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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.
One of the missing pieces for the Delaware Basin development in the Wolfcamp Formation is optimal spacing for horizontal wells. The spacing varies with formation characteristics (rock and fluid) across the Delaware Basin. A single method of determining optimal spacing has yet to be found as many pieces of information are still missing. Among the various parameters affecting development, well patterns and completion methodologies. Both parameters show a significant impact on the drainage area of wells and may in turn affect optimal spacing between the wells. The model outcomes are expected to improve recovery efficiency and minimize environmental effects of unconventional resource development. Several spacing tests were implemented in various areas of the Delaware Basin with multiple completion strategies. Private production and spacing data were analyzed in conjunction with data analytics. This step led to a newly developed model to optimize spacing. Various reservoir parameters such as permeability, fracture width and height, drainage area, reserves, and recovery factors were estimated according to patterns discovered by transient flow rate analysis.
These parameters may lead to an optimal spacing for the stacked Delaware Basin, and contribute to a better understanding of future neighboring wells development. Our findings and correlation within the Wolfcamp will be applied to various sections and formations across the Permian Basin. Current workflows and spacing advisors require use of numerical reservoir simulation and fracture simulation. Drainage area, reserves, recovery factors, and fracture height and width are the main unknowns in unconventional plays. Application of data analytics with production, spacing, life of the well on production, and completion data is anticipated to resolve some of these issues.
The paper is to develop a thorough understanding of well spacing and to propose a strategy for optimization in shale and tight rocks. Well interference due to fracture driven interaction (FDIs) (frac hits) may occur between neighboring wells especially if the distance between the wells are narrow. This interference must be avoided to reduce negative impact on productivity and estimated ultimate recovery (EUR) of the producing wells. The impact of these interactions is intricate and requires advanced numerical modeling to account for fracture propagation and depletion effects due to varied spacing sets (Kan et al. 2019).
For most US unconventional resources development, operators usually first drill the parent wells to hold their leases. After several years, infill wells will be drilled. The Meramec stack play in Anadarko Basin, Oklahoma is a multi-layered tight oil reservoir and its development just followed this practice. The parent well was drilled in layer 3 and shut down after 2-year production for infill well completion in layers 3 and 4 (layer 4 is below layer 3). After the infill well completion, field observations reveal a sharp increase in water production of the parent well, a decline in the oil production rate from the parent well, and a significant difference in production performance emerged between newly drilled infill wells. Two infill wells that are closest to the parent well but landed in layer 4 yield much lower oil and gas production compared to other infill wells completed in the same layer. In this paper, field data were analyzed to investigate the root causes of production loss from the parent well and lower-than-expected production rate from these two infill wells for this staggered well layout. Landing depth, well trajectories, operation conditions, and completion designs were compared for all infill wells and we found out that none of these can cause the significant production difference among the infill wells. Hence, the most accepted hypothesis is that the stress change induced by parent well depletion negatively affects the effectiveness of infill well completion.
A reservoir geomechanical simulation was developed to evaluate the pressure and stress change induced by the parent well depletion of two years. The reservoir model was prepared with available geological and well logging data. History matching for the parent well production was performed to determine the region of pressure sink. Based on geomechanical well logging test data, a 3D real field scale geomechanical model was built to calculate the stress redistribution induced by pressure sink. Results show that non-uniform fracture length with extreme long fractures in the parent well can generate non-uniform depletion area and pressure sink. Fractures generated in infill wells tend to propagate toward to depletion region and hit the existing long fractures in the parent well. Therefore, frac-hits still can be induced even with 1000 ft large well spacing. Stress change was also investigated vertically in different layers, especially layer 4. We found that stresses in the upper section of layer 4 have been decreased by parent well depletion and stresses in the lower section of layer 4 have been increased, which will favor fracture growing to the upper section and layer 3 due to lower stresses. Therefore, the staggered well layout may not necessarily be an effective strategy to mitigate interwell interference.
This study helps understand the poor performance of infill wells and provides some suggestions for future well development, such as applying extreme limit entry or diverter to generate more uniform fracture growth to avoid irregular depletion region, placing the parent well in the lower layer to mitigate well interference between staggered parent and infill wells for development of multiple pay layers.
This study uses a machine learning framework to systematically analyze field production and completion data to understand the impact of frac-hits on parent and child wells and predict well spacing and completions design. Frac hits are one of the most pressing reservoir management issue that can enhance or compromise production over either the short-term or have sustained impacts over longer times. The extent of the impact is dictated by a complex interplay of petrophysical properties (high-perm streaks, mineralogy, etc.), geomechanical properties (near-field and far-field stresses, brittleness, etc.), completion parameters (stage length, cluster spacing, pumping rate, fluid and proppant amount, etc.) and development decisions (well spacing, well scheduling, etc.). As a result, the impact of frac-hits is not straightforward and difficult to predict.
The study uses data from the Meramec, Woodford and Wolfcamp formations. We develop an automated machine-learning based frac-hit detection algorithm that also quantifies the impact on the parent and child wells using matched decline curve models. We analyze about 500 parent and over 1100 child wells in the three formations. Our results show that the key factors governing the extent of the impact are the extent of depletion and producing oil rate of the parent well before frac hit, completion design parameters (fluid and proppant amount) and well spacing. Our machine learning analysis generates regression models to predict the impact of frac hits. These regression models are coupled with economic analysis to determine optimum spacing for any given completion design or optimum completion design for any given spacing.
The parent wells in all three formations had both positive and negative impact of the frac hits. Around 60–67% parent wells were negatively impacted while 33–40% wells were positively impacted. For the child wells, 71–85% wells were negatively impacted and 15–29% of the wells were positively impacted. Combining the impact on parent and child wells, the impact is dominated by the child wells as 69 to 82% of the parent-child pairs were negatively impacted and only 18–31% of the pairs were positively impacted. Considering percent loss in cumulative oil volumes in the next 5-years, in the Meramec, parent wells on average show a 16% reduction while child wells show a 39% reduction due to frac hits. The corresponding numbers for the Woodford formation are 19% and 37% and Wolfcamp formation are 20% and 22%, respectively. This translates to a parent well losing on average 40–50 thousand bbls in next five years and a child well losing on average 130–150 thousand bbls in the same period.
This study systematically analyzes available data to understand the impact of frac hits and formulates a machine learning-based well spacing-well completions matrix workflow that can easily be extended to other formations by integrating commonly available production and completions data.
Abivin, Patrice (Schlumberger) | Vidma, Konstantin (Schlumberger) | Xu, Tao (Schlumberger) | Boumessouer, Wissam (Schlumberger) | Bailhy, Jason (Schlumberger) | Ejofodomi, Efe (Schlumberger) | Sharma, Amit (Schlumberger) | Menasria, Samir (Schlumberger) | Makarychev-Mikhailov, Sergey (Schlumberger)
Infill drilling consists of adding horizontal wells between existing wells to optimize drainage in high-value acreage. New wells are sometimes drilled as close as 250 ft to producing or depleted wells. Fracturing the new wells creates a high risk of fracture-driven interactions (FDI). This paper describes a methodology to characterize well interference on production in unconventional basins and the impact of mitigation technologies.
Data mining, correlations, and statistical tools were developed to extract and analyze a large commercial production database covering major plays in the US. First, cloud-based algorithms were developed to identify and characterize infill wells based on coordinates, well deviations, production dates, and an adjustable radius of interference. Second, monitoring algorithms automatically captured and analyzed abrupt changes in normalized production of infill wells and neighboring wells at the time of infill well stimulation. Finally, the effect on production of both parent and child is immediately displayed on a user-friendly user interface for further visualization and interpretation.
The method was successfully applied to areas experiencing high infill drilling in major basins such as the Williston basin. Results show that production data correlate with historical changes in infill drilling density and fracturing job volumes (proppant and fluid). The production of child wells is then compared to that of their closest parent, which shows some decline as a function of the distance between wells. The systematic workflow also identifies if the basin is prone to positive fracture hits or if there is a significant decrease in the production of existing (parent) wells. The use and impact of diversion technologies as a well interference mitigation method is also studied.
These results give important insights into the effect of field development strategies on well interference and enable recommendations related to well spacing, fracturing designs, and use of fracture geometry control technologies to optimize future well and field development. Production data analysis clearly shows a beneficial impact of both near-wellbore and far-field diversion technologies on production.
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.
Xu, Yifei (The University of Texas) | Yu, Wei (The University of Texas) | Li, Ningning (Black Hills Exploration & Production) | Lolon, Ely (Liberty Oilfield Services) | Sepehrnoori, Kamy (The University of Texas)
Abstract Numerical simulation is a practical approach to optimize the development plan of unconventional reservoirs. Pressure interference between wells makes it necessary to simulate multiple wells with complex fractures in a single reservoir model. Accurate and convenient modeling of fractures is a crucial requirement for such simulations. In this study, an Embedded Discrete Fracture Model (EDFM) is used to model a gas reservoir in the Mancos Shale of the Piceance Basin, USA. First, a history matching study is conducted to match the calculated well bottom-hole pressure of six horizontal wells by varying fracture properties while honoring other diagnostic test results. The interference between wells, through connecting hydraulic fractures, is considered to obtain a good match. The high computational efficiency of our approach is illustrated through a comparison with the Local Grid Refinement (LGR) model. Subsequently, the advantages of the EDFM approach are fully exploited through sensitivity studies. We investigated the impact of hydraulic fracture half-length, natural fracture density, and natural fracture conductivity on long-term gas production. The influence of natural fractures on well interference is also studied. We found that the EDFM method maintains a high computational efficiency with a large number of fractures, and the simulation CPU time increases linearly with the number of fracture gridblocks. This study demonstrates the application of the EDFM method to a field-scale study with multiple wells in a specific shale reservoir. The results show that the EDFM is a practical method to be used in conjunction with history matching and sensitivity studies with complex fractures due to its high computational efficiency and flexibility to model complex fractures. Introduction With the fast development of unconventional oil and gas reservoirs, a large number of horizontal wells have been drilled. At the same time, the issue of well interference becomes more critical (Lawal et al. 2013; King and Valencia 2016). In field operation, the shut-in and build-up pressure test is often utilized to identify the degree of inter-well communication vertically and areally (Portis et al. 2013; Sardinha et al. 2014; Sani et al. 2015; Scott et al. 2015; Liang et al. 2017). Well interference might occur through the matrix, connecting hydraulic fractures, natural fractures, or a combination of these mechanisms (Yu et al. 2017). The occurrence of well interference due to the last two mentioned mechanisms may adversely affect well productivity in multi-well pads (Yaich et al. 2014; Malpani et al. 2015; Liang et al. 2017; Tang et al. 2017). Also, it plays a vital role in the optimization of well spacing.