The learning curve has evolved in the last few years for operators in shale plays. Early wells started with relatively large cluster spacing and small proppant volumes resulting in suboptimal initial completions. Over the years, perforation cluster spacing has declined. Consequently, the number of hydraulic fracturing stages has increased. The total proppant pumped per lateral foot has also increased. The majority of the existing wells were completed with geometrically spaced multiple perforation clusters per stage. Sometimes more than six clusters per stage have been employed. Studies have shown that one-third of these perforation clusters are not productive (Miller et al., 2011). Noncontributing perforation clusters could be due to not initiating hydraulic fractures, insufficient proppant placement, or loss of near-wellbore connection due to over-flushing or severe drawdown. Furthermore, during the development phase, the depletion from parent wells leads to asymmetric hydraulic fracture growth on closely spaced infill wells. Parent wells may also be negatively impacted due to hydraulic fracture interference from new completions. These factors have led to poor hydrocarbon recovery factors, sometimes less than 10% in horizontal shale wells.Recovery factors from existing wells can be improved through restimulation. Candidate selection is a key in achieving economically successful restimulation. Restimulation of appropriate horizontal shale wells resulted in significant production uplifts based on early field results. Designing a fit-for-purpose restimulation treatment is dependent on initial completion, offset well distance, infill plan, and, above all, economics. On top of the design aspect, operationally achieving effective restimulation on long horizontal wells with tens of perforation clusters is a challenging task. Thus real-time monitoring and control is a key for field execution.This work uses an integrated petrophysical, geomechanical, hydraulic fracture, and reservoir modeling workflow and field observations to develop restimulation strategies for improving hydrocarbon recovery. This integrated workflow includes a multistep calibration process to reduce uncertainty. One of the key calibration steps is to model hydraulic fracture growth accounting for local geological heterogeneity and match with observed treatment parameters and microseismic interpretations. Another critical calibration step includes automatic gridding of hydraulic fracture geometry to run numerical reservoir simulation to match realized production results. Reservoir pressure distribution at the end of the production history is used to recalculate stresses for modeling the refracturing scenarios.Multiple practical refracturing scenarios were constructed for addressing near-wellbore connectivity issues and ineffective drainage along the lateral. Creating new surface area in undrained rock and restoring productivity of existing hydraulic fractures resulted in higher recovery. Higher proppant amounts in undrained rock on one well pad or late...

This paper continues the investigation of interwell fracturing interference for an infill drilling scenario synthetic case based on Eagle Ford available public data and explores pressure and stress-sink mitigation strategies applied to the simulation cases developed in the previous publication (SPE 174902). Emphasis is given to refracturing scenarios, given the intrinsic restimulation value for depleted parent wells and the strategic importance due to the current low oil prices. The stress and pressure depletion methodology is expanded in this paper, adding a refracturing scenario before the infill child well is stimulated. Changes in stress magnitudes and azimuths caused by new and reactivated fractures are calculated using a finite element model (FEM). After refracturing the parent well, modeling shows that stress deflection and repressurization of the originally depleted production zone will reduce subsequent fracture hits from infill wells. The first mechanism to reduce fracture hits is the stress realignment, which promotes transverse fracture propagation from the infill well away from the parent well. The second fracture-hit-reduction mechanism is repressurization of depleted zones to hinder fracture propagation in lower-pressure zones. Prevention of fracture hits by active deflection results in an increased stimulated reservoir volume (SRV) for both the parent and child wells. Overall pad level and individual wellbore cumulative production experience a significant increase due to increased SRV. With proper reservoir and geomechanical data, this approach can be applied in a predictive manner to decrease fracture-hit risk and improve overall recovery. This workflow represents the first comprehensive multidisciplinary approach to coupling geomechanical, complex hydraulic fracture models, and multiwell production simulation models aimed towards understanding fracture-hit reduction using refracturing. The workflow presented can be applied to study and design an optimum refracturing job to prevent potentially catastrophic fracture hits during refracturing operations.

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Excess water production can lead to premature operating cost escalation or well abandonment in conventional oil and gas reservoirs. This can also happen in tight and source rock production in cases where hydraulic fractures connect the stimulated well to a water source, especially with low hydrocarbon production rates. Polymer gel technology has been successfully used in controlling water influx with no or minimal damage to hydrocarbon production in conventional naturally fractured or hydraulically fractured reservoirs. However, there has been no public description of polymer gels tailored for shutting off water flow from fractures with the very narrow apertures expected in tight and source rock reservoirs. Established water shutoff polymer gels like those based on hydrolyzed polyacrylamide (HPAM) crosslinked with chromium(III) acetate will exhibit high extrusion pressure while penetrating the expected narrow aperture fractures present in source rock and tight gas reservoirs. This is likely to cause significant limitations to their application in unconventional resources, thus giving rise to this study on development of a polymer gel system that can be used for shutting off water flow from narrow aperture fractures. In addition to improved placement rheology, an improved gel system should ideally be composed of components that are less of an environmental concern than metal ion-crosslinked systems. This report focuses on developing a low viscosity, environmentally benign polymer gel system based on high molecular weight (HPAM), as the polymer component and a commercial grade polyamine containing polyethyleneimine (PEI) as an organic crosslinker. Gelant and gel samples of different concentration ratios of polymer and crosslinker were prepared, subjected to rheological measurements and classified using a semi-quantitative gel strength coding to find optimum concentration ratios that gave good gels. Results indicate that the HPAM/PEI system can provide a gelant with lower initial viscosity, higher final gel strength and potential greater stability at higher temperatures than current metal ion crosslinked gel systems.

As the oil & gas industry enters into next phase of unconventional reservoir development, many new in-fill wells will be drilled in various shale oil and gas plays in North America. A detailed evaluation to devise an engineered approach for stimulating and completing these wells is critical to maximizing productivity. Challenging economics that prevail today have made it even more vital to perform such a study. This paper focuses on identifying optimum stimulation treatment design and completions strategy for the in-fill well. This work is a companion work to a paper presented by Gakhar et al. at the 2016 SPE/ CSUR Unconventional Resources Technology Conference (URTeC 2431182) on developing an engineered approach for multi-well pad development in Eagle Ford shale. Together these papers, serve as a comprehensive guide for multi-well pad performance optimization in unconventional reservoirs like the Eagle Ford Shale. An ‘advanced integrated modeling workflow’ is used to execute the complex study. The workflow involves building a 3D structural geologic model based on a vertical openhole pilot well log in Eagle Ford shale reservoir. A discrete fracture network (DFN) is built from 3D seismic data interpretation. Hydraulic fracture treatment pumped on a parent well is simulated using ‘unconventional fracture model’ (UFM). The UFM simulates complex fractures, while honoring the interaction between hydraulic fractures and natural fractures. A dynamic grid with unstructured cells is then created. Hydrocarbon production from the parent well is simulated for a period of 400 days. A geomechanical finite element model (FEM) based simulator that is fully coupled with a 3D numerical reservoir simulator is then used to calculate spatial and temporal changes in in-situ stresses. Dynamic reservoir properties in the 3D model are then updated and the child well, which is drilled 600 ft away from the parent well, is built into the model. The UFM is used to simulate an array of stimulation treatment designs and compare alternate completions strategies for the child well. The reservoir simulator is then used to compare production performance of the alternate strategies. Note that in this paper, the terms "in-fill well" and "child well" are used interchangeably. Extensive evaluation is carried out using the advanced integrated modeling workflow to achieve three key objectives. The first key objective is to determine an appropriate hydraulic fracturing treatment design for an in-fill well. Four hydraulic fracture treatment designs based on slickwater, delayed borate crosslinked gels, hybrid fluid treatments, and fiber based channel fracturing fluids for the in-fill well are compared. It has been found that under reservoir conditions specific to this study, the child well produces 22% more oil, if stimulated using the fiber based channel fracturing fluid than, if fractured using the slickwater. The second key objective is to compare the impact of refracturing and recharging the parent well prior to fracturing the child well. For the study well, refracturing increases oil production from the multi-well pad by 11% over the scenario, in which the parent well is recharged by injecting 43,200 bbl of water. The third objective of this study pertains to comparing the traditional plug-and-perf completions design with an alternate based on coupling plug-and-perf with a novel "sequenced fracturing" technique with a degradable fiber based fluid diversion blend for the child well. It has been found that by using the latest sequenced fracturing technique oil production from the multi-well pad can be increased by 14% over a scenario in which the child well is completed using traditional plug-and-perf design, despite pumping fewer stages on the well. The novel completion technique also greatly improves the efficiency of operation and provides significant savings on completions cost.