Hydraulic Fracture Properties Research Articles

Pressure- and Rate-Transient Model for an Array of Interfering Fractured Horizontal Wells in Unconventional Reservoirs

Summary An analytical solution is presented for pressure- and rate-transient behavior of an array of n parallel and fractured horizontal wells in an unconventional reservoir. Wells are of equal length but otherwise of unidentical properties. Each well has an arbitrary number of uniformly spaced identical, finite-conductivity fractures and is surrounded by a stimulated reservoir volume (SRV). The properties of hydraulic fractures (HFs) and SRVs may vary from well to well. Different properties may also be assigned to the unstimulated reservoir sections between wells. Natural fractures in stimulated and unstimulated reservoir volumes are accounted for by transient dual-porosity idealization. The flow domain is divided into blocks of 1D flow under the trilinear-flow assumption. Solution for each block is obtained analytically and coupled with the solutions for the neighboring blocks by the continuity of pressure and flux at the block interfaces. Drainage volumes of wells are adjusted based on the variation of well production rates because of moving no-flow boundaries between wells. The superposition principle is applied to consider variable-production conditions as well as nonsynchronous production and shut-in schedules of wells. The final solution is in the form of a matrix-vector equation in the Laplace transform domain and inverted into the time domain numerically. The model is robust and reasonably accurate for most practical applications of single-phase oil and gas production from multiple wells in an unconventional reservoir. It is an efficient tool to assess well interference effects for different well completion designs and varying reservoir characteristics. The speed of the model makes it useful for pressure-transient and production-data analysis, as well as for the initial calibration and verification of more complex numerical models.

Hydraulic properties of stressed granite fractures with heat-induced void alteration

During the extraction of geothermal heat, the changes in temperature and pressure environments can alter the mechanical and hydraulic behavior of fractured rock masses, affecting the overall transmissivity and heat extraction efficiency accordingly. This study carried out a series of experiments, including X-ray diffraction (XRD), scanning electron microscope (SEM), uniaxial compression tests, and surface morphological scanning, to explore the influence of reservoir temperature on the mechanical behavior of granite and fracture surface topography. The results indicate that as the temperature increases, the uniaxial compressive strength, elastic modulus, and Poisson's ratio of granite show similar variation patterns that increase as the temperature approaches 200 °C and then decrease. In addition, with the increase in temperature, the overall surface elevation and roughness parameters generally decrease due to surface asperity degradation, with the maximum mean mechanical aperture found at 200 °C. Flow simulations were conducted to further explore the influence of temperature and pressure environments on fracture transmissivity and flow fields. It is found that the normalized equivalent hydraulic aperture BN of the tested fractures decreases progressively as the stress increases, and more scattered distributions of BN are observed under higher compressive stresses. Moreover, with the continuous increase in temperature, the average BN slowly increases to its peak of ~0.78 at 200 °C, then it decreases to ~0.76 at 300 °C and remains nearly constant. These findings can be important for assessing heat production performances during the geothermal extraction process with spatially and temporally varying reservoir temperatures and pressures.

Analysis and prediction of contact characteristics of rock fracture surfaces under normal loading

The real contact area of rock fractures is smaller than the nominal area, and actual stresses on contacts are significantly higher. Evaluating contact characteristics and predicting potential contact areas are crucial for understanding mechanical and hydraulic properties of geological fractures under compression or shear. We measured the real contact area of mated tensile fractures using pressure-sensitive films and studied their contact characteristics and evolution under different normal stresses through point cloud analysis. It is revealed that the initial aperture of mated tensile fractures determines the contact state. Under conditions of low normal stress, regions exhibiting higher mean curvature are more susceptible to contact formation, particularly when aperture sizes are comparable. This propensity is further influenced by the directional orientation of the normal vector components within these regions. Increasing normal stress leads to faster development of new contacts in regions with smaller initial apertures. Additionally, we predicted contact characteristics and real contact area of tensile fractures using back propagation artificial neural network. Comparison between predictions and laboratory measurements demonstrated accurate prediction of contact distribution and area values by the neural network. Our findings enable the prediction of real stress states, potential failure areas, and hydraulic conductivity of rock fractures in slope and underground rock engineering.

Integrated wellbore-reservoir-geomechanics modeling for enhanced interpretation of distributed fiber-optic strain sensing data in hydraulic-fracture analysis

Fiber-optic distributed strain sensing (FO-DSS) has been successful in monitoring strain changes along horizontal wellbores in hydraulically fractured reservoirs. However, the mechanism driving the various FO-DSS responses associated with near-wellbore hydraulic fracture properties is still unclear. To address this knowledge gap, we use coupled wellbore-reservoir-geomechanics simulations to study measured strain-change behavior and infer hydraulic fracture characteristics. The crossflow among fractures is captured through explicit modeling of the transient wellbore flow. In addition, local grid refinement is applied to accurately capture strain changes along the fiber. A Base Case model was designed with four fractures of varying properties, simulating strain change signals when the production well is shut-in for 10 d after 240 d of production and reopened for 2 d. Strain-pressure plots for different fracture clusters were used to gain insights into inferring fracture properties using DSS data. When comparing the model with and without the wellbore, distinct strain change signals were observed, emphasizing the importance of incorporating the wellbore in FO-DSS modeling. The effects of fracture spacing and matrix permeability on strain change signals were thoroughly investigated. The results of our numerical study can improve the understanding of the relation between DSS signals and fracture hydraulic properties, thus maximizing the value of the dataset for fracture diagnostics and characterization.

Numerical simulation of the thermo-hydro-chemical coupling in enhanced geothermal systems: Impact of SiO2 dissolution/precipitation in matrix and fractures

The hydraulic properties of reservoir matrix and fractures, as well as the production performance of enhanced geothermal systems, can be significantly affected by chemical dissolution and precipitation. Therefore, chemical reaction effects must be considered when exploiting dry hot rock resources. To investigate the impact of chemical effects, this study incorporates the dissolution/precipitation process of silica in the reservoir matrix and fractures and establishes a thermo-hydro-chemical coupling dual-well model that includes a main fracture and multiple secondary fractures. Results indicate that under-saturation injections increase the mechanical aperture of the main fracture by up to 0.066 mm and permeability by up to 217.3 % over a 30-year production period. Oversaturation injections decrease the mechanical aperture by up to 0.035 mm and permeability by up to 66.1 %. Reservoir matrix permeability exhibits a noticeable zonal distribution, with a maximum increase of 22.6 % in the under-saturation injection and a maximum decrease of 4.1 % in the saturation injection over a 30-year production period. Chemical reactions have a significant impact on the average production pressure. Neglecting chemical reactions in the matrix may result in overestimation or underestimation of changes in production pressure. These results provide a reference for the sustainable production of EGS in the long term.

Stiff, Smooth, and Solid? Complex Fracture Hydraulics' Imprint on Oscillatory Hydraulic Testing

AbstractFractured bedrock aquifers, especially deep aquifers, represent increasingly common targets for waste storage and alternative energy development, necessitating detailed quantitative descriptions of fracture hydraulic properties, geometry, and connectivity. Yet, multi‐scale characterization of the physical properties that govern fluid flow through and storage in fractured bedrock remains a fundamental hydrogeologic challenge. Oscillatory hydraulic testing, a novel hydraulic characterization technique, has been showing promise in field experiments to characterize the effective hydraulic properties of bedrock fractures. To date, these characterization efforts utilize simplified diffusive analytical models that conceptualize a non‐deforming, parallel‐plate fracture embedded within impermeable host rock, and have found that the returned fracture hydraulic parameter estimates exhibit an apparent period‐dependence. We conduct synthetic experiments using three different numerical models to examine proposed mechanisms that might contribute to the observed period‐dependence including heterogeneous flow and storage within the fracture (i.e., aperture heterogeneity), fracture‐host rock fluid exchange, and fracture hydromechanics. This work represents the first systematic analysis that seeks to understand the process(es) occurring within a bedrock fracture that might be contributing to this apparent period‐dependence. Our analysis demonstrates that all investigated mechanisms generate period‐dependent effective hydraulic parameter estimates, each with their own potentially diagnostic trends; however, fracture hydromechanics is the only explored mechanism that consistently reproduces period‐dependent trends in parameter estimates that are consistent with existing field investigations. These results highlight the need to develop more complex numerical modeling approaches that account for this hydromechanical behavior when characterizing fractured bedrock aquifers.

Size effect on hydraulic properties of rough-walled fractures upscaled from meter-scale granite fractures

To better bridge the gap between lab-scale data and larger-scale applications. In this study, an integrated method was developed to investigate the size dependence of fluid flow through rough-walled fractures. Granite fracture surfaces of up to 1 m in size were first scanned to acquire data on their morphology and corresponding surface distribution, the asperity height of which was found to follow a normal distribution. Digital fracture surfaces were then created on the basis of the scanned data and upscaled to 20 m by a statistical method, and individual rough-walled fractures were constructed by superimposing two statistically generated surfaces. Fluid flow through the fractures was subsequently simulated by solving the Reynolds’ equation. The simulated results showed evident links between the hydraulic properties and sample sizes. Specifically, both hydraulic aperture and transmissivity of the fracture varied as sample sizes increased until a threshold ranging from 2 to 5 m, beyond which an invariant transmissivity was attained. Thus, the sample size corresponding to invariant transmissivity could be defined as the representative size, the value of which was found to depend on the fracture aperture and roughness. In particular, whereas the augmentation of the fracture aperture appeared to suppress the size dependence on hydraulic properties, increased roughness tended to increase size dependence. The data and modelling presented herein provide insights into the scale dependence of fluid flow through a single fracture. It is concluded that even samples as large as 1 m may not be sufficient to characterize the hydraulic properties of fractures according to the representative sizes obtained, which usually exceeded 2 m under the conditions specified in the present study.

Stage-by-Stage Hydraulic Fracture and Reservoir Characterization through Integration of Post-Fracture Pressure Decay Analysis and the Flowback Diagnostic Fracture Injection Test Method

Summary The post-fracture pressure decay (PFPD) technique is a low-cost method allowing for stage-by-stage hydraulic fracture characterization. The analysis of the PFPD data is complex, with data affected by both hydraulic fracture and reservoir properties. Available analysis methods in the literature are oversimplified; reservoir or fracture properties are often assumed to be constant along the horizontal well, and therefore changes in the trend of pressure decay data are attributed to hydraulic fracture or reservoir properties only. Moreover, methods analogous to those applied to the analysis of conventional diagnostic fracture injection tests (DFITs) are often used and ignore critical mechanisms involved in main-stage hydraulic fracture stimulation. A conceptual numerical simulation study was first conducted herein to understand the key mechanisms involved in main-stage hydraulic fracturing. An analytical model was then developed to account for the dynamic behavior of the hydraulic fracture, leakoff, proppant distribution, multiple fractures, and propped- and unpropped-closure events. The analytical model is cast in the form of a new straightline analysis (SLA) method that provides stage-by-stage estimates of the ratio of unpropped fracture surface area to total fracture surface area. The SLA method was validated against numerical simulation results. Moreover, to account for the variation of reservoir properties along the horizontal well, the PFPD model is integrated with DFIT-flowback (DFIT-FBA) tests, performed at some points along the lateral, to obtain a reliable stage-by-stage hydraulic fracture and reservoir characterization approach. The practical application of the proposed integrated approach was demonstrated using PFPD and DFIT-FBA data from a horizontal well completed in 22 stages in the Montney Formation. The numerical simulation study demonstrated that the use of proppant and injection into multiple clusters (creating multiple fractures) results in multiple closure events. The closure process may start early after the pump-in period at a pressure significantly higher than the minimum in-situ stress. Using DFIT-based analytical models, which ignore the presence of proppant, causes significant errors in hydraulic fracture and reservoir property estimation. The PFPD field data examined herein exhibited a similar pressure trend to the numerical simulation cases. The ratio of unpropped fracture surface area to total fracture surface area was determined stage by stage using the PFPD SLA method, constrained by DFIT-FBA data. Engineers can use this information to optimize the hydraulic fracture stimulation design in real time, optimize the well spacing, and forecast the production. The cost and time advantages of this diagnostic method make this approach very attractive.

A two-phase type-curve method with multiscale fluid transport mechanisms in hydraulically fractured shale reservoirs

The quantitative understanding of hydraulic fracture (HF) properties guides accurate production forecasts and reserve estimation. Type curve is a powerful technique to characterize HF and reservoir properties from flowback and long-term production data. However, two-phase flow of water and hydrocarbon after an HF stimulation together with the complex transport mechanisms in shale nanopores exacerbate the nonlinearity of the transport equation, causing errors in type-curve analysis. Accordingly, we propose a new two-phase type-curve method to estimate HF properties, such as HF volume and permeability of fracture, through the analysis of flowback data of multi-fractured shale wells. The proposed type curve is based on a semianalytical solution that couples the two-phase flow from the matrix with the flow in HF by incorporating matrix influx, slippage effect, stress dependence, and the spatial variation of fluid properties in inorganic and organic pores. For the first time, multiple fluid transport mechanisms are considered into two-phase type-curve analysis for shale reservoirs. We analyze the flowback data from a multi-fractured horizontal well in a shale gas reservoir to verify the field application of the proposed method. The results show that the fracture properties calculated by the type-curve method are in good agreement with the long-time production data.

Semi-analytical solution for bottomhole pressure transient analysis of a hydraulically fractured horizontal well in a fracture-cavity reservoir

This paper study the role of hydraulic fracture properties on the transient bottomhole pressure (BHP) behavior of a horizontal well producing from a tight fracture-cavity reservoir. A combination of point source function, Laplace transformation and Perturbation transformation are used to obtain BHP step by step. Through literature comparison and numerical simulation, the results of BHP have a good consistency, which indicates the proposed method is scientific and reasonable. We divide the fluid flow into five stages, namely the wellbore storage stage, the karst cave fluid flows to the fracture stage, the radial flow stage of karst cave and fracture system, the matrix fluid flows to the fracture stage and the quasi-steady state stage. We come to the conclusion that the number of fractures and fracture direction mainly affect radial flow stage. In contrast, the length of horizontal subsection and skin factor mainly affect the karst cave fluid flows to the fracture stage. The matrix fluid flows to the fracture stage is more obvious when the fracture half-length and the horizontal segment spacing of the horizontal well are small. The study believes special attention should be paid to reforming the formations at both ends of the horizontal well. The advantage of this method is to incorporate well geometry (skin factor) and hydraulic fracturing design (fracture parameters), which is useful for well test interpretation through generating a new set of type curves. What’s more, this new method has the characteristics of easy calculation. The findings of this study can help for better understanding of well test analysis in fracture-cavity reservoir. However, the limitation of this study is that it is only suitable for this situation the horizontal well does not encounter karst caves and the karst caves in the reservoir are connected to the wellbore through fractures.

Carbon neutral oil assessment using a dual-porosity compositional model in unconventional reservoirs

The combined use of CO2 for enhanced oil recovery (EOR) and decarbonization has not been viewed favorably by environmentalists because the combustion of oil emits CO2. However, the use of CO2 for EOR and the consequential decarbonization is a viable and practical option that can be viewed as a win-win situation given other alternatives. Thus, we embarked on this study to assess the benefits of the process by modeling its application in the Niobrara and Codell unconventional formations in the Wattenberg Field of the Denver-Julesburg (DJ) Basin, Colorado. The modeling results provide an inexpensive substitute for the current non-existing field pilot tests. Modeling the reservoir geology and production performance in the unconventional resources of the DJ Basin is challenging because of the presence of numerous faults, micro-fractures, and macro-fractures. In this numerical model study, we used much large fracture permeabilities and compaction coefficients in the vicinity of major faults and we obtained hydraulic fracture dimensions and properties from a credible geomechanics simulator GOHFER. Seismic data, well logs, cores, PVT analyses, and field production data were integrated to construct the numerical flow model. The input reservoir permeabilities for the model were obtained from the rate transient analyses (RTA) of production data. After achieving a history match of production data for eleven wells, theoretical RTAs were conducted on each well using the modeled pressure and flowrate data to calculate the formation permeabilities to confirm the simulation accuracy. Despite the complexity of the well completion and reservoir heterogeneity in the model, the RTA analyses of the model production results for all eleven wells yielded the input reservoir permeability within an acceptable error tolerance. Moreover, a term named “Carbon Neutrality Index (CNI)” is defined in this research where CNI = 0 indicates carbon neutrality while negative CNI values indicates that the produced incremental EOR oil is carbon negative and there is a net decrease in carbon emission. When our validated numerical model was used to simulate a 4-year huff-n-puff CO2-EOR process, the results yielded a positive CNI value—indicating that the EOR oil was not perfectly carbon neutral. However, the stored CO2 divided by the CO2 generated from burning the incremental EOR oil is 0.82 — indicating that there is 82% reduction in CO2 emissions per bbl of EOR oil when compared with the emissions of one barrel of conventionally produced oil. Thus, CO2-EOR in the DJ Basin unconventional reservoirs is an effective decarbonization method.

Analysis of Multiple Flow/Buildup Tests Including a 5-Year Buildup: Case Study of an Australian Shale Gas Well

Summary Long-term (multiyear) buildup tests conducted for multifractured horizontal wells (MFHWs) completed in shale reservoirs offer the unique opportunity to study and analyze flow-regimes sequences that are not commonly observed with typical buildup test periods. In this study, two buildup periods (including a rarely observed, nearly 5-year buildup), and the preceding extended flow tests, were analyzed for an MFHW completed in an Australian shale gas reservoir within the Beetaloo Basin. The objectives of the analyses were to (a) identify the sequence of flow regimes observed for each test (flow/buildup, F/BU) period; (b) extract estimates of reservoir permeability and hydraulic fracture properties; and (c) study the evolution of these properties with each subsequent test. An MFHW, the Amungee NW-1H, completed in the Velkerri B shale in Australia, was analyzed. Due to a casing deformation and inability to mill out plugs beyond this, most of the flow contribution was from the heel stages of the well. The first F/BU period was conducted from 2016 to 2021 (a nearly 5-year buildup), while the second F/BU was initiated in 2021 (buildup is currently continuing). The extended (>1 month) production tests (EPTs) preceding the buildups were analyzed using rate-transient analysis (RTA) methods [flow-regime identification/straightline /type curve analysis (TCA)] modified for shale gas properties (e.g., desorption), while the buildups were analyzed using classic pressure-transient analysis (PTA) methods. The first (~5-year) buildup period (BU 1) revealed a sequence of bilinear-linear-elliptical-pseudoradial flow followed by a second linear flow period. The first two flow regimes are interpreted to be associated with interfracture flow, while the latter is assumed to correspond to linear flow to the well. Elliptical/radial flow around fractures is rationalized to occur due to interpreted relatively short fracture half-lengths (corresponding to the high-conductivity portion of the fractures). Permeability estimates are in good agreement with diagnostic fracture injection test (DFIT) analysis. Flow-regime interpretations for the other test periods (EPTs 1 and 2, BU 2) are largely consistent, although EPT 1 flow-regime interpretation was challenged by noisy data. Permeability values derived from EPTs 1 and 2 are smaller than from buildup tests, suggesting stress sensitivity caused by drawdown. Properties derived from the analysis of BU 1 and 2 are in good agreement, suggesting that any effects caused by stress sensitivity of reservoir parameters are largely reversible. Permeability derived from all tests are much larger than those obtained from laboratory data, leading to the interpretation that natural fractures are elevating system permeability. Fracture half-lengths are also much shorter than those typically reported for MFHWs. The mostly “textbook” quality well test data obtained for this field example, combined with the length of the test periods, resulted in one of the most complete flow-regime sequences observed for an MFHW completed in a shale gas reservoir. The existence of a radial flow period observed for all test periods (interpreted to be interfracture radial flow) allows for confident estimates of reservoir permeability/skin and their evolution with each subsequent test, which is rarely reported. The radial-flow-derived permeability, combined with early linear flow analysis, also allowed fracture half-length to be estimated for all tests. This case study adds significantly to our understanding of shale gas reservoir characteristics and flow-regime sequences associated with MFHWs.

Coupled effects of elastic and plastic deformation on hydraulic properties of the geothermal fracture induced by cyclic loading-unloading processes

Sustainable and profitable energy production from Enhanced Geothermal System (EGS) requires a comprehensive understanding of the coupled effects of elastic and plastic deformation on the hydraulic evolution of geothermal fractures. Four flow-through tests were conducted on granite samples with a rough single fracture at 25–180 °C. Each test was performed on three cycles of loading-unloading processes within a confining pressure of 5–30 MPa. Experimental results indicated that the hydraulic properties are negatively correlated with confining pressure in a logarithmic manner. The coupled effects of elastic and plastic deformation induced by stress loading are the main factor affecting fracture hydraulic properties. Plastic deformation is associated with the mineral grains crush occurring in fracture contacting asperities, which is a permanent and irreversible process. Compared to the results at 25 °C, a larger reduction in permeability is observed at 180 °C, as revealed by a maximum reduction in hydraulic aperture up to >40% at this temperature. This means that larger plastic deformations in the fractures are associated with higher temperatures. Therefore, the addition of proppant is very important for sustainable geothermal development for fractured geothermal reservoirs under high-stress conditions. The ion concentration detection of the effluent solution confirms the existence of free-face dissolution in high-temperature scenarios. Generally, free-face dissolution is beneficial to low-permeability geothermal reservoirs due to its positive effects on fracture hydraulic properties. As the number of loading-unloading cycles increases, the hysteresis effect induced by plastic deformation becomes less and less. Compared to the first loading-unloading stage, the maximum decline of permeability decreases from 73% to 6% and 1% during the second and third stages, respectively. However, pressure dissolution under long-term stress loading should be further investigated, because it may disrupt the self-propping balance of geothermal fracture asperities.

Applying Reservoir Simulation and Artificial Intelligence Algorithms to Optimize Fracture Characterization and CO2 Enhanced Oil Recovery in Unconventional Reservoirs: A Case Study in the Wolfcamp Formation

Reservoir simulation for unconventional reservoirs requires proper history matching (HM) to quantify the uncertainties of fracture properties and proper modeling methods to address complex fracture geometry. An integrated method, namely embedded discrete fracture model–artificial intelligence–automatic HM (EDFM–AI–AHM), was used to automatically generate HM solutions for a multistage hydraulic fracturing well in the Wolfcamp Formation. Thirteen scenarios with different combinations of matrix and fracture parameters as variables or fixed inputs were designed to generate 1300 reservoir simulations via EDFM–AI–AHM, from which 358 HM solutions were retained to reproduce production history and quantify the uncertainties of matrix and hydraulic fracture properties. The best HM solution was used for production forecasting and carbon dioxide (CO2)-enhanced oil recovery (EOR) strategy optimization. The results of the production forecast for primary recovery indicated that the drainage area for oil production was difficult to extend further into the low-permeability reservoir matrix. However, CO2 EOR simulations showed that increasing the gas injection rate during the injection cycle promoted incremental oil production from the reservoir matrix, regardless of minimum miscibility pressure. A gas injection rate of 25 million standard cubic feet per day (MMscfd) resulted in a 14% incremental oil production improvement compared to the baseline scenario with no EOR. This paper demonstrates the utility of coupling reservoir simulation with artificial intelligence algorithms to generate ensembles of simulation cases that provide insights into the relationships between fracture network properties and production.

Effect of initial normal stress on shear-induced non-linear fluid flow through fractures

This study investigated the effect of initial normal stress on the non-linear hydraulic properties of fractures during shearing. A natural rough fracture is utilised to generate the rough fracture model and a mathematical expression for predicting the normal displacement during shearing is used, after which the validity is verified. Finally, the non-linear flow rate – hydraulic gradient relationships and the empirical functions for Fochheimer coefficients and critical Reynolds number are analysed. The results show that with the increment of initial normal stress, the fractures are closed and the contact area increases, decreasing the permeability. As initial normal stress increases, both the linear and non-linear Fochheimer coefficients increase following power-law relationships with positive exponents. The non-linear Fochheimer coefficient is approximately five orders of magnitude larger than the linear Fochheimer coefficient, which is consistent with the results reported in the literature. Both Fochheimer coefficients and critical Reynolds number are strongly correlated with fracture aperture. The variation in linear Fochheimer coefficient is more robust than the variation in non-linear Fochheimer coefficient against aperture, resulting in that the critical Reynolds number increases with increasing the aperture, which follows a power-law relationship with the correlation coefficient larger than 0·91.

Modeling lost-circulation in natural fractures using semi-analytical solutions and type-curves

Drilling is a requisite operation for many industries to reach a targeted subsurface zone. During operations, various issues and challenges are encountered, particularly drilling fluid loss. Loss of circulation is a common problem that often causes interruptions to the drilling process and a reduction in efficiency. Such incidents usually occur when the drilled wellbore encounters a high permeable formation such as faults or fractures, leading to total or partial leakage of the drilling fluids.In this work, a semi-analytical solution and mud type-curves (MTC) are proposed to offer a quick and accurate diagnostic model to assess the lost-circulation of Herschel-Bulkley fluids in fractured media. Based on the observed transient pressure and mud-loss trends, the model can estimate the effective fracture conductivity, the time-dependent cumulative mud-loss volume, and the leakage period. The behavior of lost-circulation into fractured formation can be quickly evaluated, at the drilling site, to perform useful diagnostics, such as the rate of fluid leakage, and the associated effective fracture hydraulic properties. Further, derivative-based mud-type-curves (DMTC) are developed to quantify the leakage of drilling fluid flow into fractures. The developed model is applied for non-Newtonian fluids exhibiting yield-power-law (YPL), including shear thickening and thinning, and Bingham plastic fluids. Proposing rigorous dimensionless groups generates the dual type-curves, MTC and DMTC, which offer superior predictivity compared to traditional methods. Both type-curve sets are used in a dual trend matching, which significantly reduces the non-uniqueness issue that is typically encountered in type-curves.Usage of numerical simulations is implemented based on finite elements to verify the accuracy of the proposed solution. Data for lost circulation from several field cases are presented to demonstrate the applicability of the proposed method. The semi-analytical solver, combined with Monte Carlo simulations, is then applied to assess the sensitivity and uncertainty of various fluid and subsurface parameters, including the hydraulic property of the fracture and the probabilistic prediction of the rate of mud leakage into the formation. The proposed approach is based on a robust semi-analytical solution and type-curves to model the flow behavior of Herschel-Bulkley fluids into fractured reservoirs, which can serve as a quick diagnostic tool to evaluate lost-circulation in drilling operations.

Evaluating Gas-Oil Ratio Behavior of Unconventional Wells in the Uinta Basin

On account of low matrix permeability and porosity, the fluid phase behavior in tight oil reservoirs significantly differs from the conventional plays, which increases the challenges of evaluating the well performance and providing reliable production prediction. One of the most important efforts is to investigate the behavior of unconventional well gas-to-oil ratio (GOR). The growth trend of GOR is always considered as a principal reference to modify the production strategies and enhance the well productivity. In this paper, long-term GOR (20 years) behavior of an unconventional well model was evaluated by a set of comprehensive sensitivity studies. This model’s dimensions and reservoir properties are based on information of the Altamont-Bluebell field in the Uinta Basin. The simulation results established a general framework for interpreting the GOR behavior. Key drivers such as completion designs, reservoir, and fracture properties are investigated. This study provides some key insights into the GOR behaviors, such as the high sensitivity of the hydraulic fracture properties, including fracture conductivity and effective fracture half-length. The GOR behavior could be considerably different on various conductivity values or fracture lengths, resulting from the conductivity impact of phase movement and the pressure transition along the fracture. The fracture design factors like drawdown scenario and cluster spacing also play indispensable roles in impacting the GOR response, where a less aggressive drawdown rate can help to delay the GOR increase at an early stage; a widening spacing also can mitigate the rise of GOR and keep it at low value during the whole production period. The impact from natural fractures is also examined and discussed for the first time, including the effect of natural fracture numbers and conductivity, where the latter variable is considered as a more effective contributor to the GOR prediction. The findings presented in this work promote a better understanding of the GOR behaviors in tight oil reservoirs. Results and discussion in this paper allow a more accurate forecasting production to improve the reservoir management efficiency and provide multiple valuable insights to guide the field development in future projects.

Fracture Transmissivity in Prospective Host Rocks for Enhanced Geothermal Systems (EGS)

We experimentally determined the hydraulic properties of fractures within various rock types, focusing on a variety of Variscan rocks. Flow-through experiments were performed on slate, graywacke, quartzite, granite, natural fault gouge, and claystone samples containing an artificial fracture with a given roughness. For slate samples, the hydraulic transmissivity of the fractures was measured at confining pressures, pc, at up to 50 MPa, temperatures, T, between 25 and 100 °C, and differential stress, σ, acting perpendicular to the fracture surface of up to 45 MPa. Fracture transmissivity decreases non-linearly and irreversibly by about an order of magnitude with increasing confining pressure and differential stress, with a slightly stronger influence of pc than of σ. Increasing temperature reduces fracture transmissivity only at high confining pressures when the fracture aperture is already low. An increase in the fracture surface roughness by about three times yields an initial fracture transmissivity of almost one order of magnitude higher. Fractures with similar surface roughness display the highest initial transmissivity within slate, graywacke, quartzite and granite samples, whereas the transmissivity in claystone and granitic gouge material is up to several orders of magnitude lower. The reduction in transmissivity with increasing stress at room temperature varies with composition and uniaxial strength, where the deduction is lowest for rocks with a high fraction of strong minerals and associated high brittleness and strength. Microstructural investigations suggest that the reduction is induced by the compaction of the matrix and crushing of strong asperities. Our results suggest that for a given surface roughness, the fracture transmissivity of slate as an example of a target reservoir for unconventional EGS, is comparable to that of other hard rocks, e.g., granite, whereas highly altered and/or clay-bearing rocks display poor potential for extracting geothermal energy from discrete fractures.

Numerical and experimental investigation of the hydrogeological evolution around a borehole due to stress redistribution in fractured rock

The area around a borehole is often damaged by the drilling impact and stress redistribution during the installation of a borehole. Numerous studies have examined the damage caused by stress redistribution around a borehole by analyzing spalling at a borehole; however, the hydrogeological evolution of existing fractures around a borehole due to stress redistribution has not been investigated thoroughly, despite its potential influence on uncertainty during fractured rock hydraulic testing. This study numerically and experimentally evaluated the influence of stress redistribution on the hydraulic properties of fractures around a borehole to determine the changes in fracture apertures and permeability during the installation of a 3-inch-diameter vertical borehole, BDZ-1, at the Korea Atomic Energy Research Institute (KAERI) Underground Research Tunnel, and after expanding its diameter to 4 in. To confirm the results of the numerical experiments, geophysical logging and hydraulic tests were conducted before and after expanding the diameter of BDZ-1. The numerical results revealed the number of fractures with increased aperture after diameter expansion of borehole was much larger than the number of fractures with decreased aperture due to stress redistribution. Moreover, the transmissivity of the borehole vicinity also increased after diameter expansion. The results of the field tests supported those of the numerical tests, whereby changes in fracture apertures were observed and the transmissivity estimated from the hydraulic tests increased after expanding the borehole diameter. This study indicates that the vicinity of a deposition hole in a subsurface repository for radioactive waste may become a conduit for nuclides despite of little drilling impact due to the increased transmissivity around the hole from borehole-induced stress redistribution and fracture aperture change.

Analytical relationships between normal stress and fluid flow for single fractures based on the two-part Hooke’s model

The normal stress-dependent hydraulic properties of single fractures are fundamental in hydro-mechanical coupling for the fractured reservoirs. With increasing normal stress, fluid flow through single fractures decreases dramatically in the low stress range and then gradually in the high stress range, respectively. In order to describe this heterogeneous hydro-mechanical behavior, analytical relationships between normal stress and fluid flow for single fractures are established based on the two-part Hooke’s model (TPHM), in which the fracture aperture is conceptualized into two parts at a macro scale, hard part and soft part. The contributions of soft part and hard part apertures on the hydraulic properties are separately evaluated by the different mechanical properties with normal stress. The validity of the proposed relationships between normal stress and fluid flow is verified by the good agreements between experimental data and theoretical predictions for natural and induced tensile fractures. The significant reductions of permeability and flow rate at low stress are dominated by the soft part and the degree of their nonlinearity highly depends on the spatial correlation of fracture geometry. In addition, the irrecoverable fracture deformation and flow drop between loading cycles are also greatly affected by the soft part while the fracture modulus of the hard part exhibits a weak dependence on loading cycle. The proposed relationships can be used to evaluate the coupled hydro-mechanical processes in fractured rock engineering such as geothermal energy development, CO2 geologic sequestration and stability of fractured rock slope.