Summary The drilling and completion of deep wells in hot, nonporous, crystalline basement rock has challenged conventional rotary and directional drilling tools, procedures, and instruments used for oil and gas drilling. Drilling operations at the Fenton Hill Hot Dry Rock (HDR) Geothermal Test Site have led to numerous developments needed to solve the unique problems caused by a very harsh downhole environment. The well site is on the western flank of a young silicic composite volcano in the Jemez Mountains of northern New Mexico. A pair of deep wells was drilled to approximately 15,000 ft [4.6 km]; formation temperatures were in excess of 600 deg. F [316 deg. C]. The wells were drilled directionally, and inclined at 35 deg., one above the other, in a direction orthogonal to the least principal stress field. The completion of this pair of wells is unique in reservoir development. The deeper well will be a cold water injector, cooled during injection from the static geothermal gradient to about 80 deg. F [270 deg. F. The upper well will be heated during production to more than 500 deg. F [260 deg.). The well pair is designed to perform as a closed-loop heatextraction system connected by hydraulic fractures, with a vertical spacing of 1,200 ft [366 m] between the wells. These conditions strongly constrained the drilling technique, casing design, cement formulation, and cementing operations. New and upgraded technologies have been developed to resolve the difficulties of completing these two wells. Introduction In natural, or hydrothermal, geothermal reservoirs, surface waters penetrate deep enough to contact hot rock. The fluids are heated by the rock but are trapped in a porous fractured system. A large circulating convection system of fluid has been established in places. Although these hydrothermal convection systems are rather rare, they are excellent sources of energy. The ratio of dry holes to production wells in hydrothermal exploration is highly variable, but averages about 3:1. Many of these dry holes are hot, having penetrated into a volume of hot rock that lacks fluid and natural permeability. Thus, dry but hot wells are excellent candidates for artificial stimulation, or for application of the HDR energy extraction concept. Project Description The production of heat energy from hot, dry rock entails creating fracture permeability at depth to permit circulation of water from the surface through wells. A preliminary project to develop this concept (Fig. l) was initiated by the Los Alamos Natl. Laboratory in 1972 and, in 1977–80, succeeded in producing the first two reservoirs in a hot, crystalline formation at 10,000 ft [3 km], where formation temperatures are 400 deg. F [204 deg. C]. Long-term pumping and temperature drawdown tests and reservoir simulations examined the technical feasibility of the concept for the commercial development of a larger and hotter HDR geothermal reservoir. These initial results prompted drilling a second pair of deep, 350-inclined wells, so that the development of a multiple, parallel fracture reservoir could be attempted. There were many unique problems encountered both in the drilling of these two deep wells into Precambrian crystalline rock and in the initial phases of the completion and hydraulic fracturing efforts. The drilling of the deeper well pair started with the spudding of Energy Extraction Well 2 (EE-2) on April 3, 1979. This injection well was drilled and cased in 409 days. The well was drilled directionally to a measured depth of 15,298 ft [4.7 km] and deviated in a direction orthogonal to the inferred in-situ least principal stress (Figs. 2A and 2B). The bottomhole static temperature (BHST) was recorded as 608 deg. F [320 deg. C]. The production well, Well EE-3, was directionally drilled so that the wellbore trajectory was spaced 1,200 ft 50 ft [366 m+ 15 m] directly above the injection well. Well EE-3 was speded May 22, 1980, and was finished 461 days later. Well EE-3 reached a measured depth of 14,933 ft [4.6 km] and a BHST of 580 deg. F [304 deg. C]. The EE-3 borehole trajectory was maintained vertically above Well EE-2 to an azimuth tolerance of + 100 ft [+30m]. This precision was required to maximize the chances for fracture connections during completion operations. Fracturing and completion operations were initiated April 4, 1982. These operations are still in progress (May 1985). JPT

This paper discusses drilling a 2,000-foot horizontal well in the Devonian Shale, Wayne County, West Virginia, to test the concept that multiple hydraulic fractures from a horizontal wellbore can increase gas recovery efficiency over vertical stimulated boreholes. Discussion focuses on the air/mist drilling, wireline probes, and bottomhole assemblies that were used to drill the well, The target was a 50-foot zone located at a depth of 3,400 feet. Total hole length was 6,020 feet. The angle-building section was achieved using a 4.25 degrees/100-foot design to reduce the risks associated with casing installation in the horizontal section. Directional control methods proved to be unreliable in an air-drilling environment. Bottomhole assembly performance was heavily dependent on motor life and lithologic type. The completion program for the well consisted of installation of 4 1/2-inch casing with external casing packers and port collars. This completion string was installed in 2,000 feet of open hole section that was air drilled. Both geophysical well logs and a borehole television camera survey were used to design the casing string so that shale intervals could be isolated for testing and evaluation before and after stimulation. Background The drilling of directional wells and even horizontal wells to augment oil and gas production goes back to at least 1944 in the Appalachian Basin wherein a horizontal well was drilled from a 500-foot deep shaft in the Franklin Heavy Oil Field in Venango County, Pennsylvania, to improve oil recovery. Several hundred feet of horizontal core was taken during the drilling operations in the Venango Sand to characterize the reservoir. The Federal Government has been investigating the application of high-angle drilling to improve reservoir access in tight formations for more than 20 years. The focus of much of this research was to determine the properties of earth fracture systems in productive Devonian shale reservoirs and to develop improved techniques for recovering hydrocarbons with increased efficiency. The value of high-angle drilling perpendicular to natural fracture systems for maximizing production from fractured reservoirs was recognized early. Several field tests have been conducted to investigate the concept. In 1972, a high-angle borehole was drilled in Mingo County, West Virginia, to a measured depth of 4,678 feet with an average deviation of 41" from vertical through the Devonian shale section. After establishing the feasibility of drilling high-angle wellbore using air, a subsequent well was drilled to 53 degrees in the Cottageville Field, Jackson County, West Virginia. Total measured depth of that well was 4,736 feet. Experience from these two directional wells using mud motors on air identified many limitations of economic directional drilling. In DOE's latest experience, an oriented core was obtained from a Meigs County, Ohio, Devonian shale directional well to determine natural fracture spacings. High-angle air-drilling experience using downhole motors is not well documented in the petroleum literature. The most recent experience in air-drilled high-angle wells is the Grand Canyon Directional Drilling and Waterline Project which was accomplished using air-driven motors and wireline steering probes. Conventional wellbore sizes and tools were used to achieve a 71 degrees hole angle. Recent reservoir modelling studies used to estimate recovery efficiency of a Devonian shale horizontal well show a two- to three-fold increase in gas reserves per unit volume of reservoir. P. 291

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This report presents a summary of the geologic site selection studies, planning, drilling, completing, stimulating, and testing of two horizontal wells drilled in the Devonian Shales of the Appalachian Basin in West Virginia. Each horizontal well was designed and managed by BDM as the prime contractor to the Department of Energy. The first well was drilled with industry partner Cabot Oil and Gas Corporation in Putnam County, West Virginia. The second well was drilled with Consolidated Natural Gas Company in Calhoun County, West Virginia. This report summarizes four reports prepared by BDM which detail the site selection rationale and the drilling and completion operations of each weil. Each horizontal well is currently producing commercial quantities of hydrocarbons. The successful application of horizontal well technology represent continued development of the technology for application to tight and unconventional natural gas resources of the United States. Continued technology development is expected to ultimately result in commercial horizontal well drilling activity by industry in the Appalachian Basin. ix 1.0 EXECUTIVESUMMARY This report summarizes the geologic studies, site selection, drilling, logging, completion, and well _testing of two horizontal wells t drilled in the gas-bearing Devonian Shale interval in the Appalachian Basin. Detailed technical information concerning each of the two wells reviewed in this volume will be found in the technical report for each weil. Cash flow analyses were undertaken for each horizontal well using the well-specific cost and production information available through the end of January 1992. These results, detailed in this volume, show that a horizontal well is economic over a wide range of economic conditions if: (1) The well cost can be controlled to between $500,000 and $700,000 and (2) If the well is likely to produce at least 140 Mcf/day over the first year of operations, depending on the price of natural gas.

This paper discusses site selection, air directional drilling, stimulations, and economic evaluation for a 72" slant well drilled in the Devonian shale, Roane County, West Virginia. The well was drilled to evaluate the concept of using directional drilling and multiple hydraulic fracturing to improve the gas production from a 450-foot naturally fractured Devonian shale section. The well trajectory remained in target for more than 1,500 feet at a preferred azimuthal direction perpendicular to the regional fracture trend and also the known production fairway. 45 well testing has been identifled tor each zone to show initial results.