A comprehensive site study carried out in an Upper Devonian shale gas reservoir at a site in southern West Virginia provided data to test a geomechanical model for stimulation of the Huron formation. Using a model in which natural fractures provide the primary conduits for production and are the major target for stimulation, and in which stimulation triggers shear slip on those pre-existing fractures, we were able to predict the shape of the reservoir volume stimulated by injection of high-quality foam and to match injection flow rates and pressures using a dual porosity dual permeability finite-difference flow simulator with anisotropic, pressure-sensitive reservoir properties. The resulting calibrated model matched both the relative contribution of the individual stages measured by production logging and the early-life well production. This suggests that similar models may in the future provide earlier and better production predictions, guidance for completion and stimulation design, and recommendations to minimize production decline and maximize well value.

There is worldwide interest in the development of shale plays: North America has attracted noteworthy investments, while other continents are ready to follow that example. Besides the increasing commercial significance of shale plays, traditional volumetric and material balance approaches that are used for petroleum asset evaluation fail to address the special attributes of such formations, or they cannot rely on measurable and practical input. The current practice is to statistically analyze historical records in developed areas and to apply the derived type curves in new areas by assuming performance similarity. Provided that there is a sufficient statistical record base, the assumption of similarity is challenged by the multitude of parameters influencing performance. These tend to differ, introducing considerable uncertainties into predictions. As the advanced drilling and fracture stimulation techniques were introduced in the last decade, historical records support only the early production history, while late performance is extrapolated without many reference points to match. This paper investigates the applicability of traditional and non-traditional empirical, analytical and numerical methods that are used to predict shale well performance. The goal is to rationalize the link between natural/stimulated rock description with oil and gas recovery mechanisms in a way that is practical at various scales of resolution and covers early and late times. The authors have investigated the application of performance analysis techniques that are fit for macroscopic view and numerical methods that describe multiple mechanisms at a much higher level of resolution. Special features such as flow through fracture networks, gas desorption and geomechanical effects are incorporated in numerical simulation in a way that relates to the measurable petrophysical and geophysical input. Although the application of such macro-and micro-analysis has been examined within only a few case studies, it is suggested that future work would test and improve the application of these shale engineering principals. In retrospect, this study offers an understanding of mechanisms and limitations that can be used for optimization, or for the scaling-up results from a certain area to other areas that differ in natural attributes and may also adopt different design and operational practices.The simulation exercise reported in this paper represents an idealized situation and it should not be inferred that this can be used to indicate recovery from any specific shale reservoir or well, which would require additional study and appropriate incorporation of practical data that were not available to the authors in the public domain.

Abstract" comprehensive geomechanical study was carried out to optimize stimulation for a fractured tight gas reservoir in the northwest Tarim "asin. Conventional gel fracturing and acidizing operations carried out in the field previously failed to yield the expected productivity. The objective of this study was to assess the effectiveness of slickwater or low-viscosity stimulation of natural fractures by shear slippage, creating a conductive, complex fracture network. This type of stimulation is proven to successfully exploit shale gas resources in many fields in the United States." field-scale geomechanical model was built using core, well log, drilling data and experiences characterizing the in-situ stress, pore pressure and rock mechanical properties in both overburden and reservoir sections. "orehole image data collected in three offset wells were used to characterize the in-situ natural fracture system in the reservoir. The pressure required to stimulate the natural fracture systems by shear slippage in the current stress field was predicted. The injection of low-viscosity slickwater was simulated and the resulting shape of the stimulated reservoir volume was predicted using a dual-porosity, dual-permeability finite-difference flow simulator with anisotropic, pressure-sensitive reservoir properties. " hydraulic fracturing design and evaluation simulator was used to model the geometry and conductivity of the principal hydraulic fracture filled with proppant. Fracture growth in the presence of the lithology-based stress contrast and rock properties was computed, taking into account leakage of the injected fluid into the stimulated reservoir volume

Steam or CO 2 injection methods account for most of the oil recovered worldwide with Enhanced Oil Recovery (EOR) methods. Currently heavy oil production is less than 7% of the world's oil production; this percentage is not expected to increase dramatically without significant changes in reservoir management. Steam and CO 2 have been used successfully since early 1960s --steam in viscous heavy oils and CO 2 mostly in pressurized light oil fields but also in some heavy oil fields. What limits a wider application is depth and high pressure for steam and CO 2 availability for the relatively large inventory of light oil fields that exist worldwide. Although there is some overlap in fields that could benefit from either application, there are not many recorded attempts to implement both methods simultaneously. Air injection, although it was tried first as an EOR method, has not been widely implemented as in-situ combustion is difficult to control in shallow reservoirs and especially without water coinjection.The paper describes the benefits that result from operation of a downhole steam generation (DHSG) which combines thermal and nitrogen or CO 2 EOR. In addition, by controlling the ratios of steam, excess CO 2 and excess O 2 (where applicable) it is possible to use in-situ oxidation in a controlled manner and accelerate production of oil. Moreover, the CO 2 that is generated by in situ can be used elsewhere. The paper includes discussion of conceptual reservoir simulation and economic studies that demonstrate the applicability of DHSG in deeper warm-climate conventional heavy oil fields, as well as challenging arctic environments.Advances from the aerospace industry that enabled this DHSG system, the surface processing design, and well placement strategies are also discussed in this article. They provide an overview of the entire recovery system and present an opportunity to develop both virgin resources and oil fields that were prolific in primary and secondary operations and are rightfully candidates for EOR.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractJones 1 previously developed smooth, non-linear equations for fitting permeability, PV, or porosity data at multiple net hydrostatic confining stresses. The present paper supplements the original by illustrating steps required to convert these measurements into curves for uniaxial strain conditions. The concepts of specific pore volume and specific bulk volume are introduced. These dimensionless values are independent of sample size, and are more useful than pore volume or bulk volume when comparing samples. The latter is useful for subsidence calculations.An averaging technique for the reduction of normalized PV, porosity, or permeability with increasing net stress is also demonstrated for samples from a particular lithology. Samples that do not fit the general trend are easily identified, and can be excluded from averaging if desired. Studies in California reservoirs suggest that stress-related permeability reduction correlates with corresponding reduction in porosity better than permeability correlates with porosity.