|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Abstract 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. Introduction 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.
In modeling of multifrac horizontal wells, the contacted drainage volume given by the flowing material balance might be misunderstood to be the contributing fracture volume. This work uses field data and numerical simulations to demonstrate that the flowing material balance needs to be done in two steps and in conjunction with flow regime identification, otherwise it may result in overestimation of the stimulated reservoir volume. For multiple case studies in different shale plays across North America, we show that the end of linear flow period through areas with enhanced permeability is mostly controlled by fracture width and may occur very soon, in a few days or weeks, while the linear flow through reservoir endures much longer, for months or even years, until the drainage volume front reaches the outer no-flow boundaries often located between adjacent producing wells. The simulations suggest that the material balance-derived reservoir volume corresponding to the end of the first linear flow period gives a reasonable estimate of the contributing fracture volume for both oil and gas wells. According to the results, using sub-daily production data during first 2-8 weeks of production helps detect the transition of flow regimes more accurately. Furthermore, to convert the SRV’s volumetric estimate to its geometric representation, we integrate production data analysis with a three-step microseismic analysis workflow allowing us to extract the contributing fracture dimensions.
When simulating unconventional wells; the more confident the dimensions of Stimulated Reservoir Volume (SRV), the less uncertain are the history-matched matrix and SRV permeabilities. All SRVs are unique and subject to considerable spatial variability over a wide range of scales. Their structure can vary due to myriad parameters, including but not limited to the completion design,
Abstract Unconventional plays present a challenging case to design an optimized stimulation program and to maximize reservoir contact and hydrocarbon production. In this regard, conducting a reliable well spacing optimization study demands realistic and explicit fracture descriptions. This work applies an integrated technique to a multi-well case study in the Permian Basin to extract fracture dimensions based on microseismicity-derived behavioral fracture maps, while honoring the RTA-based estimates of the contributing fracture volume. The fracture dimensions are then used to conduct analytical and numerical studies to decide the optimal well spacing/placement design in the target formation. The numerical simulations in two stacked and staggered configurations confirm that although the staggered development causes a marginal decrease in the individual wells' performance, if successfully accomplished, it contributes to a higher vertical sweep efficiency from the section. Furthermore, comparing the approximations of failure planes, constructed based on the spatiotemporal analysis of microseismic events, with those achieved through seismic moment tensor inversion confirms that the collective behavior analysis gives fair estimates of fracture spatial evolutions.
Abstract In this case study, three sequential well pads were designed, stimulated and monitored to evaluate 1. Treatment order of stacked wells across multiple benches, 2. Completions optimization in proximity to a parent well and 3. The efficacy of treatment sequence in proximity to parent wells. Microseismic data were evaluated in conjunction with tracer and pressure data to provide a more detailed understanding of reservoir deformation and well connectivity using statistical approaches that consider the collective behavior of seismicity. High-resolution microseismic involves analyzing spatio-temporal trends in seismicity rather than reliance on microseismic event clouds to provide more meaningful assessment of hydraulically-linked seismicity vs. stress-driven seismicity. The findings of the first two case studies were applied to the stimulation of the third well pad to demonstrate the role of well sequencing in proximity to depleted zones and the impacts of completions design in managing well communication. Here we discuss the benefit of high-resolution microseismic in assessing perceived well interference by delineating the difference between hydraulically-linked and stress-driven seismicity recorded during multi-well hydraulic fracturing programs. In applying knowledge of reservoir deformation processes to customize stimulation programs, operators have additional tools to help manage reservoir stress, limit unwanted well communication and optimize production.
Urbancic, Ted (ESG Solutions) | Baig, Adam (ESG Solutions) | Viegas, Gisela (ESG Solutions) | Thompson, John M. (Anderson Thompson Reservoir Strategies) | Anderson, David (Anderson Thompson Reservoir Strategies) | Rice, Craig (Apache Canada) | Martin, Lucas (Apache Canada)
Abstract Common approaches based on event locations have not been able to effectively identify the connected volume leading to production. Utilizing the collective statistical behavior of seismicity, including their source characteristics, the underlying dynamic response of the reservoir through their spatial-temporal interaction during stimulation can be identified. We have successfully been able to descriptively identify the role of interacting rock properties, fracture state, and stress state, and how they can be used to construct reservoir descriptions that specify where flow and production volumes are most likely to be located relative to the treatment wellbore. By utilizing production data for a multi-well pad program in the Duvernay formation, a calibration of the dynamic parameters with RTA has been established which reduces the uncertainty of possible reservoir descriptions for model-based production forecasting. The synchronization of these data, coupled with production logs, geologic information, and fracture state, lead to an understanding of the effective, non-uniform fracture properties across the lateral of a horizontal well. The coupling of these techniques demonstrates a practical and transparent approach to enhancing reservoir characterization and improving decisions for field development design and adaptations to in-field stimulations in near real-time. A workflow for production and microseismic data integration is presented. The case studied examined provides definitive locations of stimulated reservoir volume (SRV) from dynamic parameter analysis (DPA), which corroborates the observed well performance data behavior; namely well interference effects and relative performance differences between wells. Introduction The challenges associated with assessing the effectiveness of a stimulation program in unconventional plays are well described in the literature (Cipolla et al. 2009 and Cipolla et al. 2011). Complexities due to well-developed preexisting fracture networks and their behavior during injection has in recent years been addressed by considering the microseismic response to the stimulation program. In many ways microseismicity has been considered to provide insight into frac growth and extent, however the simplified view that event distributions are representative of a producing volume has been rebuked by many studies (e.g. Urbancic and Baig, 2013, Huang et al., 2014). The distribution of microseismic events has been shown to be more of an estimate of the maximum potential producible volume for modeling purposes rather than actual productive volume.