The model incorporates fluid flow and elastic deformation, considering the friction between the contacting fracture surfaces and the interaction between fracture components. First, an analytical solution that was readily available was used to validate the model. Afterwards, a quantitative analysis was performed on the combined impacts of the layer interface strength, coefficient of interlayer stress difference, and coefficient of vertical stress difference. The results indicate that the observed fracture height geometries can be categorized into three distinct regions within the parametric space: blunted fracture, crossed fracture, and T-shaped fracture. Furthermore, the results explained the formation mechanism of the low fracture height in the deep shale reservoir of the Sichuan Basin, China, as well as the distinction between fracture network patterns in mid-depth and deep shale reservoirs.

Study of the liquid resistance effect of water-in-oil emulsions in porous media

During heavy oil recovery in the Bohai Oilfield, substantial emulsification of oil and water occurred, primarily forming water-in-oil (W/O) emulsions. This phenomenon could alter fluid dynamics within the subsurface porous media, potentially impacting well production performance. To elucidate the properties of water-in-oil emulsions and their associated liquid resistance effects, this study conducted a series of rheological tests, microscopic examinations, and injection experiments. The results show that the droplet size and distribution of water-in-oil emulsions were primarily influenced by shear rate and water content, which in turn modified emulsion viscosity. The stability of water-in-oil emulsions was reduced when they flowed through porous media. The increase in emulsion viscosity and the liquid resistance effect collectively enhanced the seepage resistance of water-in-oil emulsions flowing through porous media. Notably, when the emulsion droplet size exceeded the pore throat size, over 90% of the total seepage resistance was attributable to the liquid resistance effect. Conversely, when the majority of the emulsion droplets were smaller than the pore throat, the viscosity accounted for more than 60% of the seepage resistance. Water-in-oil emulsions flowed through cores with permeabilities ranging from 50 to 100 mD, exhibiting threshold pressure gradients between 35 and 43 MPa/m. At a core permeability of 300 mD, the threshold pressure gradient was significantly reduced to 1 MPa/m. The presence of a water-in-oil emulsion in the reservoir could result in a production pressure differential falling below the threshold pressure, thereby reducing reservoir productivity.

Betung Field Development Based On Petrophysical Integration Analysis And Radius Drainage

Abstract Betung Field which has a productive reservoir of sandstone layers of the Air Benakat Formation. The potential in Layer-5 (L-5) in 2018 is still quite large, with Original Oil In Place (OOIP) of 16,531.05 MSTB. This study uses Petrel Petrophysical and Oil Field Manager software. The output of Petrel Petrophysical is in the form of a petrophysical property model. The output of the Oil Field Manager is a Bubble map model to determine the cumulative production of a well. The petrophysical property model is then integrated with the Bubble map model to find locations for additional potential development wells. Based on the petrophysical distribution map, the Southeast – South area has reference wells with good quality where the porosity value is excelent (30% - 31%), permeability is good (119 mD – 139 mD) and water saturation is small (28% - 38%). Based on the map of the distribution of the drainage radius (Bubble map), the reference wells in the Southeast – South area have large draining radius (45 m/147.64 ft – 70 m/229.67 ft) with large cumulative (3513 STB – 10723 STB). Based on the petrophysical overlay results and drain radius, indicating the Southeast – South area potential for field development with the addition of further wells.

PROSPECTS FOR THE DEVELOPMENT OF THE SHEBELYN GAS CONDENSATE FIELD

The paper provides a brief geological and industrial characterization of the Shebelinsky gas-condensate field, including the height of the gas-bearing layer, the area of gas occurrence, porosity, permeability of collectors, effective gas-saturated thickness of the coppery sandstones, and araucarite strata. The peculiarity of the deposits lies in the low permeability and gas saturation, deterioration of collector properties of productive reservoirs from the lower to the upper and from the central to the peripheral part of the deposit. A structural map of the cover of coppery sandstones and a map of water saturation of all productive horizons are presented. The dynamics of gas reserves and reservoir pressures of the field over the years are shown, along with the authors; forecasts for their future dynamics. Calculations of the volumes of water saturation of horizons and the total volume of reservoir water that has invaded the gas-bearing part of the field have been conducted. An analysis of water saturation and its future prospects has been carried out. Statistical calculations of the dependence of water saturation volumes on time and reservoir pressure have been performed, indicating a decrease in the rates of water saturation at the late stage of field development. A geological section of the Shebelinsky field is presented, indicating the possibility of gas migration through tectonic faults. All factors influencing the maintenance of reservoir pressure within the deposit have been analyzed, including: contour water flooding; surface subsidence; internal waterdrive regime; the elasticity of rock formations, gas, and It is shown that drilling 12 deep wells within the Shebelinsky field did not reveal new deposits or caps but confirmed the presence of gas saturation to a depth of 5.5 thousand meters. The analysis of field development indicates a balance between gas production and its migration from deep horizons as of the year 2023. Approved development indicators and author’s options are provided, supported by actual field development. The conclusion is drawn that, due to migration with a volume of production of 1700– 1900 million m3, the field will operate for another 100 years.

Effect of Hydrate Saturation on Permeability Anisotropy for Hydrate-Bearing Turbidite Sediments Based on Pore-Scale Seepage Simulation

The permeability of natural gas hydrate (NGH) turbidite reservoirs typically exhibits significant anisotropy, with anisotropy being a crucial basis for evaluating reservoir production. The presence of hydrates, as a crucial constituent of the solid framework, not only impacts the overall permeability but also influences the permeability anisotropy. To investigate the saturation sensitivity of permeability anisotropy, a series of simulations are performed by integrating particle flow and computational fluid dynamics methods to construct the homogeneous and layered numerical samples and compute the evolution of permeability anisotropy. It is shown that the permeability is isotropic for homogeneous sediments and the isotropy remains unchanged regardless of variations in hydrate saturation. The permeability of layered sediments, in contrast, exhibits significant anisotropy due to the presence of dominant channels within the coarse layer. For uniformly distributed hydrates, the more effective blockage in coarse layers results in a reduction in anisotropy. While for preferentially distributed hydrates, the excess blocking of coarse layers makes the dominant channels transfer to the fine layers, the further blocking causes a U-shaped anisotropy–saturation curve characterized by a decrease–increase transformation. During the reservoir production process, the preponderance channels blocked by hydrates will be cleared and the horizontal permeability will significantly increase. As a result, the production efficiency of horizontal wells may exceed expectations. The findings offer a parameter support for production estimation and environmental assessment.

A new formulation for removing condensate blockage for low permeable gas reservoir

Condensate blockage significantly impairs gas production in low-permeability reservoirs by reducing gas relative permeability and increasing condensate saturation near the wellbore. Particularly acute in reservoirs with low pressure and permeability, effective solutions are required to mitigate this formation damage. This study introduces a novel acid treatment strategy aimed at enhancing the injectivity index in gas reservoirs afflicted by condensate blockage. Leveraging mineralogical analysis, Hydrochloric Acid (HCl) was identified as the optimal acidizing agent. The most effective concentrations of HCl for rock dissolution—15% and 7.5%—were determined through dissolution tests. The research further advances by adding methanol to the acid mix, resulting in three distinct formulations: HCl 15 wt%, HCl 15 wt% + methanol, and HCl 7.5 wt% + methanol. Comprehensive wettability alteration tests and coreflood experiments were conducted to evaluate the efficacy of these systems in permeability enhancement. The HCl 7.5 wt% + methanol formulation demonstrated superior performance in permeability improvement and condensate blockage reduction, outshining the other systems. Notably, this new acid system effectively altered wettability from hydrophobic to hydrophilic, facilitating the passage of condensate through the pore throats and thus aiding in the removal of blockages. The integration of methanol with HCl, particularly at a 7.5 wt% concentration, represents a significant advancement in the treatment of condensate blockage in gas reservoirs, promising to improve gas recovery rates by addressing the challenges posed by low-permeability formations.

Karst control on reservoir performance of a developed carbonate geothermal reservoir in Munich, Germany

The Upper Jurassic ‘Malm’ carbonates of southern Germany are currently the most developed reservoir for geothermal energy production in Germany. Although many studies have investigated the Malm carbonate reservoir, few studies have focused on the palaeokarst system – despite the fact that the reservoir is frequently referred to as ‘Malmkarst’. Data from 25 wells in the Malm reservoir, including well logs, seismic data and hydraulic information, systematically demonstrate the presence of karstification. This is apparent in the form of large sinkholes and amplitude anomalies on the seismic scale, as well as caves observed in the image log and caliper log data. Flowmeter logs correlated with the karstified section on the image log reveal thin zones of elevated permeability, contributing most of the flow at the wellbore scale. The comparison between measurements from core data and well tests provides evidence of the reservoir's excess permeability, exhibiting values several orders of magnitude higher than those measurable in cores. The stratigraphic record suggests that karstification occurred during the Jurassic and Cretaceous, prior to the burial of the carbonates by the sediments of the alpine molasse basin.

Oscillation Times in Water Hammer Signatures: New Insights for the Evaluation of Diversion Effectiveness in Field Cases

Diversion is a crucial technique for effectively improving shale reservoir production by creating more complex fracture networks. Evaluating diversion effectiveness is necessary to optimize the parameters in hydraulic fracturing. Water hammer diagnostics, an emerging fracturing diagnosis technique, evaluate diversion effectiveness by analyzing water hammer signals. The water hammer attenuation, as indicated by the oscillation time, correlates with the complexity of fracture networks. However, it remains unclear whether the oscillation time is associated with diversion effectiveness. This paper elucidates the relationship between the water hammer oscillation time and diversion effectiveness by taking the probability of diversion and the treating pressure response as the evaluation criteria. Initially, a high-frequency pressure sensor was installed at the wellhead to sample the water hammer signals. Next, the oscillation times were determined using the feature extraction method. Simultaneously, the probability of diversion and the treating pressure response were calculated using the cepstrum error function and treating pressure curve, respectively. Then, the relationship between the oscillation time and diversion effectiveness was analyzed. Finally, a rapid judgment method for evaluating diversion effectiveness based on the water hammer oscillation time was proposed. The results indicated a negative correlation between the probability of diversion and the oscillation time, with higher probabilities resulting in lower oscillation times. The oscillation times exhibited a negative correlation with the treating pressure response, including the treating pressure increases and diversion pressure spikes, wherein a greater pressure differential led to lower oscillation times. Drawing from the statistics of a shale gas horizontal well in Sichuan, a better diversion effectiveness is associated with fewer oscillations, demonstrating a negative correlation between the diversion effectiveness and the oscillation time in water hammer signatures. Finally, a rapid judgment method for evaluating diversion effectiveness was proposed, utilizing the 95% confidence interval of the mean oscillation time. This paper offers useful insights into evaluating diversion performance in field cases.