Summary Performance prediction of wells producing from tight (microdarcy) formations is a daunting task. Complexities of geology (the presence/absence of naturally occurring fractures and contribution from different lithological layers), completion and fracture geometry complexities (multiple transverse or longitudinal fractures in long horizontal boreholes), and two-phase flow are impediments to simple performance forecasting. We demonstrate the use of various analytical and numerical tools to learn about both short- and long-term reservoir behaviours. These tools include (a) traditional decline-curve analysis (Arps 1945), (b) Valko's stretched-exponential (SE) method (Valko 2009), (c) the Ilk et al. (2008, 2010) power-law exponential (PLE) method, (d) rate-transient-analysis (RTA) and transient-PI analyses to ascertain the stimulated-reservoir volume (SRV), and (e) numerical-simulation studies to gain insights into observed flow regimes. The benefits of collective use of analytical modelling tools in history matching and forecasting both short- and long-term production performance of tight oil reservoirs are demonstrated with the use of real and simulated data. Diagnosing natural fractures, quantifying stimulated-reservoir volume, and assessing reliability of future performance predictions all became feasible by using an ensemble of analytical tools.

Many tight or shale gas wells exhibit a linear flow regime that can last for years. However, production analysis in unconventional oil reservoirs, such as the Bakken, shows that the linear flow regime is not the only dominant flow regime. Field data suggest that the duration of boundary-dominated flow influenced by the stimulated-reservoir volume (SRV) and compound-linear flow generally overshadow the early-time linear flow regime. Depending on the fracture network or SRV patterns, formation linear flow in unconventional oil reservoirs may only last for a few months but contribute about 30% of the total estimated ultimate recovery (EUR). This study develops a procedure for identification of different fracture network patterns and inference of related flow parameters based on analytical methods. The reservoir description so derived is transported to a numerical reservoir-flow simulation model to capture the effects of compaction, multiphase flow behavior, and various flow regimes in an unconventional oil reservoir system. This coupled approach helps illuminate reservoir performance, which allows insights into history matching. In particular, we demonstrate (a) fracture network patterns and flow regime diagnosis through rate-transient analysis; (b) coupled numerical reservoir simulation with analytical modeling results for performance-constrained history matching; (c) sensitivity analysis on the heterogeneity effect, compaction effect, and multiphase flow effects; and (d) field application of the proposed procedure on Bakken wells. This proposed method demonstrates that analytical methods should be used before undertaking a detailed numerical reservoirflow simulation study. This understanding paves the way for much improved reservoir characterization in unconventional oil reservoirs.

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.

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.

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