A Comprehensive Reservoir Evaluation of a Shale Reservoir—The New Albany Shale

Abstract

This paper presents the results of a comprehensive reservoir evaluation of the New Albany shale reservoir in northern Kentucky and southern Indiana and Illinois. Although initially compared with the Antrim shale in the Michigan basin, the New Albany shale has been found to have very different production characteristics than the Antrim. This paper presents the results of a comprehensive study performed on behalf of the New Albany Shale Producibility Consortium (NASPC). The objectives of this study were to determine the controls on production characteristics of wells in the New Albany shale, understand well reserves, and ascertain the potential for future development in the play. The reservoir evaluation included all available geologic, formation evaluation, production, and reservoir data from multiple fields within the play. During this study, core testing was conducted to develop baseline properties required for reservoir evaluation. Study results indicated that fracture characteristics within the play are the key driver for well production characteristics and reserves. In addition, we found that matrix gas porosity, bulk permeability, methane adsorption characteristics, and net pay thickness also differentiate the New Albany shale reservoir from the Antrim. The results also indicated that horizontal wells may have the potential to improve productivity and reserves within the play by specifically targeting the characteristics of the fracture pattern within the reservoir. The results of this paper may be useful to producers in fractured shale plays who wish to improve their understanding of flow characteristics and well performance. The work presented in this paper is important because it increases the knowledge base of shale reservoir properties and characteristics and because it describes an approach that can be used to characterize shale reservoirs. Background The New Albany shale is an organic-rich shale located over a large area in southern Indiana and Illinois and in northern Kentucky (see Fig. 1). On average, the shale appears at 500 to 2,000 ft depth.1,2 A representative well log from a producing well in the play is shown in Fig. 2. The gross thickness of the organic New Albany shale ranges from about 100 to 150 ft. The shale is generally broken into four stratigraphic intervals as labeled in Fig. 2. These are the Clegg Creek, Camp Run/Morgan Trail, Selmier, and Blocher intervals from top to bottom. New Albany shale is known to be a productive gas reservoir, with some wells producing for many years. By the mid 1990s, there were 200 to 300 producing wells targeting the shale interval. There were several large, multiwell producing fields within the basin. Most of these fields were developed utilizing vertical wells, and fracture treatments were used to access and stimulate the New Albany shale interval. Gas production from wells drilled in the New Albany shale was found to be generally less than operators expected based on experiences in developing producing wells in the Antrim shale in northern Michigan. Production in the New Albany shale ranged, generally, from 30 to 100 Mscf/D per well. Water production from wells in the play has proved to be highly variable, with some wells making very little water and other wells making more than 1,000 B/D of water. Much of the mid 1990's interest in the New Albany shale was generated by operators wishing to transfer expertise gained in the Antrim shale to the New Albany shale. Projects consisted both of expansion of existing fields within the play and exploration projects in new development areas. At that time, however, there were no comprehensive reservoir studies done on the New Albany shale. Operators generally assumed that the characteristics of the shale would be similar to those of the Antrim.

Modeling and simulation of gas flow behavior in shale reservoirs

“…In general, most of the authors believe that the flow of gas in the fractures will follow Darcy's Law, but the flow behavior of gas in matrix pores is still controversial. Zuber et al (2002), Schepers et al (2009), Wang and Reed (2009), Song and Ehlig-Economides (2011 and Song (Song and Yang 2013) conducted several studies and proposed that the flow of gas from the matrix pores to the fractures in shale gas reservoirs follows Darcy's law. Rushing et al (1989), Dahaghi (2010) and Dahaghi and Mohaghesh (2011) have proposed that the flow of gas from the matrix pores to the fracture network is by diffusion.…”

Simulation of Gas Desorption and Geomechanics Effects for Unconventional Gas Reservoirs

“…Langmuir pressure and Langmuir volume of Barnett Shale, New Albany Shale, Eagleford Shale, Marcellus Shale, and Haynesville Shale published in the literature are listed in Table 1 and the corresponding Langmuir isotherm curves are shown in Fig. 3 (Zuber et al, 2002;Mengal and Watternbarger, 2011;Nobakht et al, 2012;Boulis et al, 2012;Ikewun and Almadi, 2012). Increase in EUR is used to evaluate the contribution of gas desorption to ultimate gas recovery in this paper, and it is defined below:…”

Evaluating Barnett Shale Production Performance Using an Integrated Approach

“…We have used this model successfully since the early 1990s. [14][15][16][17][18][19][20][21] Integrated Modeling Approach …”

“…Typically, shale pemeabilities have been reported to be 10 -4 to 10 -8 md. 5,[15][16][17][18][19][20][21][22][23][24][25] To obtain mineralogy, XRD testing is performed. This testing estimates the various minerals and total clay content.…”

“…One such pre-fracture technique uses nitrogen or water injection (slug) followed by a falloff test. 4,[14][15][16][19][20][21] Another technique that has been successfully used is nitrogen injection followed by a flowback and build up. A third technique uses flow (drawdown) and buildup data to evaluate gas shales before and after stimulation.…”