As unconventional reservoir development progresses, tighter well spacing improves recovery at the risk of an increase in well-to-well hydraulic fracture interference. During stimulation, fractures dilate along preferential planes of weakness that extend into an existing offset well"s producing volume. This can result in water penetration and stress reorientation. The objective is to show how to analyze pressure and rate responses from fracture interference data to impact operations, adjust field development, and identify future upside potential. The methodology starts with identifying whether fracture interference during hydraulic stimulation is beneficial (positive frac interference) or detrimental (negative frac interference) to offset producers. The impact of hydraulic fracture interference is then quantified by performing multi-phase production data analysis. The system alteration is measured by calculating the changes in well productivity and estimating incremental loss or gained volume for the pre-existing producer due to a frac interference event. This information is utilized to build full field development scenarios by modifying the drilling and completion schedule and well spacing so that the most profitable strategy is obtained. We identify that the drivers of fracture interference consists of (1) areal variation of reservoir properties, (2) pressure depletion due to the initial generation of wells, and (3) distance between producer and infill wells. The first development scenario evaluates the impact of deferred or gained production due to a frac interference event for different geological areas. The following case high-grades acreage based on areal variation of reservoir properties by delaying the development of deferred or lost production areas due to a negative frac interference event. The last scenario captures the opportunity for a tighter well spacing in areas with positive frac interference event. Based on the learnings derived from each scenario, the most profitable development strategy is presented for a typical unconventional reservoir. Furthermore, a new re-stimulation selection criteria is proposed to capitalize on the benefits of fracture interference. Conclusions are drawn from analyzing multiple multi-stage horizontal wells from the South Texas Eagle Ford and North Dakota and Montana Bakken reservoirs. In this paper, our results extend beyond retrospective studies by quantifying reservoir changes using a multi-phase approach and utilizing these results to impact development. Prior studies limited the classification of fracture interference as negative consequences of development. However, our investigation indicates that with improved understanding, we relate the impact of these events to development scheduling, confirmation of well spacing, and high-grading acreage to mitigate risks and harness the benefits of fracture interference as a mechanism of passive re-stimulation.

Vertical and horizontal inter-well communication in unconventional reservoirs remains a major uncertainty. This paper presents the results of geochemical analyses performed on several wells in the Bakken and Three Forks unconventional oil reservoirs. Geochemical analyses performed on oil extracted from core, oil sampled while drilling, and oil produced after stimulation indicate that the geochemical signatures of the Bakken and Three Forks Formations are different and unique to its respective stratigraphic units. Using unique geochemical signatures, this study developed a procedure for identifying the production of mixed oils and the relative contribution from each contributing startigraphic units. To further investigate vertical communication a detailed geologic model was constructed using core and outcrop data. The model was simulated and history matched to estimate contribution from adjacent layers. Various scenarios were simulated to understand the probability of communication. Analyses suggest that vertically adjacent layers contribute to production as predicted by the reservoir model and measured by the geochemical signature of the oil. This paper demonstrates (a) contribution from vertically adjacent formations can be significant, (b) geochemistry may be utilized to quantify vertical drainage, and (c) quantification of contribution from offset layers helped to constrain a reservoir simulation history match. Results from this study have facilitated the assessment of the degree of vertical communication across various flow units, which is the key to an efficient reservoir development.

Because of the need to quantify hydraulic fracture effectiveness, injection of chemical tracers in unconventional reservoirs has increased in popularity. Typical tracers are oil or water-soluble chemicals, which are injected into the formation along with the fracturing fluids. The tracers should invade a significant portion of the stimulated rock volume (SRV). The tracer backflow could shed light on the effectiveness of the hydraulic fracturing process and the SRV size. Emulsion tracers and controlled-release tracers are the two tracer types currently used in the industry. This paper presents application, implementation and analysis of tracer flowback in unconventional reservoirs to determine individual stage flow patterns. The tracer flowback response is also of value in assessing the probable effectiveness of various enhanced oil recovery protocols in unconventional reservoirs. We present two field examples from Bakken and Eagle Ford formations to demonstrate the value of information obtained from the interpretation and analyses of tracer flowback.

Innovative completion techniques for unconventional oil and gas reservoirs have been developed at a rapid pace. Deciphering the flow regime characteristics of the pressure-time signature of flowing wells associated with these new completion techniques is critical for evaluating well performance and ultimate hydrocarbon recovery. In this paper we present the flow regimes observed in the plots of field production data for several of these new completion techniques. We also present the simulated model results for these completions.Several rate-transient analyses (RTA) for different well completion techniques from 1990 to 2010 were analyzed to determine how different completion techniques would affect flow regime characteristics-specifically, the linear flow period. Reservoir simulation results for homogenous and heterogeneous reservoirs showed that hydraulic fracture and natural fracture properties are the most crucial variables affecting the linear flow period. A statistical analysis of the Arp's decline b-factor was also used to show the impact of increased reservoir connectivity with advanced completion techniques and stimulation. This paper demonstrates that (a) completion techniques can influence the linear flow period and the length of the transition period before boundary-dominated flow prevails, and (b) different completion techniques lead to different flow regime diagnostics and different Arp's flow rate exponent b.

In unconventional reservoirs, the well life cycle includes drilling, completion, flowback, and production. The analysis of the fracturing pressure, flowback, and production data provides an early estimate of the stimulated rock volume (SRV) and reservoir flow capacity. In this paper, we present a methodology for using the average treatment pressure and hourly flowback data to characterize reservoir connectivity as an early indicator for long-term productivity. We will also show that performing flow regime analysis during the flowback period provides a greater understanding of the initial fracture conductivity (via bilinear flow) and reservoir connectivity (via linear flow). This early time analysis also sheds light on sweet spots (or geologically favorable areas) and effectiveness of the completion practices for business decisions. In this paper, we have modified the well-known single-phase diffusivity equation to include simultaneous flow of oil, water, and gas in the reservoir. Furthermore, we used fracture treatment pressure, flowback and production data from several Eagle Ford and Bakken wells to demonstrate the value of completion and flowback data and their relation to the long-term performance of wells.

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Completion techniques in the unconventional reservoirs are continuously evolving. Yet a method to evaluate completion efficiency is still lacking. This study proposes a method employing the conventional Modified Heterogeneity Index (MHI) to evaluate completion competency and reservoir quality.Hydraulic fracturing is designed to maximize reservoir contact. The hydraulic fractures may grow beyond the target or landed geologic zones due to an improperly planned or executed stimulation. This paper first shows the vertical water saturation profile and the observed correlation between water saturation and water cut. These results help to understand reservoir communication between multiple stacked reservoirs and hence help to quantify completion effectiveness.Modified Heterogeneity Index is traditionally used in conventional reservoirs to monitor water breakthrough and normalize producer well performance in a water-flood field. This paper proposes a method to exploit the HI analyses and understand the correlation between water production and well productivity. The analysis is also tied to completion techniques to understand completion efficiency and its relation to reservoir properties. This paper demonstrates that (a) correlation between water saturation, water cuts and production indicates that water saturation is one of the key reservoir properties governing production, (b) modified Heterogeneity Index can be utilized to scrutinize the completion effectiveness and reservoir quality, (c) the new method can be used pro-actively to screen for refrac candidates and to forecast or estimate the possibility of pressure communication between offset wells.