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Wang, Lipeng (Schlumberger) | Du, Xianfei (PetroChina) | Qiu, Kaibin (Schlumberger) | Wu, Shunlin (PetroChina) | Zhuang, Xiangqi (Schlumberger) | Bai, Xiaohu (PetroChina) | Wang, Lizhi (Schlumberger) | Pan, Yuanwei (Schlumberger)
Severe frac hit incidents were encountered during stimulating horizontal production wells in a pilot pad of a tight oil reservoir in Ordos basin. The reservoir is interbedded, highly heterogeneous both vertically and horizontally as result of gravity flow deposition. This raised a big concern on the stimulation treatment size and well spacing of the pad and further implication on the field development plan of the reservoir. A deep understanding of root causes and an effective frac hit prevention and mitigation strategy were much needed to address the problem.
A multidisciplinary team was formed to investigate the problem. Initial analysis on the frac hit incidents showed that the frac hits were not correlated to well spacing, or stimulation volume as frac hits only occurred at certain stages out of those with the same stimulation volume or well spacing. Then the study turned the focus to investigating the problem from the geological and geomechanical perspective through leveraging a 3D high definition (HD) geological and geomechanical model.
The detailed investigation revealed that the root causes of the frac hits were multiple folds: Existence of natural fracture corridors led to frac hit of wells in much longer distance. Alignment of hydraulic fractures among horizontal wells also increased the chance of frac hits as the result of alignment of perforations among horizontal wells. Asymmetrical propagation of hydraulic fracture (e.g., deviated to one side of horizontal laterals increased the chance of frac hit as the result of heterogeneous sand body and in-situ stress field.) Lack of vertical fracture containment resulted in the crossing-layer frac hits.
Existence of natural fracture corridors led to frac hit of wells in much longer distance.
Alignment of hydraulic fractures among horizontal wells also increased the chance of frac hits as the result of alignment of perforations among horizontal wells.
Asymmetrical propagation of hydraulic fracture (e.g., deviated to one side of horizontal laterals increased the chance of frac hit as the result of heterogeneous sand body and in-situ stress field.)
Lack of vertical fracture containment resulted in the crossing-layer frac hits.
With the good understanding of the root causes of frac hits, a frac hit risk map was generated based on the 3D HD geoscience model, which highlighted high frac risk zone in the pad. The frac hits observed from subsequent stimulations of the horizontal wells occurred only in the high frac hit risk zone, which validated the frac hit risk map. Based on the findings from the study, the frac hit prevention and mitigation strategy was developed.
Many operators have increasingly moved toward cube development to avoid production impairment due to parent and child wells’ fracture-driven interactions (FDI). This cube development technique involves stimulating multiple wells in a section before bringing them online simultaneously or relatively close in time. This implies significant upfront investment to drill and complete in some cases 10’s of wells before producing a drop of hydrocarbon from them. Therefore, it becomes critical that the wells are completed optimally to be able to extract maximum resource from the reservoir. Multi-well stacked pad development renders itself as a 4D problem for completion optimization. Well spacing in horizontal and vertical direction and perforation spacing along the lateral being the 3 spatial dimensions, as well as the timing and sequencing of stages add the fourth dimension to the problem. Sensitizing for different sequencing scenarios in the modeling space before operational execution of the stimulation offers a cost-effective way to optimize production.
We explore the impact of hydraulic fracturing sequence and spacing on production from the group of stacked wells in a section of the Delaware Basin. A three-dimensional geomodel along with a discrete fracture network is utilized to model a complex hydraulic fracture system created for multiple treatment sequencing and spacing scenarios. Stress shadow from previously stimulated stages is seen to be a major driver in controlling the geometry of the fractures in the wells stimulated later and can be utilized to enhance reservoir contact. Finite element modeling shows the positive impact of the stress re-orientation resulting from previously stimulated stages. Hydraulic fractures confined by stress from outside wells show clear growth pattern into unstimulated sections of the reservoir, thus enhancing the production potential.
The stimulated reservoir volume and simulated production are used as key performance indicators (KPIs) for choosing the optimum sequencing and spacing strategy in this study, however the KPI can be changed to meet individual asset needs. This work aims to provide a workflow for modeling stacked well pad development and explores innovative approaches to sequence stimulation stages on wells in order to improve reservoir contact.
Kumar, Abhash (National Energy Technology Laboratory / Leidos Research Support Team) | Hu, Hongru (University of Houston) | Bear, Alex (National Energy Technology Laboratory) | Hammack, Richard (National Energy Technology Laboratory) | Harbert, William (National Energy Technology Laboratory / University of Pittsburgh)
Abstract Hydraulic fracturing involves the injection of large amount of fluid, typically water, in the reservoir rock that increases fluid pressure in the pore spaces and alters the stress condition of the rock significantly. This sudden change in the stress condition is strong enough to create new fractures in the rock or stimulates slip along the pre-existing fractures. Creating new fractures or inducing slip along multiple pre-existing fractures, both results into a marked increase in the interconnectivity of pore spaces and enhance the flow of oil and gas within the stimulated volume. The distribution of microseismic earthquakes that are generated during hydraulic fracturing is traditionally used as a proxy to estimate stimulated reservoir volume (SRV). For efficient extraction of oil and natural gas, it is extremely important to get an accurate estimate of the SRV. However, a simple energy balance calculation suggests that the combined energy released from all microseismic earthquakes during hydraulic fracturing is a small portion of the total input energy, supplied to the reservoir rock in the form of injected fluid. The difference in the total input and output energy suggests some alternate mechanism of deformation in the reservoir rock during hydraulic fracturing that need to be considered to get more accurate estimate of the total stimulated reservoir volume. Recent studies of hydraulic fracturing in the Barnett Shale, Marcellus Shale, Eagle Ford Shale and Montney Shale found the evidence of low-frequency events, with drastically different seismic signature (frequency, amplitude, time duration) than traditional microseismic earthquakes. These low frequency (1-80 Hz) earthquakes are proposed to be associated with either jerky opening or slow rate of slip along pre-existing fractures that are unfavorably oriented in the ambient stress field and releasing as much as 1000 times the energy of an average microseismic earthquake. We identified multiple long period long duration (LPLD) earthquakes in the surface seismic data recorded during hydraulic fracturing of the two Middle Wolfcamp Shale wells in Reagan County (RC), TX. LPLD events identified in this study show a dominant P-wave signal that persists for 5-10 seconds and significantly long duration compared to traditional microseismic events. We also noticed finite decay in seismic amplitude across the surface-monitoring array suggesting a non-regional or local source of deformation for their origin. We aim to compare and contrast our surface seismic observations on LPLD with seismic data from two 24-tool borehole arrays that were deployed in vertical section of the two nearby treatment wells. This comparison between surface and borehole data will be of strategic importance to evaluate the efficiency of surface seismic monitoring and it would also be helpful in finding more LPLD events in borehole data that are usually less contaminated with the surface noise.
During hydraulic fracturing, the interaction of hydraulic fractures with natural fractures can result in the formation of complex fracture networks. In the past these interactions have been captured in hydraulic fracturing models using crossing criteria developed based on two-dimensional geometries. In this work, we investigate the interaction of hydraulic fractures and natural fractures in three-dimensions and demonstrate that there can be significant differences in the observed interactions.
A hydraulic fracturing simulator is presented that solves the coupled fluid flow and geomechanics problem for three-dimensional fractures. The simulator captures the physics of fracture growth and the intersection of hydraulic fracture with pre-existing discrete fracture network. The model employs a robust algorithm to account for the stress relaxation due to the slippage of natural fractures. The displacement of failed natural fracture elements is calculated rigorously. The model allows the partial failure of three-dimensional natural fractures and accurately calculates the stresses acting on the plane of the natural fracture.
It is shown that a natural fracture inclined at an angle to an approaching hydraulic fracture experiences compression in one region (due to the stress shadow of the growing hydraulic fracture) and tension in other regions (in front of the approaching hydraulic fracture tip). The generated stresses can fail the natural fracture partially. The failure of the natural fracture relaxes the stresses around it, which can modify the direction of propagation of the approaching hydraulic fracture. In addition, if the elliptical front of the hydraulic fracture crosses an intact planar natural fracture, the three-dimensional geometry results in a line of intersection (between natural fracture and hydraulic fracture). This can lead to failure of the natural fracture even after the elliptical front has partially crossed the natural fracture. Such an interaction can allow the hydraulic fracture to both cross the natural fracture and activate (or dilate) it. These effects cannot be captured by two-dimensional simulations. This work improves our understanding of the interaction between hydraulic fractures and natural fractures. The novel results provide new insights into the mechanisms responsible for the complexity that is often observed in hydraulic fractures.
Summary The development of unconventional shale-gas formations in North America with horizontal multifractured wells is mature enough to identify production malpractices and abnormal productivity declines generally observed within 18–24 months of initial production. The primary objective of this study is to address all known causes of these productivity declines and to develop a fully coupled geomechanical/flow simulation model to simulate these production conditions. This model mimics the effect of depletion-induced in-situ stress variations on short-term and long-term productivity by taking into account several phenomena, such as stress-dependent matrix and natural-fracture permeability as well as reduction in hydraulic-fracture conductivity caused by proppant crushing, deformation, embedment, and fracture-face creep. Matrix-permeability evolutions, considering the conflicting effects of non-Darcy flow and compaction, have also been accounted for in this model. Numerical solutions for simplified hydraulic-fracture planar geometries are then obtained by use of a finite-element-method scheme. A synthetic case was defined to investigate the effects of each individual phenomenon on short-term and long-term production. Results show that the combined effects of permeability alterations in matrix and natural fractures as well as conductivity losses in hydraulic fractures may result in substantial cumulative-gas-production loss. The model also reproduces familiar field-observed trends, with lower long-term production corresponding to higher drawdowns. This behavior is attributed to the stress-dependent evolution of reservoir permeability and hydraulic-fracture conductivity. The results show that ignoring the effects of any of the previous phenomena results in overestimation of ultimate recovery. Furthermore, it is shown that proper management of pressure drawdown and the penalty for lower initial production rates in unconventional shale-gas reservoirs can yield substantially higher ultimate recovery. The model is fully versatile and allows modeling and characterization of all widely differing (on a petrophysical level) shale-gas formations as well as proppant materials used for the stimulation treatments. This integrated model can be used for optimization of key parameters during the hydraulic-fracture design, for fine tuning production history matching, and especially as a predictive tool for pressure-drawdown management.
Kumar, Abhash (National Energy Technology Laboratory, AECOM) | Chao, Kevin (Northwestern University) | Hammack, Richard (National Energy Technology Laboratory) | Harbert, William (National Energy Technology Laboratory, University of Pittsburgh)
Abstract Low-frequency seismic events of long duration were recorded by a surface array of 48, 3-component geophones during the fracture stimulation of two offset horizontal wells in the Middle Wolfcamp Formation (8000–8100 ft. below the geophone array) at the Hydraulic Fracturing Test Site (HFTS) in Reagan County, TX. Each recorded event was approximately 5–10 seconds long, with no clear first wave arrival; the seismic energy was largely visible on the vertical component suggesting that the events are dominated by P waves. A finite temporal moveout was observed across the seismic network in event arrival times indicating a causal relationship with the local source of deformation. The low-frequency seismic events observed in this study can be distinguished from the more commonly known microseismic events by their: emergent waveform, lack of clear P wave and S wave arrivals, longer duration (few seconds), and lower-frequency energy content (10–60 Hz). Previous researchers have observed similar low-frequency, long duration events in conjunction with the hydraulic fracturing of hydrocarbon reservoirs and have referred to them as long-period, long-duration (LPLD) events in the literature. LPLD events may be important to a comprehensive understanding of fracture stimulation because these events are thought to represent: movement along pre-existing discontinuities such as bedding planes and fractures/faults, deformation of ductile rocks with high clay content, and the jerky tensile opening of hydraulic fractures. LPLD events resulting from slow shear-slip on faults and fractures of relatively larger dimension or rupture in the clay rich rock are collectively referred to as slow-slip seismicity, which was first observed in tectonic and volcanic settings, areas with high pore pressure like hydraulically fractured reservoirs. Because LPLDs are thought to represent deformation mechanisms not captured by microseismic analysis (which dominantly indicate shear failure of brittle rock), we believe that incorporating LPLD events into a new methodology for delimiting stimulated reservoir volume might improve predictions of well production.
Lascelles, Peter (EP Energy) | Wan, Jichun (EP Energy) | Robinson, Lauren (EP Energy) | Allmon, Randy (EP Energy) | Evans, Grant (EP Energy) | Ursell, Luke (Biota Technology) | Scott, Nicole M. (Biota Technology) | Chase, John (Biota Technology) | Jablanovic, Jelena (Biota Technology) | Karimi, Moji (Biota Technology) | Rao, Vik (Biota Technology)
Abstract DNA diagnostics is a new reservoir characterization tool with potential to maximize reservoir production in tight rock formations. DNA extracted from rock layers provides high resolution fingerprints that define a "DNA stratigraphy" for organic intervals like the Wolfcamp. DNA sequences originate from microbes feeding on organic matter or minerals within the formation. A DNA stratigraphic profile, or type section, was assembled from a vertical pilot well's cuttings and core. The DNA signature from produced oil from offset laterals was subsequently compared against the DNA type section to provide estimated effective drainage height. Cuttings from a lateral well were compared with DNA from its produced oil to construct a production profile comparable to a traditional production log. In addition, when oil samples are collected over time, the method provides insight on interference, completion effectiveness, and SRV (Stimulated Reservoir Volume) changes with time. An optimized development plan in unconventional reservoirs requires operators to understand parameters such as effective drainage height, hydraulic fracture half-length and individual stage contributions resulting from their completions. Wolfcamp reservoirs consist of highly laminated mudrocks interbedded with limestones that have quite different mechanical properties. These contrasting lithologies make it difficult to estimate resultant completion geometries, SRV, and well-to- well interactions. Also, using costly production logs, individual stage contributions are difficult to obtain in lower pressure reservoirs like the Wolfcamp. However, these reservoir performance parameters are required to set benchmarks and continuously uplift the EUR by taking advantage of insightful diagnostics. Production logs, micro-seismic, chemical or radioactive tracers are all useful in understanding the subsurface, but can be expensive and can pose operational challenges. Subsurface DNA sequencing is a relatively low cost new data source that can be used to gain subsurface insights in complicated reservoirs. DNA stratigraphy can help assess critical geometric parameters resulting from stimulation by employing non-invasive sampling that enables lifetime well monitoring to track the flow of oil and provide engineers the basis to optimize completions and development plans. An 8 well "subsurface" lab was selected for the experiment. The project included one vertical pilot hole with cuttings, and 8 horizontal wells landed in two Wolfcamp pay zones (one of the laterals was extended from the same vertical pilot). Three horizontals had been on production for 11 months before the pilot well and 6 additional laterals were drilled. The pilot well and its sidetracked lateral had cuttings extracted for DNA sequencing. DNA signatures from the pilot well and lateral well were compiled to produce vertical and lateral DNA stratigraphic profiles. The DNA stratigraphic profiles were then compared to DNA from oil produced in the 7 offset laterals. DNA profiles were also compared to standard geologic parameters using pilot well e-logs, particularly mechanical stratigraphy. Lateral wells were sampled at various times after initial production to assess changes with time. Blind tests were designed to check the method as a reasonable estimator for effective drainage height and communication. DNA stratigraphy provides a more informed view of well spacing, completion design and well performance to help increase efficiency and asset value.
Summary Since the late 1980s when Maersk published their work on multiple fracturing of horizontal wells in the Dan field, the use of transverse multiple-fractured horizontal wells has become the completion of choice and the “industry standard” for unconventional and tight-oil and tight-gas reservoirs. Today, approximately 60% of all wells drilled in the United States are drilled horizontally, and nearly all are multiple-fractured. However, little work has been performed to address and understand the relationship between the principal stresses and the lateral direction. This paper has as its goal to fundamentally address the questions: In which direction should I drill my lateral? Do I drill it in the direction of the maximum horizontal stress (longitudinal), or do I drill it in the direction of the minimum horizontal stress (transverse)? This work focuses on how the horizontal well's lateral direction (longitudinal or transverse fracture orientation) influences productivity, reserves, and economics of horizontal wells. Optimization studies, with a single-phase fully 3D numerical simulator including convergent non-Darcy flow, were used to highlight the importance of lateral direction as a function of reservoir permeability. The simulations, conducted for both oil and gas formations over a wide range of reservoir permeability (50 nd–5 md), compare and contrast the performance of transversely multiple-fractured horizontal wells with longitudinally fractured horizontal wells in terms of rate, recovery, and economics. This work also includes a series of field case studies to illustrate actual field comparisons of longitudinal vs. transverse horizontal well performance in both oil and gas reservoirs, and to tie these field examples to the numerical-simulation study. Further, the effects of lateral length, fracture half-length, and fracture conductivity were investigated to see how these parameters affect the decision of lateral direction in both oil and gas reservoirs. In addition, this study seeks to address how completion style (openhole or cased-hole completion) affects the selection of lateral direction. The results show the existence of a critical reservoir permeability, above which longitudinal fractured horizontal wells outperform transverse fractured horizontal wells. With openhole completions, the critical permeability is 0.04 md for gas reservoirs and 0.4 md for oil reservoirs. With cased-hole completions, longitudinal horizontal wells are preferred at a reservoir permeability above 1.5 md in gas reservoirs, and transverse horizontal wells are preferable over the entire permeability range of this study (50 nd–5 md) in oil reservoirs. These are new findings. Previous work generally suggested that longitudinal horizontal wells are a better option for gas reservoirs with permeability over 0.5 md, and for oil reservoirs with permeability over 10 md. This work extends prior study to include unconventional reservoir permeabilities. It provides critical permeability values for both gas and oil reservoirs, which are validated by the good compliance between actual field-case history and simulation results. This work also demonstrates a larger impact of completion method over fracture design. These findings could guide field operations and serve as a reference for similar studies.
Abstract The development of unconventional shale gas formations in North America with horizontal multifractured wells is mature enough to identify production malpractices and abnormal productivity declines generally observed within 18 to 24 months of initial production. The primary objective of this study is to address all known causes of these productivity declines and to develop a fully coupled geomechanical-flow simulation model to simulate these production conditions. This model mimics the impact of depletion-induced in-situ stress variations on short-term and long-term productivity by taking into account several phenomena, such as stress-dependent matrix and natural fracture permeability as well as reduction in hydraulic fracture conductivity due to proppant crushing, deformation, embedment, and fracture-face creep. Matrix permeability evolutions, considering the conflicting effects of non-Darcy flow, and compaction, have also been accounted for in this model. Numerical solutions for simplified hydraulic fracture planar geometries are then obtained using a finite element method (FEM) scheme. A synthetic case was defined to investigate the effects of each individual phenomenon on short-term and long-term production. Results show that the combined effects of permeability alterations in matrix and natural fractures as well as conductivity losses in hydraulic fractures may result in substantial gas cumulative production loss. The model also reproduces familiar field-observed trends, with lower long-term production corresponding to higher and higher drawdowns. This behavior is attributed to the stress-dependent evolution of reservoir permeability and hydraulic fracture conductivity. The results conclude that ignoring impacts of any of the above phenomena results in overestimation of ultimate recovery. Furthermore, it is shown that proper management of pressure drawdown and the penalty for lower initial production rates in unconventional shale gas reservoirs can yield substantially higher ultimate recovery. The model is fully versatile and allows modeling and characterization of all profoundly different (on a petrophysical level) shale gas formations as well as proppant materials utilized for the stimulation treatments. This integrated model can be used for optimization of key parameters during the hydraulic fracture design, for fine-tuning production history matching, and, especially, as a predictive tool for pressure drawdown management.
Summary The objective of this study is to develop physical models to quantitatively simulate the pressure response of well interference through fracture hits with complex geometries. Our study offers a model for an improved understanding of the influence of key reservoir and fracture properties on intensity of well interference, which may help field operators to further optimize the spacing of wells in a multi-well pad. We combine numerical, semi-analytical, and analytical model tools to identify, analyze, and visualize the inter-well interference process. Our analysis can account for complex non-planar fracture geometries using a semi-analytical model. The stimulated rock volume is visualized by an analytical streamline model. Three scenarios for well interference are investigated including interference through a single slanted fracture hit, multiple slanted fracture hits, and multiple complex fracture hits. For the first scenario, we examine the effects of connecting fracture conductivity, primary fracture conductivity, and matrix permeability on the pressure response of a shut-in well. For the second scenario, we vary the number of connecting fractures to investigate the impact on the pressure response of a shut-in well. For the last scenario, we use a complex fracture propagation model to generate non-planar fracture geometries with and without natural fractures. The semi-analytical model is used to evaluate the effect of both hydraulic and natural fractures on the pressure response of a shut-in well. The simulation results show that the pressure drop of the shut-in well increases with the increasing conductivity of connecting fractures and primary fractures and number of connecting fractures, while decreases with the increasing of matrix permeability. Furthermore, the pressure drop of the shut-in well through complex fracture hits without natural fractures is larger than that with natural fractures. Introduction Determination of the optimum well spacing is a key factor to improve the economic performance of unconventional oil and gas resources developed with multi-well pads. Tighter well spacing often results in well interference through complex connecting fractures, also known as fracture hits (Lawal et al. 2013; King and Valencia 2016). It is common to drill infill wells in a multi-well pad to effectively increase the stimulated area and maximize recovery (Safari et al. 2015). However, infill well drilling increases the risk of well interference. Ideally, the infill wells should have the minimum well interference with the existing wells (Ajani and Kelkar 2012). When the well spacing is much closer, the well interference is more frequent (Ajani and Kelkar 2012; Malpani et al. 2015; Kurtoglu and Salman 2015). The fracture hits can negatively affect well performance when damaging a well (Yaich et al. 2014; Malpani et al. 2015). Hence, a better understanding of well interference is fundamentally important for further well spacing optimization.