Reservoir Matrix Research Articles

Rigorous Estimation of the Initial Conditions of Flowback Using a Coupled Hydraulic-Fracture/Dynamic-Drainage-Area Leakoff Model Constrained by Laboratory Geomechanical Data

Summary The application of rate-transient-analysis (RTA) concepts to flowback data gathered from multifractured horizontal wells (MFHWs) completed in tight/shale reservoirs has recently been proposed as an independent method for quantitatively evaluating hydraulic-fracture volume/conductivity. However, the initial fluid pressures and saturation in the fracture network and adjacent reservoir matrix are generally unknown at the start of flowback, creating significant uncertainty in the quantitative analysis of flowback data. In this study, we present a semianalytical flow model, coupled with a hydraulic-fracture (fracture) model and constrained with laboratory-based geomechanical data, for evaluating the initial conditions of flowback. In previous work, a semianalytical model based on the dynamic-drainage-area (DDA) concept was used to simulate water-based fluid leakoff from an MFHW into a tight oil reservoir (Montney Formation, western Canada), with minimal mobile water, during and after fracturing operations. The model assumed that each fracturing stage can be represented by a primary hydraulic fracture (PHF) containing the majority of the proppant, and an adjacent nonstimulated reservoir (NSR) or enhanced fracture region (EFR), which is an area of elevated permeability in the reservoir caused by the stimulation treatment. Each region was represented by a single-porosity system. The DDA propagation speed within the PHF during the stimulation treatment was constrained through using a simple analytical fracture model. Although this approach was considered novel, several improvements and additional laboratory constraints were considered necessary to yield more accurate predictions of initial flowback conditions. In the current work, the modeling approach described previously was improved by representing the EFR with a dual-porosity system; fully coupling the fracture model (used for PHF creation and propagation) with the DDA model for fluid-leakoff simulation into the EFR and adding a proppant-transport model; and modeling the shut-in period. Finally, to ensure that model geomechanics were properly constrained, a comprehensive suite of previously gathered laboratory data was used. Laboratory-derived propped (PHF) and unpropped (EFR) fracture-permeability/conductivity data as a function of pore pressure, as well as fracture-compressibility data, were used as constraints for the model. It should be noted that our model assumes that fracture closure has no effect on the pressure/saturation of the PHF/EFR/matrix. The improved model was reapplied to the tight oil field case and yielded more realistic estimates of initial flowback conditions, enabling more confident history matching of flowback data. The results of this study will be important to those petroleum engineers interested in quantitative analysis of flowback data to accurately obtain fracture properties by ensuring proper model creation.

Productivity analysis of fractured wells in reservoir of hydrogen and carbon based on dual-porosity medium model

Hydrogen is usually locked in energy-rich organic compounds and there is almost no pure hydrogen in nature. Organic compounds produced in reservoirs of hydrogen and carbon are an important source of hydrogen production. Understanding the productivity characteristics reservoirs of hydrogen and carbon is the important step to ensure adequate hydrogen energy. This study analyzes the production of hydraulically fractured organic reservoir of hydrogen and carbon. First, based on the diffusion mechanism in reservoir matrix, a multi-scale dual-porosity medium model of reservoir of hydrogen and carbon is established. Then, the mathematical model is solved and verified through a historical matching of field gas production data. Finally, parameter analysis was performed to determine the key parameters to improve the recovery efficiency in organic reservoir of hydrogen and carbon. Results show that improving fracture permeability can improve gas recovery efficiency of hydrocarbon reservoirs. The matrix desorption can develop natural gas production for a long period. Long sizes of hydraulic fractures have large contact surfaces for gas diffusion and increase gas generation and cumulative gas production. The proposed model can predict and analyze the production performance of reservoirs of hydrogen and carbon.

A semi-analytical model for investigating the productivity of fractured horizontal wells in tight oil reservoirs with micro-fractures

Combining horizontal drilling with hydraulic fracturing has become a well-established technique to improve well productivity in tight oil reservoirs. The existence of micro-fractures in these reservoirs affects the fluid flow process as well as the productivity. However, current models for evaluating the well performance of fractured horizontal wells containing micro-fractures lack accuracy. Hence, the objective of this study is to build an efficient model to analyze well productivity, considering the effects of micro-fractures. A novel flow model for multi-fractured horizontal wells was established, considering the effect of micro-fractures on the fluid flow. Subsequently, we built a reservoir model based on the typical fracture and fluid properties of a tight oil block in the Daqing oil field, China. Good agreement between the prediction results and field data was obtained, indicating that the effect of micro-fractures on well productivity cannot be neglected. Further study reveals that micro-fractures essentially function as a joint connecting reservoir matrix and have a persistent impact on well productivity. Micro-fractures can promote well productivity; however, if the value of micro-fracture permeability increases, this promotional effect will slow down. Well productivity can be considerably improved as an increase in micro-fracture percentage. Finally, a series of sensitivity studies were conducted to identify the effects of critical parameters on well productivity. Results show that reservoir permeability significantly influences well productivity, followed by reservoir effective thickness, micro-fracture percentage, fracture number, hydraulic fracture half-length. Pressure sensitivity coefficient, threshold pressure gradient and micro-fracture permeability have the least effect on well productivity. This work provides a sophisticated and efficient tool to evaluate the productivity of multi-fractured horizontal wells in tight oil reservoirs with micro-fractures.

Statistical analyses of reservoir and fracturing parameters for a multifractured shale oil reservoir in Mississippi

AbstractThe use of multifractured horizontal wells has improved the efficiency of hydrocarbon extraction from shale gas and oil plays. It is highly desirable to estimate the characteristics of the reservoir and well fracturing through production data analysis. Production rate transient data from 16 wells in the Mississippi sections were analyzed to estimate local reservoir permeability and hydraulic fracture parameters. Key factors affecting well productivity have been identified for optimizing future well completion. Based on the theory of distance of investigation during transient linear flow, the reservoir matrix permeability of TMS was estimated to be between 53 nd and 210 nd, averaging at 116 nd. The matrix permeability follows the lognormal distribution and is considered homogeneous according to the coefficient of variation. The fracture half‐length was estimated using the matrix permeability data from the rate transient analysis. The fracture half‐length was found to have a mean value of 234 ft with a standard deviation of 66 ft in a normal distribution. The fracture conductivity was back‐calculated by matching pseudosteady production rate data to Guo et al's (SPE Reserve Eval Eng.12, 2009, 879) productivity model for boundary‐dominated flow. The fracture conductivity was estimated to range from 0.4 md‐ft to 3.2 md‐ft, averaging at 1.4 md‐ft. Based on Guo et al's (SPE Reserve Eval Eng.12, 2009, 879) well productivity model applied to TMS condition, well productivity can be improved significantly by increasing fracture length and conductivity. Future TMS wells should be completed with conductivity values of greater than 10 md‐ft.

Propagation of hydraulic fracture under the joint impact of bedding planes and natural fractures in shale reservoirs

AbstractThe generation of the complex fracture network through hydraulic fracturing is a prerequisite for economic exploitation of shale gas. Bedding planes and natural fractures in shale reservoirs exert a direct impact on the propagation of hydraulic fracture and the formation of the complex fracture network. Based on theoretical analysis and flow‐stress‐damage coupled approach, the propagation of hydraulic fracture under the joint impact of the bedding planes and the natural fractures is studied. The results show the main factors that influence the fracture propagation are the horizontal principal stress difference, the minimum horizontal principal stress, the approaching angle of bedding plane (AABP), the intersection angle of natural fracture (IANF), and the cohesion of the reservoir matrix and the bedding plane. The bigger the horizontal principal stress difference is and the smaller AABP and the cohesion are, the more likely hydraulic fracture will propagate toward the direction of the maximum horizontal principle stress; the smaller AABP and the cohesion are, the more easily it will propagate along the bedding planes; AABP and IANF are the key factors that affect the fracture network formation and both of them bear a negative correlation on the principal stress difference for the formation of the fracture network; the smaller the stress difference and the cohesion difference between the bedding plane and the reservoir matrix are, and AABP is close to IANF and they are in the middle of its value range, the more easily the fracture network forms. The research results are of great significance to reveal the propagation law of hydraulic fracture and the formation of the complex fracture network in shale reservoirs and the efficient exploitation of shale gas.

Modified SLD model for coalbed methane adsorption under reservoir conditions

In the process of coalbed methane (CBM) mining, with the decreasing of reservoir pressure, stress sensitivity and matrix desorption shrinkage, which could be called self-regulating effect comprehensively, possess great effect on the gas adsorption due to the changing of pore volume. Therefore, it is necessary to modify the simplified local density (SLD) model to investigate the gas adsorption under reservoir conditions for an accurate prediction of CBM production. For the utilization of SLD adsorption model, assume the pores as slit pore. When pressure is lower than critical desorption pressure and keeps falling, the deformations of specific surface area (SSA) and pore width could be studied by the chosen Shi and Durucan (S&D) model. Furthermore, based on the variation relationship and the modification of SLD model, a new adsorption predicting model could be derived with the consideration of stress sensitivity, and matrix desorption shrinkage. In the absence of stress sensitivity and matrix desorption shrinkage, the calculated consequence is relatively smaller than the actual field adsorption data. What’s more, the sensitivity analyses of Poisson’s ratio, pore volume compressibility and critical desorption pressure are conducted with the application of this new model. At the same reservoir pressure, Poisson’s ratio possesses negative relationship with modified adsorption, while pore volume compressibility and critical desorption pressure both possess positive influence on modified adsorption. The main reason is that Poisson’s ratio affects matrix desorption shrinkage negatively, while pore volume compressibility and critical desorption pressure affect matrix desorption shrinkage positively. In spite of the opposite effect of stress sensitivity and matrix desorption shrinkage on pore deformation, matrix desorption shrinkage exhibits a dominant role in self-regulating.

An investigation of hydromechanical effect on well productivity in fractured porous media using full factorial experimental design

We propose a statistical investigation of the hydromechanical effect on well productivity in fractured porous media using full factorial experimental design. Factors affecting the well productivity have been investigated quantitatively, then ranked based on their impacts. The outcomes of this study can be used as a guideline for studying the uncertainties involved in well productivity. The results show that six main factors, initial reservoir pressure, matrix permeability, far-field stresses, fracture stiffness, fracture density, and fracture connectivity have effects on initial well productivity and its reduction, dictating the relationship between well productivity and drawdown pressure. Since the interactions among these factors cannot be neglected, all main factors should be investigated simultaneously for their effects on the well productivity. Results also show that the impact of each main factor is different, to reduce the computational cost, the most significant factors can be selected for the sensitivity analysis based on their ranks.

Drained rock volume around hydraulic fractures in porous media: planar fractures versus fractal networks

This study applies the Lindenmayer system based on fractal theory to generate synthetic fracture networks in hydraulically fractured wells. The applied flow model is based on complex analysis methods, which can quantify the flow near the fractures, and being gridless, is computationally faster than traditional discrete volume simulations. The representation of hydraulic fractures as fractals is a more realistic representation than planar bi-wing fractures used in most reservoir models. Fluid withdrawal from the reservoir with evenly spaced hydraulic fractures may leave dead zones between planar fractures. Complex fractal networks will drain the reservoir matrix more effectively, due to the mitigation of stagnation flow zones. The flow velocities, pressure response, and drained rock volume (DRV) are visualized for a variety of fractal fracture networks in a single-fracture treatment stage. The major advancement of this study is the improved representation of hydraulic fractures as complex fractals rather than restricting to planar fracture geometries. Our models indicate that when the complexity of hydraulic fracture networks increases, this will suppress the occurrence of dead flow zones. In order to increase the DRV and improve ultimate recovery, our flow models suggest that fracture treatment programs must find ways to create more complex fracture networks.

Experimental and Numerical Study on CO2 Sweep Volume during CO2 Huff-n-Puff Enhanced Oil Recovery Process in Shale Oil Reservoirs

CO2 huff-n-puff has been proven to be the most effective enhanced oil recovery (EOR) method in shale oil reservoirs. The injected CO2 will replenish reservoir energy and penetrate the reservoir matrix to extract oil. However, the CO2 sweep volume during the huff-n-puff process has not been accurately evaluated by existing studies. In this paper, the CO2 sweep volume was investigated through experimental and numerical simulation methods. In the experimental study, the CO2 sweep areas were depicted by X-ray computed tomography scan technology. The results indicated that the ratio of the CO2 sweep area was 78.63% in the seventh huff-n-puff cycle, leading to a total oil recovery of 56.80%. The numerical simulation considered the mechanisms of molecular diffusion and nanopore confinement. The results showed that in the first huff-n-puff cycle, the gas sweep volume percentage was 9.47% after 100 days of huff period. In the gas swept volume, oil viscosity was reduced by 25.9% to 68.2%. After three cycles of CO2 ...

Improved cell culture immunofluorescent assay for detection of infectious Cryptosporidium spp. in prefinished water

The New York City Department of Environmental Protection's (NYC) Hillview Reservoir is an uncovered prefinished water storage reservoir postultraviolet (post‐UV) light disinfection. As an additional tool to the detection of total (viable and nonviable) oocysts using Methods 1623/1623.1, the performance of an improved cell culture immunofluorescent assay (CC‐IFA) for the specific detection of infectious oocysts in this NYC reservoir matrix was evaluated. Mean CC‐IFA matrix spike recovery of infectious Cryptosporidium parvum and Cryptosporidium hominis oocysts was comparable to the mean Method 1623 recovery of total oocysts, ranging from 29 to 46%. Experiments using ≤5 C. parvum or ≤10 C. hominis viable oocyst spikes prepared using flow cytometry indicated that the reservoir matrix did not adversely affect CC‐IFA detection. Therefore, the improved CC‐IFA appears useful for the detection of environmentally relevant, low numbers of infectious oocysts in the reservoir matrix and for the refined assessment of Cryptosporidium risk.

Application of cumulative-in-situ-injection-production technology to supplement hydrocarbon recovery among fractured tight oil reservoirs: A case study in Changqing Oilfield, China

Water flooding and gas injection are two traditional secondary development methods for tight oil reservoirs. Water injection has the problem of small injectivity due to low permeable reservoir matrix while gas injection brings about severe breakthrough because of obvious viscosity difference between gas and oil. These traditional approaches that supplement energy between wells are not highly effective. To fill this gap, this paper proposes an efficient energy-supplement method, continuous in-situ injection and production (CIIP), among fractures for multistage fractured horizontal well (MFHW) in tight oil reservoirs. CIIP divides hydraulic fractures into two kinds, in which odd fractures are used for production while even fractures are for injection. CIIP has three main advantages over traditional water flooding: firstly, it switches displacement interval from between injection and production wells to between hydraulic fractures; secondly, CIIP has a better injectivity compared to traditional water flooding at the same injection pressure; and thirdly, CIIP improves sweep efficiency thereby improving oil recovery.In this paper, a workflow is developed to evaluate the performance of CIIP in a case study. Reservoir properties and micro-seismic (MS) mapping data are analyzed to provide fundamental parameters for building a numerical simulation model, and then history matching is achieved to validate the model. The simulation considers two scenarios of hydraulic fractures: the uniform and non-uniform fractures. Uniform-fracture simulation aims to investigate the mechanisms of CIIP under three fracture models; different fracture half-lengths and the situation of existing high permeable channels between injection and production fractures are also included in uniform-fracture simulation. Non-uniform-fracture simulation, whose fractures are interpreted according to MS mapping results, is devised to demonstrate CIIP’s superiority in a realistic way. This study is based on a theoretical approach and the results wait to be further proven in the field.Simulation results demonstrate that CIIP is an efficient energy-supplement method. It helps to maintain reservoir pressure near the initial condition during the thirty-year simulation. Meanwhile, even if ten injection wells are added, CIIP still injects 55% more water than water injection (WI) at the same injection pressure. Uniform-fracture simulation indicates that CIIP has a 2.23% more oil recovery than WI and a 3.74% than depletion. Besides, the influence of high permeable channels between injection and production fractures is insignificant and we can still expect CIIP’s good performance when hydraulic fractures hit local natural fractures. The non-uniform-fracture simulation demonstrates that CIIP performs well too when hydraulic fractures are randomly distributed. It also finds outs that the presence of primary fractures in which proppant concentrates is essential to CIIP while the role of natural fractures is trivial compared to the hydraulic fractures. In a word, CIIP is a promising technology for tight oil reservoir development.

Investigation on Interference Test for Wells Connected by a Large Fracture

Pressure communication between adjacent wells is frequently encountered in multi-stage hydraulic fractured shale gas reservoirs. An interference test is one of the most popular methods for testing the connectivity of a reservoir. Currently, there is no practical analysis model of an interference test for wells connected by large fractures. A one-dimensional equation of flow in porous media is established, and an analytical solution under the constant production rate is obtained using a similarity transformation. Based on this solution, the extremum equation of the interference test for wells connected by a large fracture is derived. The type-curve of pressure and the pressure derivative of an interference test of wells connected by a large fracture are plotted, and verified against interference test data. The extremum equation of wells connected by a large fracture differs from that for homogeneous reservoirs by a factor 2. Considering the difference of the flowing distance, it can be concluded that the pressure conductivity coefficient computed by the extremum equation of homogeneous reservoirs is accurate in the order of magnitude. On the double logarithmic type-curve, as time increases, the curves of pressure and the pressure derivative tend to be parallel straight lines with a slope of 0.5. When the crossflow of the reservoir matrix to the large fracture cannot be ignored, the slope of the parallel straight lines is 0.25. They are different from the type-curves of homogeneous and double porosity reservoirs. Therefore, the pressure derivative curve is proposed to diagnose the connection form of wells.

Insights into the role of clays in low salinity water flooding in sand columns

Clays in sandstone are thought to be a key factor in low salinity (LS) water flooding. This study investigates the effects of quartz, kaolinite and illite in LS water flooding in synthetic sand columns as a function of temperature. Four chromatography columns containing different amounts of pure quartz sand, illite, and kaolinite (100% quartz sand; 95/5% sand/illite; 95/5 sand/kaolinite; and 95/2.5/2.5% sand/illite/kaolinite). The use of these synthetic columns gives full control over mineralogy. These columns were saturated with high salinity (HS) formation water with 0.01 M (M) sodium acetate and aged for a week at 70 °C. They were then flooded with waters (yes, the use of water to displace water) with various salinities at four different temperatures (25, 70, 90 and 120 °C). Effluent concentrations of Ca2+ and acetate (CH3COO−) and pH were measured. This is a novel experimental design, where formation water containing sodium acetate is flooded with waters of varying salinity to gain insight into LS flood performance and possible recovery mechanisms. The hypothesis pursued here is that the behavior of the acetate ion (attached to matrix minerals during the aging process and then released due to ionic exchange) in an LS flood would provide a valuable analog that would simulate the bonding of carboxylic acids in crude oils with reservoir matrix minerals (and subsequent desorption during LS flooding). Key results include the following: (a) Our hypothesis was correct—the use of Na acetate behaved analogously to carboxylic acid, giving useful insights; (b) The quartz-only column showed strong evidence (elevated pH, presence of Ca2+ and acetate in effluent) of ionic exchange due to LS flooding, showing that pure quartz is responsive to LS flooding and that clays are not absolutely needed; (c) Quartz plus kaolinite plus illite gave a slightly higher response than pure quartz so clays can play a role. Oil displacement results were also done for a pure quartz sand column, and this showed a strong response to the LS flood, confirming that clays are not absolutely needed.

Petrophysical characterisation of reservoir intervals in well-X and well-Y, M-Field, offshore Douala Sub-Basin, Cameroon

Studies for the characterization of hydrocarbon reservoirs using well logs have been carried out in the M-Field of the Douala Basin to evaluate the hydrocarbon prospectivity, delineate hydrocarbon zones and determine the petrophysical properties of the identified reservoir rocks. Data from two wells comprising gamma ray, resistivity, neutron, density logs were used. Gamma ray log was used for lithologic discrimination; resistivity log was employed to identify formation fluid based on electrical responses of reservoir formations, while combined density and neutron logs were used to estimate reservoir porosity, as well as ascertain hydrocarbon type where present. Four hydrocarbon bearing reservoirs were delineated in the study area; one in Well-X (X2) with a thickness of 6.2 m and three others in Well-Y (Y1, Y2, Y3) with thicknesses of 19.2 m, 7.6 m and 78.7 m, respectively. Neutron–density crossplots indicate heterogeneous reservoir matrix comprising of sand, limestone and dolomite. The reservoirs were correlated using gamma ray log and were found to be discontinuous across the wells. The petrophysical parameters of the reservoirs evaluated indicate porosity, water-saturation and hydrocarbon-saturation values of X2 to be 20.8%, 30.8% and 69.2%, respectively, and the average porosity, water saturation and hydrocarbon saturation of the Well-Y reservoirs to be 40.2%, 18.3% and 81.7%, respectively. The porosity value indicates medium–high formation porosities and oil as the dominant hydrocarbon type. The crossplot of water-saturation and porosity revealed that the grain size variation of the reservoirs ranges from fine-grained to silty sands. The bulk volume water (BVW) values for the M-Field reservoirs suggest that they are homogeneous and at irreducible water saturation (Swirr) and hence will produce water-free hydrocarbons.

Mitigating Sulfidogenesis With Simultaneous Perchlorate and Nitrate Treatments.

Sulfide biogenesis (souring) in oil reservoirs is an extensive and costly problem. Nitrate is currently used as a souring inhibitor but often requires high concentrations and yields inconsistent results. Recently, perchlorate has displayed promise as a more potent inhibitor in lab scale studies. However, combining the two treatments to determine synergy and effectiveness in a dynamic system has never been tested. Nitrate inhibits perchlorate consumption by perchlorate reducing bacteria, suggesting that the combined treatment may allow deeper penetration of the perchlorate into the reservoir matrix. Furthermore, the metabolic intermediates of perchlorate and nitrate reduction (nitrite and chlorite, respectively) are synergistic with the primary electron acceptors for inhibition of sulfate reduction. To assess the possible synergies between nitrate and perchlorate treatments, triplicate glass columns packed with pre-soured marine sediment were flushed with media containing sulfate and an inhibitor treatment [(i) perchlorate; (ii) nitrate; (iii) perchlorate and nitrate; or (iv) none]. Internal geochemistry and microbial community changes were monitored along the length of the columns during six phases of increasing treatment concentrations. In a final phase all treatments were removed. Sulfide production decreased in all treated columns in conjunction with increased inhibitor concentrations relative to the untreated control. Interestingly, the potency of the “mixed” treatment was additive relative to the individual treatments suggesting no interaction. Microbial community analyses indicated community shifts and clustering by treatment. The mixed treatment column community’s trajectory closely resembled that of the community found in the perchlorate only treatment, suggesting that perchlorate was the dominant control on the “mixed” community structure. In contrast, the nitrate and untreated column communities had unique trajectories. This study indicates that concurrent nitrate and perchlorate treatment is not more effective than perchlorate treatment alone but is more effective than nitrate treatment. As such, treatment decisions may be based on economic factors.

Geomechanical Response of Fractured Reservoirs

Geologic carbon storage will most likely be feasible only if carbon dioxide (CO2) is utilized for improved oil recovery (IOR). The majority of carbonate reservoirs that bear hydrocarbons are fractured. Thus, the geomechanical response of the reservoir and caprock to IOR operations is controlled by pre-existing fractures. However, given the complexity of including fractures in numerical models, they are usually neglected and incorporated into an equivalent porous media. In this paper, we perform fully coupled thermo-hydro-mechanical numerical simulations of fluid injection and production into a naturally fractured carbonate reservoir. Simulation results show that fluid pressure propagates through the fractures much faster than the reservoir matrix as a result of their permeability contrast. Nevertheless, pressure diffusion propagates through the matrix blocks within days, reaching equilibrium with the fluid pressure in the fractures. In contrast, the cooling front remains within the fractures because it advances much faster by advection through the fractures than by conduction towards the matrix blocks. Moreover, the total stresses change proportionally to pressure changes and inversely proportional to temperature changes, with the maximum change occurring in the longitudinal direction of the fracture and the minimum in the direction normal to it. We find that shear failure is more likely to occur in the fractures and reservoir matrix that undergo cooling than in the region that is only affected by pressure changes. We also find that stability changes in the caprock are small and its integrity is maintained. We conclude that explicitly including fractures into numerical models permits identifying fracture instability that may be otherwise neglected.

Coupled THM and Matrix Stability Modeling of Hydroshearing Stimulation in a Coupled Fracture-Matrix Hot Volcanic System

A coupled thermal-hydraulic-mechanical (THM) model is developed to simulate the combined effect of fracture fluid flow, heat transfer from the matrix to injected fluid, and shearing dilation behaviors in a coupled fracture-matrix hot volcanic reservoir system. Fluid flows in the fracture are calculated based on the cubic law. Heat transfer within the fracture involved is thermal conduction, thermal advection, and thermal dispersion; within the reservoir matrix, thermal conduction is the only mode of heat transfer. In view of the expansion of the fracture network, deformation and thermal-induced stress model are added to the matrix node’s in situ stress environment in each time step to analyze the stability of the matrix. A series of results from the coupled THM model, induced stress, and matrix stability indicate that thermal-induced aperture plays a dominant role near the injection well to enhance the conductivity of the fracture. Away from the injection well, the conductivity of the fracture is contributed by shear dilation. The induced stress has the maximum value at the injection point; the deformation-induced stress has large value with smaller affected range; on the contrary, thermal-induced stress has small value with larger affected range. Matrix stability simulation results indicate that the stability of the matrix nodes may be destroyed; this mechanism is helpful to create complex fracture networks.

Case Study: 4D Coupled Reservoir/Geomechanics Simulation of a High-Pressure/High-Temperature Naturally Fractured Reservoir

Summary The Keshen Reservoir is a naturally fractured, deep, tight sandstone gas reservoir under high tectonic stress. Because the reservoir matrix is very tight, the natural-fracture system is the main pathway for gas production. Meanwhile, stimulation is still required for most production wells to provide production rates that sufficiently compensate for the high cost of drilling and completing wells to access this deep reservoir. Large depletion (and related stress change) was expected during the course of the production of the field. The dynamic response of the reservoir and related risks, such as reduction of fracture conductivity, fault reactivation, and casing failure, would compromise the long-term productivity of the reservoir. To quantify the dynamic response of the reservoir and related risks, a 4D reservoir/geomechanics simulation was conducted for Keshen Reservoir by following an integrated work flow. The work started from systematic laboratory fracture-conductivity tests performed with fractured cores to measure conductivity vs. confining stress for both natural fractures and hydraulic fractures (with proppant placed in the fractures of the core samples). Natural-fracture modeling was conducted to generate a discrete-fracture network (DFN) to delineate spatial distribution of the natural-fracture system. In addition, hydraulic-fracture modeling was conducted to delineate the geometry of the hydraulic-fracture system for the stimulated wells. Then, a 3D geomechanical model was constructed by integrating geological, petrophysical, and geomechanical data, and both the DFN and hydraulic-fracture system were incorporated into the 3D geomechanical model. A 4D reservoir/geomechanics simulation was conducted through coupling with a reservoir simulator to predict variations of stress and strain of rock matrix as well as natural fractures and hydraulic fractures during field production. At each study-well location, a near-wellbore model was extracted from the full-field model, and casing and cement were installed to evaluate well integrity during production. The 4D reservoir/geomechanics simulation revealed that there would be a large reduction of conductivity for both natural fractures and hydraulic fractures, and some fractures with certain dip/dip azimuth will be reactivated during the course of field production. The induced-stress change will also compromise well integrity for those poorly cemented wellbores. The field-development plan must consider all these risks to ensure sustainable long-term production. The paper presents a 4D coupled geomechanics/reservoir-simulation study applied to a high-pressure/high-temperature (HP/HT) naturally fractured reservoir, which has rarely been published previously. The study adapted several new techniques to quantify the mechanical response of both natural fractures and hydraulic fractures, such as using laboratory tests to measure stress sensitivity of natural fractures, integrating DFN and hydraulic-fracture systems into 4D geomechanics simulation, and evaluating well integrity on both the reservoir scale and the near-wellbore scale.

Evaluation and selection of numerical simulation methods for shale gas reservoirs

The complex fracture network brings great challenge to the numerical simulation of shale gas reservoirs. Based on the discrete fracture model (DFM), micro scale model and field scale model are established to investigate the influence of fracture types on the reservoir performance when the correspondence of matrix permeability and fracture aperture is different. Results show that: because the magnitude of shale gas reservoir matrix permeability is (10−8–10−4)×10−3μm2 and the SRV is a prerequisite for shale gas production, hydraulic fractures play an important role in the shale gas production while the contribution of natural fractures in and out the SRV is relatively small. Therefore, considering the computational complexity and precision, natural fractures can be characterized by matrix-natural fracture apparent permeability model and continuum model while the hydraulic fracture can be characterized by the discrete fracture network (DFN) with less computational grids and high efficient.

Dynamic changes of dissolved organic matter during nitrate transport in a loose-pore geothermal reservoir

The dynamic changes of dissolved organic matter (DOM) during nitrate transport were investigated to explore the relationship between carbon sources and the nitrate reduction process in a loose-pore geothermal reservoir. Batch experiments were performed at four temperature levels (4 °C, 25 °C, 35 °C, and 45 °C) to determine the characteristics of the DOM extracted from the geothermal reservoir matrix. According to its fluorescence spectra, fluorescence index (FI), and biological/autochthonous index (BIX), the DOM was mainly derived by autochthonous microbial processes. Column experiments were carried out at 25 °C, 35 °C and 45 °C to determine the dynamic changes of the matrix DOM during nitrate transport in the simulated geothermal reservoir. The dynamic changes of the FIs; the fluorescence intensities (divided by dissolved organic carbon) of peaks B1 and T1; and concentrations of NO3−-N, NO2−-N, NH4+-N and the total dissolved inorganic nitrogen (∑N) in the column effluent within 412 h (10.5 PV) indicated that the reduction rate of nitrate and the production of denitrifiers were enhanced with an increase in temperature. Although a red shift of peak T2 during experiment at 35 and 45 °C implied the variation of the aromatic components of DOM during denitrification, low molecular weight aliphatic hydrocarbons in the matrix DOM were more active as electron donors than the aromatic compounds, as indicated by the variations of the effluent pH and SUVA254 values. No obvious trend in the variation of the BIX with temperature was observed possibly due to the short test duration of the column experiments. The findings should advance our understanding of the biological transformation of nitrate in loose-pore geothermal reservoirs.