Closure Of Natural Fractures Research Articles

Interwell interference model of horizontal wells in shale gas reservoirs based on multi-connected boundary element method

Due to the wide application of closely spaced multi-well horizontal pads for developing unconventional gas reservoirs, interference between wells becomes a significant concern. Communication between wells mainly occurs through natural fractures. However, previous studies have found that interwell communication through natural fractures is varied, and non-communication also appears in the mid and late stages of production due to natural fracture closure. This study proposes a boundary element method for coupling multi-connected regions for the first time. Using this method, we coupled multiple flow fields to establish dual-well models with various connectivity conditions of the stimulated reservoir volume (SRV) region. These models also take into consideration of adsorption and desorption mechanism of natural gas as well as the impact of fracturing fluid retention.The study found that when considering the non-communication of SRV regions between multi-well horizontal pads, the transient behavior of the targeted well exhibits a transitional flow stage occurring before the well interference flow stage. In addition, sensitivity analysis shows that the well spacing and production regime, as well as the connectivity conditions of the SRV region, affect the timing of interwell interference. Meanwhile, the productivity of the two wells, reservoir properties, and fracturing operations affect the intensity of interwell interference.

Research on the transport behavior of microparticle proppants inside natural fractures

As a crucial exploration technique for unconventional reservoirs, hydraulic fracturing enables the formation of complex fracture networks, thereby facilitating the flow of oil and gas. The closure of natural fractures decreases stimulation performance. Microparticle proppants are used to fill natural fractures and effectively increase the stimulation area. The 100-mesh proppant conventionally used in field operations may be insufficiently small to effectively access natural fractures. In order to effectively overcome natural fractures closure, microparticle proppants (i.e., proppants with a diameter of 75 μm (200-mesh) or less) are required. The particle size threshold test of microparticle proppants placement is conducted to determine the size threshold of proppants flowing into natural fractures. The microparticle proppants placement experiment in multi-branch fractures is conducted to investigate the volume difference of proppants in different fractures. Numerical simulations are performed to model proppant transport within fractures of actual dimensions to facilitating the optimization of stimulation parameters. The main conclusions are as follows: (1) Effective inflow of microparticle proppants requires a size threshold of proppants. For the 200-mesh proppants, the size should be less than half of natural fractures width when microparticle proppants effectively flow into natural fractures. (2) Sand concentration affects the size threshold of microparticle proppants. The size threshold should appropriately increase to ensure the inflow of proppant. (3) Difference of multi-branch fracture width has a significant effect on volume of microparticle proppants inside fractures. When the width ratio of multi-branch fractures exceeds 2, this effect becomes obvious. (4) Particle size has an effect on proppant placement. 200-mesh proppants can obtain uniform distribution of proppants among natural fractures. 140-mesh proppants can obtain maximum proppant volume among natural fractures. Sand concentration significantly affects proppant placement performance. The optimal sand concentration is 60kg/m3. The pumping rate for a single cluster fracture should not be excessively low. The pumping rate should be larger than 0.5m3/min and the optimal pumping rate 2m3/min. In this paper, the particle size and concentration of particulate proppant are optimized and the geometric characteristics of fractures are considered. These conclusions provide important practical guidance and scientific basis for the optimization and application of hydraulic fracturing technology.

Buildup Evaluation of a Tight Overpressured Naturally Fractured Carbonate Reservoir with the Use of a Semi-Empirical Model

Summary This paper examines the buildup (BU) pressure response of a vertical well that penetrates an unconventional tight naturally fractured carbonate reservoir in Mexico. Four BUs in the same well over a period of 4 months, with intermediate flow periods, suggest partial closure of natural fractures. Radial flow is dominant in the four BUs. This is recognized in semilogarithmic and pressure derivative crossplots. However, the formulations require a consistent empirical component to match the BU data. The four BU tests are evaluated with a semi-empirical dual porosity model with restricted interporosity flow. The restricted flow between matrix and fractures is the result of partial secondary mineralization (cementation) within the fractures, which can be visualized as a natural positive skin that reduces the oil flow from the matrix to the fractures. The empirical part of the method is provided by a severity exponent (SE), which helps improve the match between the BU semilog and derivative plots. The BU evaluations permit estimating several parameters of interest, including fracture capacity (k2·h), skin, storativity ratio (ω), and the extrapolated pressure (p*). Results suggest that although natural fractures are present, they tend to close once the well goes on production. Thus, the conclusion is reached that the carbonate reservoir is tight and likely stress dependent. The calculated skin goes from an improved condition around the wellbore to slightly damaged conditions, probably due to fracture closure. The value of ω increases continuously, suggesting a tendency of the reservoir to move from dual to single porosity behavior. The reservoir is overpressured (0.87 psi/ft) and the extrapolated pressures (p*) decrease because of the tight characteristics of the reservoir. However, given the large size of the reservoir, the likelihood of depletion is low. The novelty of this study is the development of a new easy-to-use semi-empirical well testing model for matching the BU pressure response of four tests performed in a well that penetrates an overpressured, unconventional, tight, naturally fractured carbonate reservoir. The tests could not be matched with conventional methods currently available in the literature.

Supercritical CO2-Shale interaction induced natural fracture closure: Implications for scCO2 hydraulic fracturing in shales

Multi-stage hydraulic fracturing has been identified as a must to develop shale gas reservoirs by increasing the stimulated reservoir volume (SRV). Supercritical CO2 (scCO2) has been studied as an alternating fracturing fluid due to its tendency to solve numerous problems associated with conventional aqueous based hydraulic fracturing such as formation damage, clay swelling, water scarcity and ground water contamination. However, its consequences to the host rock are not well understood. It has been recognized that scCO2-shale interaction alters the petrophysical properties during the long-term exposure of shale into scCO2, far little attention has been paid to understand the impact of this process for the short term. Thus, laboratory fracturing experiments using scCO2 on cubic shale samples (50 × 50 × 50 mm) in true triaxial stress cell (TTSC) were conducted. X-ray computed tomography (CT) imaging and low-pressure N2 adsorption were also performed to gain a deeper understanding of the fluid-rock interactions on the studied shales at a short-time process. Post-fracturing x-ray CT scans revealed a significant reduction, in the range of 14% to 46%, in the aperture of the natural fractures, indicating towards a possible scCO2 induced swelling. Mechanical compression test on the sample results in around 12% reduction in the fracture aperture, ruling out the possibility of confining stress being the key factor behind the fracture closure observed during fracturing. scCO2 soaking and N2 adsorption experiments showed the narrowing down of the macropores after scCO2 treatment implying the adsorption swelling as one of the controlling factors for the reduction of fracture aperture. Taken together, our results suggest that scCO2-shale interactions during the short term process of hydraulic fracturing can contribute to decreasing the conductivity of pathways between matrix and hydraulic fractures and hence adversely affecting the post-fracturing productivity of the rock.

Modeling the closure behavior of natural fractures in porous media using high aspect ratio interface elements

Many reservoirs consist of fully saturated rock masses containing a very complex natural fracture network. In such cases a decrease in the fracture fluid pressure reduces its aperture due to an increase in the effective stresses. In order to tackle the influence of fracture permeability on the pressure field and fluid flow, this paper proposes a Discrete Fracture-Matrix (DFM) model based on the finite elements to simulate coupled flow and geomechanics in porous media containing fractures with known position and properties (e.g. DFN realizations and fracture networks interpreted from outcrops). The proposed model is based on the use of triangular finite elements with high aspect ratio (HAR) to explicitly represent the fractures. These HAR elements have been successfully used to deal with cracks in concrete structures, desiccation cracks in soils and hydraulic fracturing in geo-reservoirs. This work demonstrate that these HAR elements equipped with a simple continuum (stress-strain) constitutive contact model that mimics the discrete (stress-displacement) Barton-Bandis joint model are able to properly describe the closure behavior associated with natural fractures. The constitutive model is integrated by means of the IMPL-EX scheme, which is a robust and stable technique used to achieve faster convergence. Darcy's law establishes the relationship between the fluid flow and the pressure field, and a fully coupled hydro-mechanical formulation comprises the mathematical framework. The proposed approach is based on continuous mechanics concepts and the implementation is made at constitutive level, and therefore it is simple and easy to be included in any existing FE program. To show the efficiency and accuracy of the proposed model, three numerical examples are conducted in this work: (i) benchmarks involving a medium with a single natural fracture, (ii) three reservoirs with different discrete fracture networks, and (iii) a transient analysis of a reservoir under different fracture conditions, such that the behavior of a intact reservoir, a reservoir containing fractures with constant aperture, and a reservoir in which the fractures aperture depends on the stress state are compared in terms of pore pressure, displacement field and fluid loss. In the first example, the results obtained with the proposed methodology are validated against the Barton-Bandis model. The agreement between the results is very satisfactory. The analysis of the latter two cases show the Barton-Bandis contact model is able to reproduce the effects of fracture permeability on pressure field in the reservoir, showing the capacity of the model to reproduce the main trends associated with the closure of natural fractures.

Fracture Characterization Using Flowback Water Transients from Hydraulically Fractured Shale Gas Wells.

Fracture characterization is necessary to evaluate fracturing operations and forecast well performance. However, it is challenging to quantitatively characterize the complex fracture network in shale gas reservoirs because of the unknown density and reactivation of natural fractures. The flowback water transients can provide useful information about the complexity of the fracture network after the fracturing operations. In this paper, a mathematical model for modeling fracturing fluid flowback of hydraulically fractured shale gas wells is established. This proposed model characterizes the flow of water and gas in a hydraulic fracture-induced natural fracture–shale matrix system. Hydraulic, capillary, and osmotic convections; gas adsorption; and natural fracture closure are considered in this model. Flowback simulation of a hydraulically fractured shale gas well is conducted using the developed numerical simulator, and the water/gas transients between hydraulic fractures, natural fractures, and matrix are obtained. Finally, two field cases from the Longmaxi Formation, Southern Sichuan Basin, China, are used for comparison of the flowback data with the model results. The good match of the two water transients provides a group of fracture network parameters, that is, the effective length and conductivity of main hydraulic fractures and the density of induced natural fractures. The proposed model for describing the flowback process and its meaningful relationship with the fracture–network complexity provides an alternative approach for post-stimulation evaluation.

Determine In-Situ Stress and Characterize Complex Fractures in Naturally Fractured Reservoirs from Diagnostic Fracture Injection Tests

Estimation of in-situ stresses has significant applications in earth sciences and subsurface engineering, such as fault zone studies, underground CO2 sequestration, nuclear waste repositories, oil and gas reservoir development, and geothermal energy exploitation. Over the past few decades, Diagnostic Fracture Injection Tests (DFIT), which have also been referred to as Injection-Falloff Tests, Fracture Calibration Tests, and Mini-Frac Tests, have evolved into a commonly used and reliable technique to obtain in-situ stress. Simplifying assumptions used in traditional methods often lead to inaccurate estimation of the in-situ stress, even for a planar fracture geometry. When a DFIT is conducted in naturally fractured reservoirs, the stimulated natural fractures can either alter the effective reservoir permeability within the distance of investigation or interact with the hydraulic fracture to form a complex fracture geometry, this further complicates stress estimation. In this study, we present a new pressure transient model for DFIT analysis in naturally fractured reservoirs. By analyzing synthetic, laboratory and field cases, we found that fracture complexity and permeability evolution can be detected from DFIT data. Most importantly, it is shown that using established methods to pick minimum in-situ stress often lead to over or underestimates, regardless of whether the reservoir is heavily fractured or sparsely fractured. Our proposed “variable compliance method” gives a much more accurate and reliable estimation of in-situ stress in both homogenous and naturally fractured reservoirs. By combining the unique pressure signatures associated with the closure of natural fractures, a lower bound on the horizontal stress anisotropy can be estimated.

Poro-viscoelastic modeling of production from shale gas reservoir: An adaptive dual permeability model

In most simulations of gas production from shale reservoirs, only the elastic deformation of reservoir rock and fractures is modeled. However, many experimental studies and field investigations indicate shale experiences viscoelastic deformation. In this work, a numerical model is constructed by implementing a poro-viscoelastic model into a dual permeability model (DPM) by using finite element method (FEM), to investigate the coupled time-dependent viscoelastic deformation of shale, and fracture permeability evolution in response to compressible flow of gas and gas desorption. The viscoelastic effect is considered through both deviatoric and mean effective stresses to allow for the effect of shear strain localization. The geomechanical model is first verified against available analytical and numerical solutions. Then, the model is applied to a few synthetic production cases to investigate the geomechanical evolution of a fractured reservoir. Comparing the case of poroelasticity and poro-viscoelasticity shows that the pore pressure differences throughout the domain are small, however, the stress evolution is quite divergent, with higher fracture closure in the poro-viscoelastic case. Comparison of the cumulative gas productions for poroelastic and poro-viscoelastic cases shows that cumulative gas production predicted by the poro-viscoelastic case is always lower than that of the poroelastic one. The difference between the two cases increases for long production times, as the viscous deformation (creep) of the reservoir rock closes the fracture. Results of the numerical simulations suggest that viscous deformation-enhanced closure of natural fractures that feed the main propped fractures can have a critical role in production decline.

Evaluation of production losses from unconventional shale reservoirs

The Promising production trends and predictions, as well as improvements in hydraulic fracturing and horizontal drilling technologies, have made unconventional reservoirs economically feasible. Although these reservoirs have high initial production rates, it is observed that their production performance declines fast. Therefore, it is necessary to identify the reasons behind the production performance reduction. With continuing production, pore pressure decreases and consequently the effective stress applying on fractures increases. This phenomenon causes the fracture closure. In this paper, both individual and combined effects of natural fracture and hydraulic fracture closures on well performance are investigated. We use available experimental data to represent hydraulic and natural fracture conductivity alterations with changing stress conditions. Simulation results show that the individual effects of hydraulic and natural fracture closure on production performance is in the range of 6%–13% and 7%–23%, respectively. Additionally, the combined effect of natural and hydraulic fracture closure is in the range of 10%–25%. It is observed that the coupled effect of natural and hydraulic fracture conductivity losses is less than the summation of the individual effects. Sensitivity analysis is also performed for certain reservoir parameters. This work can provide a better understanding of the main reasons of production losses from unconventional reservoir simulations.

The effect of natural fracture's closure on long-term gas production from unconventional resources

The future U.S. and world energy supply is supported by the observed trends of long-term production forecasts from unconventional resources. Also, recent innovations in multi-pad horizontal drilling and hydraulic fracturing empower such trends to be economically viable. Nevertheless, the triggered fractures in an unconventional reservoir rapidly shrink, as a result of produced gas that leads to a significant loss in long-term production. Hence, it is critical to quantify the effect of fracture closure on long-term production for to reach an accurate production forecast. In this paper, the permeability changes of secondary fractures network are investigated with respect to their effect on the long-term gas production from unconventional resources.An analytical trilinear model is revised and improved in order to handle the constant bottom-hole pressure production scenario and hence analyzing the cumulative gas production by considering the effect of stress on natural fracture permeability. In addition, a comprehensive sensitivity study is performed to rank the influence of uncertain parameters on cumulative production and consequently identify a condition in which a severe effect of pressure-dependent natural fracture on production is observed. It is concluded that the pressure-dependent natural fracture permeability can cause up to ten percent less cumulative production than considering the constant natural fracture permeability. Also, the improved analytical model is very fast and robust compared to the commercial numerical simulators. The advantage of this approach is to obtain a quick and accurate assessment of the complex production behavior of unconventional reservoirs. The findings of this paper provide valuable insights into long-term investment on unconventional reservoirs and guide decision making for the secondary or tertiary enhancement treatments of unconventional wells, such as re-fracturing.

The influence of fracture stiffness and the in situ stress field on the closure of natural fractures

The extent to which the aperture of natural fractures is reduced, and they are rendered closed and unproductive by the in situ stress field in the subsurface, is critical to planning the exploitation of naturally fractured reservoirs. The semi-log relation between stress and the reduction of natural fracture aperture is combined with the effective normal stress acting on fractures of varying alignment with respect to the horizontal stresses to yield the relation: delta = 1/q log(n+1/2n + n-1/2n cos2theta ) + logsigma ' H /q - p/q, where delta is the reduction of fracture aperture (fracture closure), p and q are constants in the semi-log fracture closure/stress relation, sigma ' H is the maximum effective horizontal stress magnitude, n is the ratio between the maximum and minimum effective horizontal stress magnitudes, and theta is the angle between the normal to the fracture and the sigma H direction. Key conclusions from this relation are: (i) for a given fracture, the sensitivity of fracture closure to the anisotropy of the in situ stress field can be constrained by the effective horizontal stress ratio; (ii) natural fracture closure is very sensitive to fracture alignment with respect to sigma H where the effective horizontal stress ratio is high; (iii) the sensitivity of natural fracture closure to its alignment with respect to sigma H decreases markedly as the effective horizontal stress ratio drops; (iv) except where the effective horizontal stress ratio is infinite, the rate of change of closure with changing alignment is relatively low at very low and at high misalignment angles, and much greater at intermediate angles. The above relation is applied to a number of fractures for which the closure/stress relations have been determined. With varying alignment with respect to sigma H , less stiff fractures show up to four times more closure than stiff fractures.

Does the in situ stress field control the orientation of open natural fractures in sub-surface reservoirs?

In order to evaluate naturally fractured reservoirs, it is critical to assess whether natural fracture sets believed to exist at depth (eg, from surface mapping and/or seismic data) are likely to be open and productive or closed and nonproductive. The semi-log relation between stress and the closure of natural fractures is combined with the effective normal stress acting on fractures to yield: δ−ks−InoH' = In {n+12n +n-12n cos2θ },which relates fracture closure (8), the constants in the semilog fracture closure/stress relation (k and s), and maximum effective horizontal stress (oH) magnitude with the effective horizontal stress ratio (n), and the angle between the normal to the fracture and the o"h direction (0).This relation shows that: (i) for a given fracture, the sensitivity of fracture closure to the anisotropy of the in situ stress field can be constrained by the effective horizontal stress ratio (n); (ii) natural fracture closure is sensitive to fracture orientation with respect to the in situ stress field where n is high; (iii) the sensitivity of natural fracture closure to its orientation with respect to the in situ stress field decreases markedly as n drops; and (iv) the rate of change of closure with changing orientation is relatively low at very low and very high misalignment angles, and much greater at intermediate angles.