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Summary Currently, researchers and the industry believe that water invasion into a shale matrix should dominate the process of water soaking before flowback of hydraulic fracturing fluids. Based on laboratory observations with Tuscaloosa marine shale (TMS) cores, we postulate a hypothesis that cracks are formed in shale formations during and after hydraulic fracture stimulation and that they later contribute to improved well productivity. The formation of cracks contributes to improving well inflow performance, while the cracks also draw fracturing fluid from the hydraulic fractures, reduce fracture width, and consequently lower well inflow performance. The tradeoff between crack development and fracture closure allows for an optimum water-soaking time, which could potentially maximize well productivity. A mathematical model was developed to describe the dynamic propagation of cracks based on the capillary-viscous force balance. The effect of crack formation on the long-term well productivity was analyzed using a previously published mathematical model for well productivity. A combination of the crack propagation and the well productivity models for the first time provides a technique for predicting the optimum fluid soaking time before flowback of hydraulic fracturing fluids. Sensitivity analyses show that reducing the viscosity of fracturing fluid could potentially speed up the optimum water-soaking time, while lowering the water-shale interfacial tension (IFT) could potentially delay the optimum water-soaking time. Real-time shut-in pressure data can be used in the crack propagation model to "monitor" crack development and identify the optimum water-soaking time before the flowback of hydraulic fracturing fluids for maximizing well productivity and the gas/oil recovery factor. Introduction Multifractured shale gas/oil wells with high water recoveries ( 70%) after hydraulic fracturing are normally low-productivity wells, while those with 10 to 40% water recoveries are normally high-productivity wells (Fan et al. 2010). The water loss into the formation does not hinder the gas/oil flow into the wellbore.
Complex flow mechanisms, such as Knudsen diffusion, are encountered in the shale matrix because of the presence of nanopores. Numerous apparent-permeability models have been proposed to capture the ensuing non-Darcy flow behavior. However, these models are not readily available in most commercial reservoir simulators, and ignoring these mechanisms can potentially underestimate the overall matrix conductivity. This work implements an explicit coupling strategy for integrating a pressure-dependent apparent-permeability model in reservoir simulation. The numerical models are subsequently used to study the effects of apparent-permeability modeling and natural-fracture distribution on gas production and water loss during flowback. The effects of multiphase-flow functions on fluid retention are also assessed.
A set of 3D reservoir models are constructed using field data obtained from the Horn River shale-gas reservoir. First, stochastic 3D discrete-fracture-network (DFN) models are scaled up into equivalent continuum dual-porosity/dual-permeability models. An apparent-permeability (Kapp) model accounting for contributions of slip flow, Knudsen diffusion, and surface pore roughness is applied at each gridblock. A novel coupling scheme is formulated to facilitate the updating of Kapp after a certain specified time interval, capturing the pressure dependency of the Kapp. The sensitivity of the updating frequency is analyzed.
The results reveal that incorporating these additional flow mechanisms by means of the apparent-permeability formulation could potentially increase the overall gas-production prediction by up to 11%, depending on the average pore radius, reservoir pressure, and several other matrix or fluid properties. The implications of Kapp modeling in water-loss mechanisms are further examined through a set of sensitivity analyses, where the effects of multiphase-flow functions and DFN distributions are systematically investigated. The following interesting findings are observed:
This work offers a novel, yet practical, scheme for representing the pressure-dependent matrix apparent permeability in the flow simulation of shale reservoirs. The proposed method captures the non-Darcy flow behavior caused by the complex transport mechanisms occurring in nanosized pores. Most importantly, this coupling procedure can be implemented in existing commercial reservoir-simulation packages. The results have revealed a few interesting insights regarding the potential implications in fracturing design and estimation of stimulated reservoir volume.
We present an integrated interpretation of microseismic, treatment, and production data from hydraulic-fracturing jobs carried out in two adjacent wellpads in the Horn River Basin, northeast British Columbia, Canada.
We conclude that poor correlation coefficients (R2) in crossplots of normalized production rate vs. the product of stimulated reservoir volume (SRV) and porosity and total organic carbon (TOC) (SRV × φ × TOC) indicate pressure interference between wells or wellpads. Good correlation coefficients in the same crossplots indicate lack of interference.
The SRV × φ × TOC product reflects the hydrocarbon pore SRV because there is a relationship between TOC and hydrocarbon saturation in shales (Lopez and Aguilera 2018). Our results suggest that natural-fracture networks have an important effect on well connectivity and on the spatial distribution of microseismic data. Connectivity between wellpads occurs through a network of pre-existing natural fractures, which are approximately perpendicular to the least principal compressive stress in the area.
This conclusion is supported by data analysis from Wellpads I and II in the Horn River Basin. Wellpad I includes eight wells that were drilled and fractured in the Muskwa and Otter Park formations (four wells in each formation) in 2010. Wellpad II includes three wells drilled and fractured in 2011 in each of the three shale formations, Muskwa, Otter Park, and Evie. There is a 1-year interval between fracturing on the first and second wellpads.
The data analysis includes evaluation of magnitudes, b-values, moment-tensor inversion (MTI), and the spatial and temporal distributions of three-component microseismic events recorded during more than 200 stages of fracturing by multiwell downhole arrays. We analyzed Gutenberg-Richter frequency/magnitude graphs for each fracturing stage, and with proper integration of b-values, fracture-complexity index (FCI), MTI information, and treatment data, we distinguished hydraulic-fracturing-related events and events associated with slip along the surface of natural fractures. The results are compared with 5- and 4-year gas-production data in Wellpads I and II, respectively.
Identification of natural fractures and information about interactions between hydraulically fractured wells are both essential for optimal well placement and completion, reservoir characterization, SRV calculation, and reservoir simulation. This study presents a distinctive insight into the integrated interpretation of microseismic events and production data to identify the activation of natural fractures and interference between the hydraulically fractured wells. The methodology developed in this study is thus related to production engineering, but examines it from the point of view of microseismic data.
Argüelles-Vivas, Francisco J. (The University of Texas at Austin) | Wang, Mingyuan (The University of Texas at Austin) | Abeykoon, Gayan A. (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin)
This paper presents an application of 3-pentanone, a symmetric short ketone, to enhance the water imbibition in coreflooding of fractured carbonate cores. 3-Pentanone was tested in two ways: 1.1-wt% 3-pentanone solution in reservoir brine (3pRB) and pure 3-pentanone (3p) as a miscible solvent. It was presented previously that 3p is a mutual solvent for oil and water, and can rapidly change the rock wettability to strongly water-wet with its electron-rich oxygen atom through the oil and water phases. The main objective of this research is to investigate how the initial water saturation in the matrix affects the imbibition of 3pRB or 3p from the fracture and the resulting recovery of oil from the matrix.
The experimental results were analyzed in terms of material balance (mass and volume) with simplifying assumptions. This analysis enabled to estimate how much of the injected components were imbibed into the surrounding matrices from the fracture and the relative contribution of the injected components to displacing oil in the matrix.
For the injection of 3pRB, the oil recovery was consistently greater when there was an initial aqueous phase in the matrix. While the presence of an initial aqueous phase did not affect the imbibed fraction of the injected 3p, it made it more effective for 3p to enhance the oil displacement by water in the matrix. For example, 87% of the oil recovered from the matrix was displaced by water (the rest by 3p) for the coreflood with an initial water saturation of 31%.
The injection of pure 3p showed that a larger amount of oil was recovered from the matrix with the presence of an initial aqueous phase in the matrix. The oil recovery mainly came from the displacement of oil by 3p in the matrix with a minor contribution of water. Results for the 3pRB and 3p injections indicate collectively that 3-pentanone was more effective in enhancing oil recovery when an aqueous phase was initially present in the matrix.
It has often been reported that the peak production of a well drilled in tight formations is highly dependent on the fracture-contact area. However, at present, there is no efficient approach to estimate the fracture surface area for each fracture stage. In this paper, we propose a method to calculate the fracture surface area on the basis of the falloff data after each stage of the main hydraulic-fracture treatment.
The created hydraulic fracture closes freely before its surfaces hit the proppant pack, and this process can be recognized in the pressure falloff data and its diagnostic plots. The pressure-decline rate during fracture closure is mainly caused by the fluid leakoff from the fracture system into the formation matrix. For a horizontal well drilled in the same formation, with the known leakoff coefficient(s) and fracture-closure stress(es), the total-fracture surface area can be calculated for all stages to meet the requirement of the fluid-leakoff rate.
The wellbore-storage effect, friction dissipation, and tip extension dominate the early pressure falloff data. Whereas the transient pressure dominated by friction losses typically lasts approximately 1 minute, the tip extension might end after approximately 15 minutes. Therefore, falloff data should be acquired for at least 30 minutes to observe a fracture-closure trend. The fracture-closure behavior can be identified on the G-function plot as an extrapolated straight line or on the Bourdet derivative in log-log plot as a late-time unit slope. The behavior of the late unit slope depends on the pressure-decline rate, or correspondingly, to the fluid-leakoff rate. Therefore, the total-fracture surface area can be estimated using hydraulic-fracture design input values for the formation-leakoff coefficient and fracture-closure stress. The calculated fracture surface area represents the combined area of primary and secondary fractures—effectively all fracture surfaces contributing to the fluid leakoff.
We applied the approach to all stages in a horizontal well that exhibit the fracture-closure behavior. The approach shows some promise as a potential way to estimate fracture surface areas that could allow an early estimate of the expected well performance.
It is widely known that only a small fraction of the water injected during hydraulic fracturing is recovered during the flowback period. The water that remains in the reservoir is believed to imbibe into the matrix. Because of the capillary discontinuity between the matrix and the fracture, water blockage is formed near the matrix/fracture interface and reduces the hydrocarbon relative permeability. Therefore, shut-in is often performed just after hydraulic fracturing to alleviate water blockage by redistributing the water deeper into the reservoir through capillary imbibition.
However, field data show mixed observations on shut-in performance: some report shut-in as beneficial, while others suggest that it is detrimental. On the basis of laboratory experiments, shut-in is shown to increase the hydrocarbon relative permeability upon flowback. However, most of the laboratory-scale experiments might not simulate the stress-dependent permeability (SDP) observed in hydraulically fractured reservoirs. SDP is a behavior of a porous medium in which its permeability changes depending on the pressure/ stress change which, in turn, affects the grain compaction/dilation or fracture aperture and hence permeability. As reported in many experiments, SDP inevitably occurs because the pore pressure changes significantly during both the fracturing and the production stage in hydraulically fractured reservoirs. Therefore, there have been questions concerning the applicability of such laboratory-scale experiments to explain the field-scale phenomena. Because reservoir simulation allows the inclusion of SDP, several papers used the simulation approach to investigate shut-in benefits while including the SDP. However, most of the previous simulation studies used an unrealistic input for the matrix SDP and an asymmetric model segmentation, or even did not validate their numerical model with field-data history matching. This paper will show that such unrealistic input, and such an improper modeling approach, can yield misleading conclusions on shut-in benefits. Therefore, the first objective of our study is to demonstrate an improved modeling workflow to simulate flowback upon water fracturing. Afterward, we aim to evaluate shut-in benefits in terms of hydrocarbon recovery and net present value (NPV). The NPV allows a more realistic economic evaluation of shut-in benefits, because it discounts the higher initial production rate because of shut-in that happens in the future. A parametric study on the injection volume, matrix absolute permeability, and economic parameters is also presented.
Given the more realistic modeling approach, our model is successfully history matched with field production data from the Middle Bakken Shale reservoir. This model quantitatively shows that shut-in does not significantly affect the ultimate oil recovery in shale-oil reservoirs. In fact, the model shows that longer shut-in tends to decrease the NPV because the higher initial production rate upon shut-in cannot be maintained for long enough to compensate for the production loss during the shut-in period. Our model suggests that such higher initial production rates are unsustainable because even after shut-in, water will reaccumulate toward the fractures and create water blockage. In addition, the high pressure buildup during fracturing only marginally increases the average reservoir pressure and will be expended quickly once flowback starts. In other words, shut-in seems to only delay the water-blockage issue, although it allows the early-time flowback to start in a milder water-blockage situation. As a result, in this study we propose immediate flowback as a more profitable flowback strategy.
For hydraulic fracturing in unconventional reservoirs, propped volume is the key to predicting total production. Microseismic analysis is frequently performed to detect fracture extension. Recently, microseismic analysis was utilized for various objectives. Though several methods of estimating proppant distribution are currently used, including tracers and core analysis, it is important to investigate whether microseismic analysis can discriminate proppant injection in order to cross-check and decrease the uncertainty of proppant distribution. To estimate the propped fracture distribution, accurate microseismic processing is important. In this study, indications of microseismic events caused by proppant injection were interpreted by accurate microseismic processing and the waveform-similarity clustering of microseismicity in the Horn River shale gas field.
We analyzed a certain hydraulic fracturing stage of zipper fracturing. In this stage, hydraulic fracturing was carried out over 7000 seconds. The first proppant injection started 1000 seconds after starting water injection and continued for 2500 seconds. Next, larger proppant was injected after termination of the first proppant injection and continued for 3500 seconds. Microseismic data was acquired using 36 downhole arrays of 3C geophones in a vertical section of two horizontal wells. Microseismic events were located by focusing P-waves, because, in this field, there is high uncertainty in picking direct S-waves. After that, we classified microseismic events using waveform similarity clustering by cross correlation between each microseismic event in the P-waves and S-waves of the each microseismic data.
Microseismic hypocenters were distributed in a bi-wing pattern from the perforation location. They were concentrated more on the southwest side than the northeast side. Sparse distribution in the northeast side could be caused by existing fractures from the neighboring well treatment. In a time-series histogram of microseismic event frequency, the events are concentrated at the start of water injection and second proppant injection. In a time-distance plot, a linear feature was detected which implies initial fracture opening. Applying the clustering procedure, two clusters were detected which include events that mainly occurred at the start of water injection. These events are located close to each other and have high waveform similarities, which implies that they have the same source mechanism, namely, initial fracture opening. Two other clusters were also detected that include events which only occurred at the start of the second proppant injection. These events were also located close to each other. From net pressure analysis, proppant screenout did not occur. Therefore, the events in the latter clusters are interpreted to have been caused by proppant injection and their hypocentres could represent proppant distribution.
Although further investigation, including fracture propagation simulation, is required and only a few events are interpreted as events caused by proppant injection, this approach should help to estimate the distribution of propped fractures and the total propped volume.
The objective of this paper is to present the development and application of a simple equation for calculating the asymmetric growth of the stimulated reservoir volume (SRV) in an anisotropic shale-petroleum reservoir using microseismic data, and the hydraulic diffusivities of the anisotropic shale.
Calculation of the SRV is a problem tackled with solutions that involve different degrees of complexity. Because shale reservoirs are anisotropic, microseismic events generally develop 3D nonuniform asymmetric patterns around the injection points. This paper presents a new method with an easy-to-use analytic equation that allows for reproducing the asymmetric growth of microseismic events as a function of time by considering reservoir anisotropy.
Asymmetric growth refers to the fact that propagation of the microseismic cloud in a given direction can be larger, equal, or smaller compared with the propagation in other directions. Accurate determination of the SRV asymmetric pattern is critical for use in specialized material-balance and reservoir-simulation models of shale-petroleum reservoirs. This determination allows for morerealistic projections of reservoir performance.
The novelty of the method is the development of an easy-to-use approach for estimating SRV in a spatially nonuniform asymmetric anisotropic reservoir using octants in a coordinate system. The SRV is calculated from the volume of a symmetric ellipsoid divided by a constant value Vc. This is despite the fact that the point of injection of the fracturing fluids in the asymmetric reservoir can be at, close to, or far from the center of the ellipsoid. The development of Vc is presented in this paper. Use of the SRV calculation model is illustrated with real microseismic data of the Horn River Shale in Canada for a case where Vc is equal to 1.3722. Also presented are calculations of hydraulic diffusivities in this anisotropic shale.
Modelling fracture systems where fracture mechanics and fluid flow are consistent, constitutes an essential part for predicting the performance of shale oil and gas operations. One of the challenges in these complex systems is the reconciliation of volumes of injected water during fracturing, hydraulic fracture volume and the water flowback after the well is open to production. Achieving consistency becomes even more challenging given the interdependence of multiple sources of uncertainty.
We propose a workflow that uses multiple sources of observed operational data, such as volume of water injected and produced, static pressure, soaking time and saturation logs, to calibrate a static model representing the fracture volume and rates of water imbibed into the matrix. The soaking period is modeled using Embedded Discrete Fracture Model (EDFM) that honors the fracture geometry generated by a commercial software based on unconventional fracture model (UFM). The allocation of water imbibed into the matrix during the soaking period uses imbibition capillary pressure from 3D numerical models.
After applying the proposed methodology to calibrate stimulated shale oil reservoir in a multi well pad, we can assess the relative impact of fracture complexity compared to capillary dominated flow. Additionally, we can perform sensitivities on impact of the water retained in the fracture volume and matrix, respectively. Finally, the methodology showed that we can use the imbibition capillarity to explain and reconcile water losses during the soaking period. This information is of key importance while deciding the value of the flowback rates as input during calibration of hydraulic fracture area and quality of the stimulation procedure. Extended applications of this workflow include performance assessment of gas entrapment and evaluation of EOR operations in unconventional systems.
We propose a methodology based on the hypothesis of capillary imbibition mechanism to explain and capture the volume of injected water that does not return during hydrocarbon production. This workflow, well suited for realistic complex Hydraulic Fracture Networks (HFNs) consisting of millions of fractures planes, enables calibration of fracturing fluids and water flowback while assessing the effect of the spontaneous imbibition.