Frac fluid delivery is selective in effect, so must fracture models. Here, a physics-based analytical model, called nine-grain model, is presented for production forecasting in multifrac horizontal wells in unconventional reservoirs, where the utilized formulation inherently enables defining three-dimensional non-uniform SRVs, selective frac-hits, and pressure- and time-dependent permeabilities. The model is validated by constructing case studies of liquid and gas reservoirs and comparing the results with numerical simulations. In cases with both production history and fracing-induced microseismic data available, the SRV's spatial structure is extracted using a hybrid four-level straight-line technique that links volumetric RTA estimations to morphometric microseismic analysis and entails plots of plasticity, diffusivity, flowing material balance and early linear flow. By applying our model to an oil well in Permian Basin, we demonstrate that the knowledge gained from the coupled microseismic-RTA contributes to resolving the non-uniqueness of RTA solutions. The proposed reservoir modeling procedure enables efficient incorporation of microseismic interpretations in modern RTA while honoring the SRV space-time variability, thus facilitates informed decision making in spacing design of wells and perforation clusters.
Frac-hits. A frac-hit can be defined as observing a perturbation in the well production rate and/or pressure that is induced by a child offset (or an infill) well, usually triggered by pressure sinks created around parent wells or high permeability lithofacies. A frac-hit that temporarily alters the parent well productivity is called a communication frac-hit, and those with long-term effects, generally caused by fracture interference, are referred as interference frac-hits. A frac-hit may also compromise the productivity of the child well itself since the existing pressure sinks distribute the fracing energy in a larger area and might lead to an asymmetric fracture growth around the child well. Besides the parent well operational condition, the microseismic monitoring of fracing can potentially indicate interference frac-hits as it reveals fracture overlaps and any preferential fracture dilation towards existing wells. Depending on the rock and fluid properties, well age, parent-child horizontal and vertical distances, and the spatial extent of Stimulated Reservoir Volume (SRV), the constructive (Esquivel and Blasingame 2017) or destructive (King et al. 2017, Ajani and Kelkar 2012) effects of frac-hits can be experienced by fractures, SRV or the entire drainage volume (stimulated and non-stimulated zones), usually by impacting rock multiphase fluid interfacial arrangements and/or changing dimensions of conductive fractures. Aside from prevention, thoroughly reviewed by Whitfield et al. (2018), it is essential to incorporate frac-hits into production forecasting models, which to date, is not yet as straightforward as their detection. Both types of frac-hits cause a change in the well productivity over time which is not necessarily correlated with pressure, and hence, complicate the reservoir modeling process.
Three different types of analysis were performed on high-frequency bottomhole pressure data acquired in the Hydraulic Fracturing Test Site (HFTS; Ciezobka et al., 2018) program. The pressure data was made available by Laredo Petroleum Incorporated (LPI) and the Gas Technology Institute (GTI) through participation in the HFTS joint industry project. Rate transient analysis (RTA), pressure interference test (PIT) analysis, and reservoir pressure depletion analysis of production and pressure data were performed to better understand the performance of these hydraulically fractured Wolfcamp reservoirs of the southeastern Midland Basin. Unconventional RTA, PIT analysis, and reservoir depletion analysis of the HFTS pressure data provides three different perspectives to describe fracture systems in the formation. The study of these combined attributes of this unique dataset provides new insights about pressure communication and reservoir drainage of the Wolfcamp A and Wolfcamp B in the HFTS area.
Hydraulic fractures generated during multi-stage hydraulic fracturing operations often have complex geometries (Cipolla et.al, 2008). Estimating the dimensions of complex fracture networks is one of the biggest challenges of evaluating hydraulically fractured reservoirs. Utilizing high frequency bottomhole pressure (BHP) data, unconventional RTA provides a method to evaluate effective fracture dimensions with advantages of low marginal cost and simplicity. Chu et al. (2017) demonstrated the workflow to analyze multiphase rate transient data using examples of Permian Wolfcamp horizontal wells. In this study, a similar workflow is applied to BHP data collected from 11 Wolfcamp horizontal wells in the HFTS project.
High frequency BHP data collected during well interference tests can also be utilized to identify inter-well communication. Over the years, spacing between wells on a multi-well pad has been altered, along with fracture designs, to improve reservoir development efficiency. Larger fracturing treatments have been performed to increase well productivity. Interaction between nearby producing wells is more likely to happen with increasing fracture length and closer well spacings. Understanding the magnitude of fracture communication is therefore important for optimizing well spacing with fracturing treatment sizes. Communication between producing wells can be detected from pressure response at an observation well to significant rate changes at an active well, such as a shut-in (SI) or bring-online (BOL). The process is called a pressure interference test (PIT). PITs are widely used in conventional reservoirs to determine inter-well reservoir properties (Kamal, 1983). In unconventional shale reservoirs, analysis methods to understand the pressure interference test results have been developed in recent years. Sardinha et al. (2014) analyzed pressure interference between wells in Horn River Basin by calculating pressure hit percentage. Awada et al. (2015) identified the interference response time by looking at pressure derivatives. Roussel and Agrawal (2017) applied poroelastic geomechanical models to interpret pressure interference data and calculate fracture dimensions. In the HFTS project, two PITs were conducted among 11 horizontal wells at different times of production. Kumar et al. (2018) analyzed interference data from the first PIT by calculating field response times between source and observation wells. In this discussion, we follow the technique presented by Chu et al. (2018) for analyzing power-law PIT data to quantitatively diagnose well communication among HFTS wells. The magnitude of pressure interference (MPI) between communicating wells is calculated and compared for two PIT sequences conducted 18 months apart.
Shoemaker, Michael (Callon Petroleum Company) | Hawkins, James (Callon Petroleum Company) | Becher, John (Callon Petroleum Company) | Gonzales, Veronica (Callon Petroleum Company) | Mukherjee, Sandeep (Callon Petroleum Company) | Garmeh, Reza (Callon Petroleum Company) | Kuntz, David (Callon Petroleum Company)
E&P companies in the Permian Basin typically implement basin-wide development strategies that involve cookie-cutter type methods that use multi-well pads with identical geometric stage and cluster spacing. Such development strategies however fail to recognize and account for subsurface stress heterogeneity, and thus assume similar geomechanical properties that are homogeneous and isotropic which may cause well-to-well interference or “frac hits”, particularly near “parent” wells as fields continue to mature.
Minimum horizontal stress (Sh) is the leading parameter that controls hydraulic fracture stimulation, but is next to impossible to measure quantitatively, especially far field and in 3D space. In-situ stress differences from fluid depletion, combined with stratigraphy and subsequent mineralogy contrasts, control fracture containment vertically and laterally which define fracture propagation and complexity. Far field preference of virgin rock towards brittle vs ductile deformation is governed by mineralogy which defines the elastic moduli or geomechanical behavior of the rock. When integrated with pore pressure and overburden stress, the elastic rock properties are characterized by the Mechanical Earth Model (or MEM) which defines key inputs for calculating Sh using the uniaxial Ben Eaton stress equation. However, implementing this model historically produces incorrect calculated stress, when compared to field measured stress, due to an assumed homogeneous and isotropic subsurface.
Parameterization of fracture geometry models for well spacing, frac hit mitigation, and engineered treatment design in shale (or mudrock) requires an anisotropic in-situ stress measurement that accurately captures subsurface stress states. A method herein is proposed that achieves this using a modified version of the anisotropic Ben Eaton stress equation. The method calculates minimum horizontal stress by substitution of AVO seismic inversion volumes directly into the stress equation, replacing the bound Poisson's ratio term with an equivalent anisotropic corrected Closure Stress Scalar (CSS) defined in terms Lamé elastic parameters, specifically lambda (λ) or incompressibility and mu (μ) for shear rigidity. The CSS volume is corrected for anisotropy using static triaxial core, and is calibrated to multi domain data types including petrophysics, rock physics, completion engineering, and reservoir engineering (DFIT) measurements.
Successful application of said method in the Delaware and Midland sub-basins (of the greater Permian Basin) is shown. Anisotropic minimum horizontal stress (Sh) volumes from 3D seismic defined at 1 ft. vertical log resolution were interpreted quantitatively regionally, particularly as a prevention tool near parent wells prone to frac-hits. Moreover, the method provides an anisotropic measurement of in-situ stress variability (or stress differential) to qualitatively model 3D fracture geometries for engineered treatment optimization. Current stress modeling methods rely on the propagation of geomechanical properties from well control, which do not necessarily represent rock properties and stress states at the area of interest.
During the hydraulic fracturing process, the fracturing fluid may cause water blockage, if the nearby secondary fractures subsequently close and get disconnected due to changes in effective stress distribution during flowback and production. The fluid inside the fractures could also get squeezed out upon fracture closure. The circumstances and detailed mechanisms associated with this phenomenon are still poorly understood. In this work, a coupling scheme for incorporating a pressure-dependent apparent permeability model in reservoir simulation is implemented. The numerical models are subsequently used to investigate the impacts of water blockage and apparent permeability modeling on gas production and water flowback.
A high-resolution 3D reservoir model is constructed based on the field data obtained from the Horn River shale gas reservoir. Stochastic 3D discrete fracture network (DFN) model is upscaled into equivalent continuum dual-porosity dual-permeability (DPDK) model by analytical techniques. A realistic DFN configuration is examined to simulate the potential scenarios of water blocking. An apparent permeability (Kapp) model that accounts for contributions of Knudsen diffusion, slip flow and surface pore roughness is introduced. In order to capture the pressure dependency, a novel coupling scheme is developed to facilitate the updating of Kapp and effective stress after a certain designated time interval. In addition, a novel method involving rock-type indicators is introduced to represent the open and closed states of secondary fractures, facilitating the modeling of stress-dependent closure of the secondary fracture system.
Fracture closure and the resulting water blockage would impact the gas production and water recovery, particularly if the near-well fractures are disconnected. Neglecting the effects of Kapp could essentially overestimate the contribution of hydraulic fracture for a certain observed gas production. The existence of secondary fractures could also enhance water loss, which is contrary to some conclusions in previous research where Kapp modeling and disconnected fractures are ignored. The impacts of shut-in duration and matrix multiphase flow functions are systematically studied. It is concluded that gas and water production would increase if less water is imbibed into the matrix during the shut-in period in the presence of disconnected secondary fractures. It is also observed that a shorter shut-in period may be beneficial to both water and gas recovery, where previous studies have reported no observable increase in gas production when secondary fracture closure was not considered.
This work presents a set of detailed simulation studies to examine the scenarios or conditions that may be responsible for water blockage, particularly in the presence of disconnected secondary fractures. A novel, yet practical, scheme is implemented to couple stress-dependent matrix apparent permeability and fluid flow, as well as to model pressure-dependent fracture closure. The modeling scheme can be readily integrated in most commercial reservoir simulation packages. The results have revealed several potential scenarios of water loss, along with the associated implications on optimal operational strategies and estimation of stimulated reservoir volume.
We analyzed flowback (FB) and post-flowback (PFB) production data from six multi-fractured horizontal wells completed in Eagle Ford Formation. The wells are supercharged at the beginning of the flowback process and the reservoir pressure remains above bubble point during the post-flowback period. Interestingly, we observe a pronounced unit slope (pseudo-steady state) in the rate-normalized pressure (RNP) plots of water for post-flowback period, while such unit slope is not observed for the flowback period. We developed a conceptual and mathematical model to describe these observations and to estimate the average fracture pore volume (Vf) during the post-flowback process. This model assumes no water influx from matrix into the fracture system, which is consistent with the lack of mobile water in the target reservoir. It also assumes stable influx of oil from matrix into the fracture system with insignificant mass accumulation of oil in the fracture system. Therefore, water production at pseudo-steady state conditions occurs under the driving forces of water expansion, oil expansion, and fracture closure. We also performed decline curve analysis on water production data to estimate initial Vf, as the fractures tend to be fully saturated with water at the beginning of the flowback process. The difference between ultimate water recovery and average Vf from the PFB model represents the loss in fracture volume due to fracture closure. The results show that about 65% of fracture closure occurs after 7 months of PFB production. Fracture closure is the dominant drive mechanism during FB and early PFB periods when reservoir pressure drops rapidly.
Analysis of flowback is becoming a common practice for early characterization of fractured horizontal wells completed in unconventional reservoirs. Several authors have developed different models for analyzing early flowback data to characterize complex fracture networks created by multi-fractured horizontal wells. Examples of recent studies include Abbasi et al. (2012, 2014), Ezulike et al. (2013), Clarkson and Williams-Kovacs (2013), Ezulike and Dehghanpour (2014a, b), Jia et al. (2015), Xu et al. (2016), Ezulike et al. (2016), Yang et al. (2016), Williams-Kovacs (2017) and Chen et al. (2017).
Connectivity of the pore system is crucial for production of hydrocarbons from unconventional resources. In shales, pore throats critically control and limit permeability. Even if larger pores are the dominant pore size, small pores throats could ultimately control the access to that pore space. Mercury injection capillary pressure (MICP) measurements are commonly made to determine pore throat size distributions. Results for shales usually show large injection volumes associated with pore throats just several nanometers in diameter. The existence of these small pore throats has also been confirmed by Focused Ion Beam/Scanning Electron Microscope (FIB/SEM) analysis. One of the unique properties of mercury is that it is non-wetting to both matrix phases present in organic-rich shales; therefore, it can access pore systems in both organics and inorganics. MICP measurements dynamically alter the pore structure through pore compressibility which intrinsically depends on the aspect ratios of the pores; crack like pores, with very high aspect ratios, may close at low pressures and may not be sampled by MICP. The connectivity of the pore space and how much of it is accessed by MICP remains poorly understood.
Here we report on shale samples that have undergone MICP followed by Micro X-ray Computed Tomography (μXCT) and FIB/SEM imaging. μXCT results show that not all regions of the shale samples were accessed uniformly by MICP. Mercury is observed going into fractures and penetrating into the shale matrix. The distance away from the fractures and the percentage of the sample volume accessed by mercury has been calculated. Some samples, such as the Tuscaloosa Marine Shale, showed mercury penetration throughout specific layers in the sample, whereas Eagle Ford samples showed mercury penetration more uniformly and on average of almost 150 μm away from the fractures with almost 60% of the entire sample volume accessed by the mercury. These μXCT results suggest that mercury is not fully accessing all the pore space of the sample even at 60,000 psi which corresponds to a pore throat radius of 1.8 nm.
Cryo FIB/SEM was used to further investigate mercury intrusion into the shale matrix at the nanometer scale. Frozen droplets of mercury were observed in pores as small as 30 nm which corresponds to an injection pressure of 6,000 psi. The mercury clearly accessed the organic pores and remained after pressure was reduced. This is also reflected in the hysteresis observed in the MICP spectra captured during pressurization and depressurization. The magnitude of the hysteresis is a consequence of the differences between pore bodies and pore throats. Like the μXCT, SEM results show that intrusion of mercury into the sample is not uniform indicating that many of the pores are not connected to the outside of the sample. These results suggest that pore connectivity in shales may be very limited, and the volume accessible may not extend far from fractures in the shales.
Unconventional resources such as Bakken shale have made a significant impact on the global energy industry, but the primary recovery factor still lingers from 5% to 15 %. Over the past ten years, a number of pilot tests for both gas and water injection or their cyclic injection have been implemented to improve oil recovery in the Bakken Formation. The available public data show that the injectivity is not a problem, but only a small increase in production. The obvious reason is unexpected early breakthroughs even with a relatively low reservoir permeability of around 0.03 mD. Lots of experimental and simulation studies have been conducted to investigate different mechanisms behind these improved oil recoveries. However, no one has succeeded to clarify this early breakthrough.
In this study, a simulation reservoir model, including two wells, is developed, whose properties are based on public data. In terms of hydraulic fractures for each well, their geometry and conductivities are evenly built. Furthermore, our geomechanical module is applied to capture the evolution of stress field and rock failure, where a Barton-Bandis model and a Mohr–Coulomb failure criterion are applied to model tensile and shear failure, respectively. Our simulation model coupled with the geomechanical module is then implemented to explain the performance of injection pilot test.
The results of this initial study clearly show the new fractures (frac-hits) induced by water injection connect the injection and production wells, resulting in the early water breakthrough. The stress field has also been altered by the production process to favor the formation of these fractures. This study highlights the importance of geomechanics during an IOR process; identifies the reasons for the early breakthrough and provides an insight view about how to improve oil production in the Bakken Formation.
The main goal for an operator developing an unconventional reservoir project is to maximize NPV per acre by optimizing its completion strategy. This can be achieved by applying a comprehensive approach that accounts for key well treatment controlling parameters, their impact on the future production performance, and economic uncertainty. In this work, we developed and applied a workflow to explore the impact of various completion parameters and determine the completion strategy with the maximum economic gain.
The workflow integrates petrophysical well log and core data, along with PVT lab experiments with normalized permeabilities calculated from microseismic attributes to initialize the reservoir model. The reservoir model is then calibrated using actual field data to generate a history matched model. Since this model is developed based on microseismic data and represents a realistic network of fractures created during stimulation, it can be further used to analyze the impact of main completion parameters, well spacing and configuration, on the production performance of the wells.
The workflow is applied to three wells drilled in a gas reservoir in the Marcellus Shale. Because abundant field data were available, we can be certain that the calibrated reservoir model accurately matches the reservoir behavior. Detailed analysis of the reservoir model shows the presence of undepleted zones which indicates the current well spacing is too wide. However, the frac hits recorded through microseismic monitoring and pressure interference with nearby wells suggests a tighter well spacing will result in energy loss and over-stimulation. Therefore, an economic analysis is used to evaluate the various well spacing and configuration scenarios and their implications in terms of cost-benefits.
Various well spacing scenarios are created for the original and the proposed chevron pattern well configurations. For each scenario, the EUR, NPV per well, and NPV per acre are calculated to represent maximum gas production, the overall profitability of the pad, and the economic success of the project, respectively. Three gas price scenarios are used for calculation of the NPV's to analyze the impact of the market condition on the economics of the project. The analysis demonstrates that tighter well spacing, independent of gas price, leads to the improved NPV per acre, reduction of EUR, and an increase in well communication as shown by the newly developed well communication index. The models reveal that a monotonic relation between well spacing and NPV per acre does not exist due to the complex nature of the created fracture network and competition between two opposite factors: frac hits that arises at tighter well spacing and unstimulated zones that diminish.
We showed that obtaining optimized well spacing and configuration could only be achieved through applying a comprehensive workflow that not only accounts for the impact of various well design and configuration parameters on production but also their economic implications defined in terms of NPV per acre. It is important to note that the integration of microseismic data was essential for the success of the workflow since it provides a realistic picture of the pathways connecting the adjacent wells which facilitate well communication.
Frac hits relates to the problem of newly created hydraulic fractures interacting with either primary and/or secondary fractures from offset wells. This fracture-driven interaction (FDI) represents a major concern for shale oil and gas producers given that infill wells experiencing frac hits typically underperform parent wells landed in the same zone. In addition, the sudden pressure communication established through frac hits between multi-fractured horizontal wells (MFHW) can result in damage to parent wells.
In this work, we introduce an analytical model to detect frac hits and assess the fraction of primary fractures connected between the infill and offset well. We assume that frac hits are due to overlapping primary fractures. Frac hits are modeled as a valve between MFHWs that allows certain degree of pressure communication. While the aperture of this valve is controlled by the number of frac hits, the leakage rate is governed by the bottomhole pressure (BHP) differential between wells.
The analytical solution to the fluid-flow model is derived in Laplace domain and is inverted numerically. We found that BHPs are coupled via the degree of interference coefficient δw, defined as the ratio of frac hits to the total number of primary fractures of the infill well. We utilize δw to history-match the analytical model with numerical data. As a result, history-matched δw delivers an estimate of the actual fraction of frac hits ((Equation)).
We study several sensitivity analyses to examine the impact of variation in MFHW properties on the accuracy of the estimation of (Equation) via δw. In general, our model gives an accurate estimation (Equation) for most of the cases evaluated in this work; however, we see that the analytical model may introduce significant error in the estimation of frac hits when SRV and matrix permeability are the same order magnitude. Type-curves for rate-normalized data as well as (Equation) vs δw tables are discussed herein. The computational script used for the analytical calculations in this work proved to be efficient and straightforward to implement.
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, there is no efficient approach to estimate the fracture surface area at present. In this paper, we propose a method to calculate the fracture surface area based on the falloff data after each stage of the main hydraulic fracture treatment.
The created hydraulic fracture closes freely before its surfaces hit on the proppant pack, and this process can be recognized on the pressure falloff data and its diagnostic plots. The pressure decline rate during fracture closure is mainly caused by fluid leakoff from the fracture system into the formation matrix. For a horizontal well drilled in the same formation, we may assume the same leakoff coefficient among all stages, so the total fracture surface area can be calculated for all stages to meet the requirement of the fluid leakoff rate.
Wellbore storage effect, friction dissipation and tip extension dominate the early pressure falloff data. While the transient dominated by friction losses typically lasts about one minute, tip extension may end after about 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 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 promise as a straightforward way to estimate fracture surface areas that could, enable, in turn, an early estimate for the expected well performance.