Summary This paper describes simple diagnostics steps which can be used ahead of any fracturing treatment to determine fluid and reservoir properties essential to fracturing success. It outlines a logical progression of diagnostic injections and the data obtained from each process. These diagnostic injections have been performed in the Antrim Shale of Northern Michigan to improve the fracture design by allowing real-time data analysis in a user-friendly fashion for quick interpretion on location. Over 7,000 fracture treatments have been performed in the Antrim Shale of Northern Michigan. Very few have been altered significantly based on pressure data acquired from each preceding treatment. In essence, there has been very little evolution in how operators stimulate the Antrim. Primarily, this is due to the inability to accurately model (fracture) the effect of natural fractures in the Antrim Shale. Nevertheless, it is possible to use these models to analyze pretreatment pressure responses to produce a more efficient frac design and improve the resulting frac conductivity. As the industry moves away from the "cookie cutter" frac design toward one specific design, with minimal additional time and effort, for the well, a mere 10 mcf/d/well increase in production over a period of 10 to 15 years becomes very economical. This paper will illustrate simple diagnostic tests that can be performed prior to each fracturing treatment to give good indication of fluid efficiency localized rock stress. Under real-time circumstances, a 10 to 15 min injection test followed by a complete falloff can yield an abundance of information regarding the viability of a particular fracturing treatment. In the Antrim Shale of Northern Michigan, these diagnostic techniques have been used successfully to determine leakoff, closure, fracture extension, and various other parameters essential in designing a fracturing treatment. In addition, pretreatment results have been linked with the success or premature screen-out of particular wells in the Antrim. Through case studies, this paper will show a logical progression of data analysis based on diagnostic results. Resulting in a fracturing treatment that can be designed or altered on location based on actual reservoir response and measured stresses. In turn, operators can regain a measure of predictability in controlling fractured behavior by tailoring a unique solution for each well without excessive time or added cost. Introduction Fracturing in the Antrim Shale of Northern Michigan has been a common method of completion for over 10 years. In this time period over 5,000 wells have been completed in this zone consisting of the Norwood (lower) and Lachine (upper). Surprisingly, each operator has its own recipe for fracturing the Antrim. Due to well volume, presumed excessive time and expense, and undefined value-added; many operators steer away from performing regular diagnostic tests on their wells before fracturing treatments. Treatments are normally pumped as written. Premature screenouts are associated with excessive leakoff without a qualitative or quantitative analysis. Field personnel without the tools or procedures to recognize the symptoms, by performing diagnostics, generally fall short of a successful treatment when applying one design to every well. Pretreatment diagnostic injections in some fashion are commonly used worldwide for evaluating fundamental reservoir properties. Whether it is tight gas sand in east Texas or high permeability oil zones in the Gulf Coast, diagnostic injection tests are used to determine the necessary fluids, rates, and concentrations for fracturing treatments. As it applies to the Antrim shale, other than a small injection to determine bottomhole pressure, no other analysis is regularly performed prior to treatment. Utilizing complex equations to determine fracture pressure and rate beforehand, or determining fracture width, relies on data not always accessible or even applicable in a highly natural fractured reservoir. Rather, a simple process consisting of designed injections and monitored falloff has been used over the course of the year in various Antrim fields to improve the fracturing design and in evaluating reservoir responses. This paper describes the theory behind each injection, the information collected, the real-time application, and the methods of altering frac designs based on reservoir results. Formation Characterization To understand the range of pressure responses within the Antrim Shale, it is extremely important to be familiar with its lithology and structure. The Antrim formation consists of a series of self-sourced, highly organic shale laminae interspersed with beds of varying calcite content (Figs. 1 and 2). A GRI study states that: reservoir pressure ranges from 150 to 750 psi, matrix gas porosity is 3 to 5%, matrix perm is about 10 md, and bulk perm is 1 to 50 md.* Permeability is highly variable and is dominated by regional conjugate NE-NW fractures thought caused by the Appalachian orogeny. Antrim Shale fractures can be open or partially sealed with calcite, according to a University of Michigan study. Formation image logs have generally indicated higher fracture frequency toward the outer margins of the Michigan Basin where geologists deduce that the "glacial rebound" caused local fracturing on the "shallower" Antrim. Even the "proven" northern productive areas appear to be influenced by the presence of apparent "random fracture nests." Fracture frequency alone, as viewed by logs, does not necessarily assure more productivity, based on several operator studies. This assessment may simply be the result of:higher or less fracture frequency away from the borehole-face;the lack of considering accepted effects of fracture aperture width on fracture productivity; andinadequate fracture design for varying fracture character. Ultrasonic and microconductivity imaging has recorded apparent microfractures, "open" bed boundaries, and both high- and low-angle fractures with some breakout. Many natural fractures appear to truncate at "open" bed boundaries, suggesting that an "induced" fracture would behave the same, thus limiting fracture height growth (Fig. 3).
Over thousands of fracture treatments have been performed in the Antrim Shale of Northern Michigan. Very few have been altered sighificantly based on pressure data acquired from each preceding treatment. In essence, there has been very little evolution in how operators stimulate the Antrim. Primarily, this is due to the inability to accurately model (fracture) the effect of natural fractures in the Antrim Shale. Nevertheless, it is possible to use these models to analyze pretreatment pressure responses to produce a more efficient frac design and improve the resulting frac conductivity. As the industry moves away from the "cookie cutter" frac design towards one specifically design, with minimal additional time and effort, for the well, a mere 10 mcI/cl/well increase in production over a poriod of 10-15 yrs becomes very economical. This paper will illustrate simple diagnostic tests that can be performed prior to each fracturing treatment to give good indication of fluid efficiency localized rock stress. Under real-time cicumstances, a 10-15rnin injection test folliewed by a complete fall-off can yield an abundance of information regarding the viability of a particular fracturing treatment. In the Antrim Shales on Northern Michigan, these diagnostic techniques have been used successfully to determine leak-off, closure, fracture extension and various other parameters essential in designing a fracturing treatment. In addition, pre-treatment results have been linked with the success or premature screen-out of particular wells in the Antrim. Through case studies, this paper will show a logical progression of data analysis based on diagnostic results. Resultantly, a fracturing treatment can be designed or altered on location based on actual reservoir response and measured stresses. In turn, operators can regain a measure of predictability in controlling fractured behavior by tailoring a unique solution for each well without excessive time or added cost. P. 205
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