Production Data Analysis of Shale Gas Reservoirs

Abstract

Unconventional shale gas reservoirs have become a very important part of the resource base throughout the world, but especially in the United States. Production data analysis techniques using various forms of material balance time originally put forth by Palacio and Blasingame (1993) have been proposed and validated in recent publications for a variety of problems (including shale gas and coalbed methane systems) using an adjusted system compressibility function similar to that proposed by Bumb and McKee (1988) to account for adsorbed gas. These modified material balance solutions allow for "type curves" (rate or pressure solutions) to be used in a conventional analysis manner. The significant challenge in the application of production data analysis for shale gas systems is to determine what the parameter values (analysis results) represent within the context of the inherent complexity of these systems. In this work we propose a slight (but substantive) modification to material balance time and apply the technique to synthetic and field data to assess the capability of this approach for the analysis of production data from gas shales. The formulation we use is that of Cox, et al. (2002) which provides a means for evaluation production data as an equivalent "well test", where we are able to observe characteristic flow regimes in the data and constrain several of the key parameters of interests in shale gas systems. While the field results are difficult to corroborate, the relative magnitudes of the parameters we obtained appear to be reasonable. Introduction The vast majority of gas production in the United States comes from what are known as conventional hydrocarbon reservoirs. However, these conventional reservoirs are becoming increasingly difficult to find and exploit. In an era of rising prices for crude oil and natural gas, the ability to produce these commodities from unconventional reservoirs becomes very important. The United States Geological Survey states that, among other things, an unconventional reservoir must have regional extent, very large hydrocarbon reserves in place, a low expected ultimate recovery, a low matrix permeability and typically has a lack of a traditional trapping mechanism (Schenk, 2002). In particular, shale gas reservoirs present a unique problem to the petroleum industry in that they may contain natural gas in the pore spaces of the very tight reservoir rock, in the pore spaces of natural fractures in the formation and on the surface of the rock grains themselves which is referred to as adsorbed gas (Montgomery, et al., 2005). This sorbed gas presents difficulties in that desorption time, desorption pressure, and volume of the adsorbed gas all play a role in how this gas affects the production of the total system. Adsorption can allow for significantly larger quantities of gas to be in place and possibly produced. Historically, the first commercially successful gas production in the U.S. came from what would now be considered an unconventional reservoir in the Appalachian Basin in 1821. Currently, some of the largest gas fields in North America are unconventional, shale gas reservoirs such as the Lewis Shale of the San Juan Basin, the Barnett Shale of the Fort Worth Basin, and the Antrim Shale of the Michigan Basin. In addition, gas production from unconventional reservoirs accounts for roughly 2% of total U.S. dry gas production (Hill, et al., 2007). Shale gas reservoirs present numerous challenges to analysis that conventional reservoirs simply do not provide. The first of these challenges is the dual porosity nature of these reservoirs. Similar to carbonate reservoirs, shale gas reservoirs almost always have two different storage volumes for hydrocarbons, the rock matrix and the natural fractures (Gale, et al., 2007). Because of the plastic nature of shale formations, these natural fractures are generally isolated or closed due to the pressure of the overburden rock (Gale, et al., 2007). Consequently, their very low matrix permeability, usually on the order of hundreds of nanodarcies (nd), makes un-stimulated, conventional production difficult, if not impossible. Therefore, almost every well in a shale gas reservoir must be hydraulically stimulated (fractured) to achieve economical production. These hydraulic fracture treatments are believed to re-activate and re-connect the natural fracture network (Gale, et al., 2007).

Integration of microseismic and other post-fracture surveillance with production analysis: A tight gas study

“…Type-curve methods have been described in detail in previous work and are not reviewed here e recent adaptations of these techniques for CBM and shale analysis were discussed in Clarkson et al (2009) and Lewis and Hughes (2008), respectively. As part of this work, new type-curves have been developed for multi-fractured horizontal wells.…”

Unconventional gas reservoir evaluation: What do we have to consider?

“…Low matrix permeability, which causes transient flow periods to be extensive Dual porosity or dual permeability behavior, due to existence of natural fractures or induced hydraulic fractures (or both) Other reservoir heterogeneities, such as multi-layers (interbedded sand/silt/shale) and lateral heterogeneity Stress-dependent permeability, due to a highly-compressible fracture pore volume Desorption of gas from the organic matrix Multi-mechanistic (non-Darcy) flow in shale matrix, caused by gas-slippage along pore wall boundaries and diffusion (see Javadpour, 2009), or in the hydraulic fractures due to inertial flow Recent advances in these methods specifically for UGRs include: Shale gas reservoirs (Lewis and Hughes, 2008;Moghadam et al, 2010;Abdulal et al, 2011) …”

Production Analysis of Multi-Stage Hydraulically Fractured Horizontal Wells in Tight Gas Reservoirs

“…Lewis and Hughes (2008) presented type-curves for single and dual-porosity gas reservoirs using a modified material balance time. Medeiros et al (2008) presented a semi-analytical solution for the MFHW.…”