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.

This work is a simulation of sand production mechanics using an elasto-plastic ftnite element formulation. An open vertical well was considered in order to simulate the performance of near-wellbore unconsolidated sand during hydrocarbon production.In the simulation procedure, the assigned values of the initial stress fteld around the wellbore were taken from previous sand arching experiments conducted at the Colorado School of Mines on a similar well conftguration using 20/40 frac sand. The mechanical rock properties used in simulation were also taken from previous experimental work. The model did not require fluid properties such as density and viscosity be determined. The values of cohesion and pressure drop across the open well sandface were varied in the simulation of hydrocarbon production through the considered wellbore.Through multiple simulations, the effect of these variations on the stability of the sand surrounding the wellbore was observed. In this study, stability is considered to be elastic behavior and plastic behavior is assumed to indicate failure.It is concluded that sand production from a well can be modeled using the elasto-plastic ftnite element formulation. The stability of the sand around the wellbore depends on the pressure-drop across the sand face and the cohesion of the sand grains. The model presented can provide information on whether a producing zone will exhibit sand production problems.

Discussion/Reply The authors of paper SPE 150515, titled “Downhole Steam Generation Pushes Recovery Beyond Conventional Limits,” (JPT June 2012), are commended for bringing the topic to the forefront. However, the article is a little too optimistic and may lead the reader to wrong conclusions. With all the perceived promise over the decades, this technology is still in the conceptual stage, especially in the reservoir EOR mechanisms envisioned by the authors and in the basic operational design. Playing devil’s advocate, here is a short list of possible “cons” to accompany the article’s list of “pros” for the process: Conventional steam-enhanced oil recovery (EOR) depends on the latent fraction of heat contained in quality steam. Sensible heat in water has proven to be of little help in the recovery of incremental oil. For the typical project that operates at <<100 psig, the latent fraction of heat in the steam is in the range of 80%. For steam at the proposed >2,000 psig the latent fraction falls to about 35%. If applicable, this changes the mechanism displacing oil from the reservoir; it is no longer a conventional steamflood. In general, the deeper the reservoir, the hotter the formation. The hotter the formation, the lower the oil viscosity and less need for steam. In California, the typical reservoir at 2,000 ft is 130°F and at 5,500 ft, it is 200°F. Granted, other parts of the world have lower temperatures at depth (e.g., the Alberta fields are about 130°F at 5,000 ft); however, this is a limiting factor for deep thermal processes. Deeper reservoirs tend to be tighter sands and the downhole steam generation (DHSG) demands that all the fluid sent downhole is injected. This will require either reduction of injection, which has implications for the reservoir process, or injecting at fracture pressures, which has its own set of problems. There are few better filters in the oil field than a wellbore sand face. Couple this with the inevitable particulate generation in DHSG, and well plugging problems are likely to occur.

What has been regarded as unconventional by many has been conventional for the few that have developed viable, and in many cases, very profitable projects that succeeded in extending the envelope of recoverable hydrocarbons. The range of recoverable hydrocarbons is bounded by physical constraints like reservoir properties, unfavorable hydrocarbon characteristics, or in many cases, hydrocarbons still captured in the formations. The methods of extraction that have been devised to address such challenges frequently combine applications of enhanced recovery, intensive stimulation, or advanced drilling. The distinction between conventional and unconventional can be reasoned not in the context of new versus old, more or less prolific accumulation attributes, or the method of extraction, but in the approach that is followed. A conventional development approach would cover the entire field with increasing intensity; an unconventional approach would pursue intensive development sequentially from the more prolific to the less prolific parts of the field. Although it is easy to see the technical benefits of unconventional methods, their integration with economic and market parameters is necessary in order to provide a successful implementation. The purpose of this paper is to present a set of features that are found as common denominators in successful developments of such resources. These common features could be viewed as unconventional resource development principals that outline the areas where particular attention is required for their ultimate success. In that context, the influence of market pricing, cost structure and resource evaluation are examined and offer a platform for project implementation that can be viewed as a "road map". The basic premise in this reasoning is that while it is not possible to develop a universal technological solution, careful adaptation of technology to the subsurface and operational realities allow synergies to develop that improve the chance of economic success. The recognition of key risks in unconventional resource development is instrumental in addressing the reasoning in resource classification. In that sense, while geological risks are often viewed as key in conventional resources, unconventional resources carry more risks as more complex extraction methods are implemented. Once development commences, it could maintain a positive outlook with changing market conditions as the associated costs relate to some extent to fuel costs that are in turn dependent on the product prices. The long development cycle of such projects lasting more than 20 years reduces the exposure to fluctuating prices as long as a reasonable average trend is considered at the onset. With evolving methods of extraction, the oil industry is shifting focus from exploration into intensive exploitation. Inevitably, the terms unconventional resources and a non conventional approach present a new direction for realizing the fuel sources of the future.