Unique Aspects of Drilling and Completing Hot, Dry Rock Geothermal Wells
- R.S. Carden (Shuraeu, Grace, Moore, and Assocs.) | R.W. Nicholson (Well Production Testing) | R.A. Pettitt (Los Alamos Natl. Laboratory) | J.C. Rowley (Los Alamos Natl. Laboratory)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- May 1985
- Document Type
- Journal Paper
- 821 - 834
- 1985. Society of Petroleum Engineers
- 1.10 Drilling Equipment, 1.5.1 Bit Design, 3 Production and Well Operations, 1.6 Drilling Operations, 5.5 Reservoir Simulation, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.11 Drilling Fluids and Materials, 1.9.4 Survey Tools, 1.5 Drill Bits, 5.2.1 Phase Behavior and PVT Measurements, 5.9.2 Geothermal Resources, 1.14 Casing and Cementing, 2 Well Completion, 4.2.3 Materials and Corrosion, 1.6.1 Drilling Operation Management, 1.4.1 BHA Design, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.14.3 Cement Formulation (Chemistry, Properties), 1.7 Pressure Management, 4.3.4 Scale, 1.14.1 Casing Design, 1.6.9 Coring, Fishing, 1.6.2 Technical Limit Drilling, 1.6.6 Directional Drilling, 4.1.9 Heavy Oil Upgrading
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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.
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).
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