In general shale is thought to be relatively nonreactive to low pH or acidic fluids. This is because of the general belief the clay, silt, and organic materials comprising the major components of shale formations exhibit insignificant bulk solubility in acid. What we find however is that shale units are highly laminated and contain acid-soluble minerals homogenized in the shale bulk matrix and natural fractures. XRD analysis and SEM images of shale samples show a great diversity and distribution of soluble material in the shale producing unit. SEM images of the shale fracture face before and after exposure to certain reactive fluids show a remarkable amount of surface texture disruption and micro-etching of the fractured surface. Based on these observations, it is concluded that reactive fluids are capable of (1) enhancing gas diffusion into and through narrow-aperture induced fractures, and (2) increasing surface area for flow of gas from the shale matrix. Such fluids are also capable of enhancing flow through mineral-filled microcracks or other secondary porosity. Initial production response from wells treated with reactive low pH fluids has been promising. This paper documents X-ray and SEM analyses of many shale plays in Oklahoma. Production enhancement mechanisms are proposed to explain the observed physical effects of these fluids on shale. Introduction Shale can be defined as a laminated sediment in which the constituent particles are predominantly of the clay size (<0.004 mm, <0.000157-in.) distribution. Shale includes the indurated, laminated, or fissile claystones and siltstones. The anisotropy is that of bedding and such other secondary cleavage or fissility that is approximately parallel to bedding. The secondary cleavage has been produced by the pressure of overlying sediments, dewatering during diagenesis, and plastic flow. The fine particles that compose shale can remain suspended in water long after the larger and denser particles of sand have deposited out. Shales are typically deposited in low-energy environments and are often found in lake and lagoonal deposits, in river deltas, on floodplains, and offshore of beach/sand bar systems. Major producing shales exist throughout the U.S. (Fig. 1). Samples of Woodford, Caney, and Barnett shales are used in this paper to illustrate the diverse makeup of mid-continent shale. Fig. 1-Major shale plays in the U.S. Productive shale plays are unique in that they are source rock, reservoir rock, and trap. The primary storage and producing mechanism of shales are a topic of heated debate. In general, most agree that there is a "free" and "adsorbed" component of hydrocarbon present in most shale plays. Exactly where the hydrocarbon is and how it got there are still topics of research. A conceptual model that seems to have some degree of acceptance is one where the "free gas" is stored and produced from microporosity in lamina and natural fractures and the "adsorbed gas" is stored and produced from the bulk shale matrix (Fig. 2). Shale Types In general, we have classified the shale plays in the U.S. with the descriptions shown in Table 1.

A study, directed at the improvement of hydraulic fracturing treatments performed in the Lobo Wilcox formation in south Texas, is presented. During the study, the performance of numerous gas wells fractured using a single-fluid (organometallic crosslinked) or a multiple-fluid (organometallic and borate crosslinked) technique was determined. During the multiple-fluid treatment (MFT) the organometallic-crosslinked fluid is pumped followed by a borate-crosslinked tail-in fluid. The field study indicates Lobo Wilcox wells fractured using conventional high-temperature fracturing fluids (organometallic-crosslinked fluids) exhibit poor production in comparison to wells fractured using multiple fluids. Improved fracturing fluid recovery and improved well performance were observed in wells fractured with multiple fluids. The improved well performance is attributed to less conductivity impairment by the borate tail-in fracturing fluid. This technique can be used in any high-temperature well to "economically" improve fracture conductivity.