The Antrim Shale of the Michigan Basin is one of the most active natural gas plays in the U.S., accounting for over 1200 well completions during 1992. Despite the high level of development activity, current approaches to completing, stimulating and producing Antrim wells may not be optimum for this shallow, underpressured, naturally fractured, dual-porosity reservoir with characteristically low matrix permeability, and with mobile water, free gas and adsorbed gas coexisting in the reservoir system. Some examples of the technical areas which require attention include the frequently disappointing stimulation results achieved with hydraulic fracturing, and the high producing backpressures associated with the commonly practiced reverse gas-lift technique for well dewatering. This paper describes the activities and interim results of the Gas Research Institute's field-based research in the Michigan Basin aimed at enhancing Antrim well performances through improved completion, stimulation and production practices.

Three field research projects were performed during 1991 and 1992 specifically to investigate alternative completion, stimulation and production practices in the Antrim Shale, each in cooperation with an active Antrim operator. The Bagley East Project, performed in cooperation with NOMECO Oil and Gas Co., investigated the potential for improving the performance of existing Antrim wells by reducing flowing bottomhole pressures by utilizing mechanical pumping methods for well dewatering, and by restimulating wells identified through pressure transient testing as problem wells. A gas production increase of 109% was achieved in one well after it was converted from reverse gas-lift to a mechanical pump. A second well, identified through pressure transient testing to have a dimensionless skin factor of zero (after fracture stimulation and approximately one year of production), was restimulated with a resulting increase in gas production of 168%. Based on the results achieved at the Bagley East Project, there appears to be considerable scope for improving the performance of existing Antrim wells through optimized dewatering methods and through selective restimulation.

The two remaining research projects, the North Charlton 31 and Elvira #11 projects, performed in cooperation with Ward Lake Energy and Terra Energy respectively, are aimed at improving stimulation technology in the Antrim Shale. The North Charlton 31 Project is investigating whether individually fracture stimulating the two commonly completed shale intervals (the Norwood and the Lachine) is more cost effective than a single treatment for both horizons, as is routinely practiced today. The project consists of four wells, two open-hole completions in which single-stage fracture treatments were performed, and two cased-hole wells in which each horizon is being individually stimulated. To date, pre-stimulation pressure transient tests, the open-hole single-stage fracture treatments and the cased-hole Norwood fracture treatments have been performed. Future research operations, including pressure transient testing and the individual stimulation of the Lachine in the cased-hole wells, should provide insights into the cost-effectiveness of single-stage versus two-stage fracture treatments.

The Elvira #11 Project is investigating whether less-expensive stimulation treatment methods might be viable alternatives to hydraulic fracturing in the Antrim Shale. Typically, post-fracture skin factors as determined by pressure transient testing are in the −2 to −3 range, considerably less than one would expect with a well propped, long hydraulic fracture in a moderate permeability shale. These low, negative skin factors suggest that nearwellbore damage-removal type stimulation treatments may provide the same degree of stimulation as hydraulic fracturing in the Antrim Shale, at least in higher shale permeability settings, but at a lesser cost. In this project, three offset wells were each stimulated with different methods, one by a simple acid bailout treatment to cleanup the perforations, another using the high energy gas fracturing (HEGF) method, and the third well by hydraulic fracturing. Post-stimulation injection/falloff testing indicated that hydraulic fracturing provided a superior completion efficiency, with a measured skin factor of −2.1; the acidized well and the HEGF well had measured skin factors of +5.6 and +37 respectively, implying that poor communication between the wellbore and the natural fracture system still exists in these wells. Future production testing is still required to confirm these results.

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