Investigating the Expected Long-Term Production Performance of Shale Reservoirs

Abstract

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.

Effect of Dynamic Imbibition on the Development of Ultralow Permeability Reservoir

“…The experimental results show that the recovery of fractured core (2)(3)(4)(5)(6)(7)(8)(9)(10)(11)(12) does not see an obvious increase after two rounds of imbibition processes, while there is still a small amount of oil extracted after the third time of imbibition for nonfractured core (2-2), e.g., a recordable increase in recovery. However, in regard to the increment of imbibition recovery, the nonfractured core is still not as high as that of the fractured core, which reveals the fact that the fractures in the fractured core can not only increase the recovery of imbibition but also reinforce the efficiency of imbibition.…”

“…The resultant multidirection water breakthrough makes water injection ineffective, and the pressure system is difficult to establish. The development effect is, therefore, not desirable with the oil recovery normally below 15% [5][6][7][8][9][10].…”

Study on Effect of Perforation Orientation on Hydraulic Fracturing of Shale

“…Large-scale hydraulic fracturing technology is the core technology to realize the development of unconventional oil and gas resources. Foreign fracturing technology mainly includes [1][2][3][4] the following: nitrogen foam fracturing technology, the technology first began in January 1968, in the United States and Canada on the extensive use of foam fracturing technology, and foam fracturing is particularly suitable for low pressure and low permeability water sensitive formation [5]; water fracturing technology, which uses water to add appropriate drag reduction agent as fracturing fluid, can save 30% of the cost without reducing production and has achieved good application results in the transformation of low permeability reservoirs [6]; and synchronous fracturing technology is the latest fracturing technology which has been successfully applied in the development of Barnett shale gas in Vosburg Basin in recent years. It is the fracturing of two wells (or more than two wells) at the same time [7].…”

The Role of Drive Mechanisms in Redesigning Development Practices in a Fractured Tight Oil Carbonate Resource

“…Typically, 4 -6 wells per section are common based on the assumption that each lateral well will drain 160 to 100 acres respectively. Although these designs are presented as established practices by a resource industry which made the first serious entry in 2005 in the Barnett dry gas play (Ahmed, 2014), various engineers, geologists and geomechanics specialists have worked hard to establish principles of evaluation and appraisal based on physical measurements, modeling and field verification (Koutsabeloulis and Zhang, 2009;Vassilellis et al, 2009Vassilellis et al, , 2010Vassilellis et al, , 2011Moos et al 2011, Gui et al, 2013. These attempts to predict production performance based on geological characterization have produced in many cases encouraging results, and it is hopeful that in time widely accepted and applied practices will create a reliable link between geology and expected cash flows and introduce geology based incentives that will allow achieving better recoveries at lower costs of extraction.…”