The ultra-tight nature of shale reservoirs has resulted in the maximization of the stimulated area within a section to increase production. As a result, some wells appear to interfere with one another during stimulation. This interference has been known to typically reduce (occasionally enhance) the performance of wells currently in production by altering the existing fracture network, or near well permeability, via the presence of multiple phases. This process is known as a "frac hit". Three different mechanisms are thought to be possible causes of the well-to-well interaction: depleted zones, changing stress fields, and high permeability lithofacies. Numerical and analytical modeling will be used to explore the impact of dynamic completion systems. In this paper, modeling techniques are demonstrated to allow operators the ability to use rate transient analysis (RTA) tools to model frac hits. Examples from the Haynesville and Marcellus are examined. The examples were categorized based on the dominant flow regime, transient linear flow or depletion flow, and then the proper technique was employed. Unique characteristics with respect to reservoir phenomenon, i.e. depleted zone, changing stress fields, or high permeability lithofacies are also discussed. These modeling procedures will enable operators to bound forecasts for wells that have been altered by the stimulation of a neighboring well. This means operators can still provide risked reserves based on numerical modeling and RTA software for wells that have endured a hit. In addition, the techniques will be applied to re-fracturing. Now operators have the ability to forecast re-fractured wells quantifying the NPV of a re-fracture. Lastly, the knowledge gained from the in-depth examination of the phenomenon and drive mechanisms behind the frac hit enables the avoidance of future occurrences of well damage.
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Transient linear flow diagnostic plots in shale gas wells often exhibit a positive y-intercept and may mask the early transient linear flow regimes because of non-reservoir pressure drops. Increased completion resistance reduces the peak production rate early in the life of a well impacting NPV. The shale gas industry is very early in the research required to distinguish the individual contributions of completion resistance, e.g. poor fracture conductivity, near-perforation damage or choke skin, and fracture face damage skin. Many of these phenomena can be diagnosed in production wells using unique shape(s) from various diagnostic plots allowing for analysis of completion effectiveness.Mechanistic reservoir simulations were used to generate diagnostic plot signatures for low conductivity fractures, choke skin, and near fracture face damage. Subsequently, the corresponding signatures were compared with a large database of shale gas wells in numerous plays across North America to aid in the fingerprinting of these non-reservoir pressure losses. Only low fracture conductivity, not choke skin, can have a quarter slope. Near fracture face damage results in two distinguishable linear trends, one of the damaged region and the other for the matrix.Completion skin diagnosis is a way of evaluating fracture efficiency by identifying the root causes of the non-reservoir pressure losses so as to mitigate them in the future. The following presents a catalogue of signatures that enables greater diagnostic capabilities to classify non-reservoir pressure losses. The study is the first comprehensive cause-by-cause look at completion damages with an emphasis on identification and diagnosis in shale gas wells.
Making optimal well spacing decisions in unconventional plays is critical for commercial viability. Given the huge areal extent of these plays and low permeability, a large number of wells are needed to optimally extract the resource. The well spacing decision has to incorporate changes in geology/reservoir characteristics, completion methodology, presence of offset wells, and economic constraints. This work shows the impact of changes in reservoir properties such as permeability, completion properties as fracture spacing and completion footprint or the areal configuration of the stimulated reservoir volume (SRV) in determining optimal well spacing. As additional development or infill wells are drilled in a section, the possibility of SRV overlap increases. When the stage/cluster placement is not staggered between the neighboring wells, the created fractures may intersect resulting in SRV destruction i.e. the fracture area accessible to the neighboring wells is less than the total fracture area created in absence of SRV overlap. With staggered placement of stages, the created fractures are at an offset and the SRV's overlap without the fractures intersecting. This results in accelerated depletion of the region between the wells by reducing the rock volume each hydraulic fracture has to drain. Thus, the neighboring wells rob some late life production potential by draining the reservoir within the study well drainage volume. The impact of the percentage of fracture overlap, fracture spacing, and reservoir permeability on overall recovery and economic value is evaluated using synthetic models. For the scenario of SRV destruction, the NPV decreased with increasing SRV overlap. With staggered placement of fractures, there is a minor loss in NPV for less than 50% SRV overlap under the economic constraints considered. Higher than 50% overlaps may be detrimental depending on permeability and fracture spacing. Changes in cost/economic constraints also impact optimal well spacing. The presented results will assist operators in planning closer well spacing by optimizing capital expenditures and hydrocarbon recovery.
Early in the development of a shale gas resource, optimal well spacing remains unknown as wells are sparsely drilled to hold leases by production. Developing the acreage requires operators to select locations, specify drilling plans, and design completions for multi-stage horizontal wells to maximize the operating metrics as defined by the company. This paper builds on our earlier work which presented sensitivity analysis for optimal well spacing with respect to permeability, fracture spacing and half-length under the assumption of uniform and symmetric completion configurations. The well spacing sensitivity to heterogeneity in completion configurations (i.e., non-uniform fracture half-length and asymmetric fracture spacing) are presented in this paper using forward and stochastic modeling approaches. Forward modeling results show a strong bias towards the longest repeated fracture half-length in determining the optimal well spacing. Higher reservoir permeability abates the impact of fracture heterogeneity. Fracture modeling, constrained by production logs, temperature logs, and/or microseismic, can be used to aid in the identification of the longest repeated half-length. This paper demonstrates the challenges associated with stochastic modeling of well performance. Examples from synthetic and field case studies are presented to illustrate uncertainty in reservoir and completion parameter determination. The spacing optimization workflow used captures this uncertain range to effectively determine the impact on recovery factor and Net Present Value (NPV). The importance of the quantity of production history needed to determine optimal well spacing is also presented. Results reveal that with increasing heterogeneity longer production history is required for reliable determination of optimal well spacing. Finally, a field case study applying a production log and fracture modeling is examined to identify the impact of non-uniform fracture spacing and fracture half-length heterogeneity. These conclusions, via the application of deterministic and stochastic modeling on production from field cases and synthetic wells, will aid operators in answering the multi-billion dollar question: how many wells should be placed in a given area? The workflow described in this paper not only can answer this question but also help us to understand how to maximize economic return and the ultimate gas recovery.
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