80
60
analysis to a dataset from an HDR hydraulic frac- turing operation to help characterize the devel- oping fracture system within the reservoir.21 The greatest potential for improving the eco-
40 20
nomics for geothermal energy projects, as in any high-risk, high-cost venture, is by risk reduction through a better understanding of the subsur- face. The unknowns that affect drilling and com- pletion risk, environmental impact, stimulation and overall project success are all exacerbated by a lack of knowledge about lithology, stress regime, natural seismicity, preexisting faults and fractures, and temperature at depth.22 Correcting these shortcomings will be a
0 0 10 20 Volume of fluid injected, 1,000 m3
> Controlling reservoir size. During a massive hydraulic fracture test at Fenton Hill, a linear relationship was established between the seismically active reservoir volume and the volume of injected fluid, as determined from microseismic event location data. (Adapted from Duchane and Brown, reference 16.)
30 Despite the progress being made on the tech-
nological aspects of HDR exploitation, commer- cial viability of these prospects remains elusive as a consequence of their depth and tempera- ture. For example, commercial hydrothermal well depths range from less than 1 km to a rare few that reach about 4 km [13,000 ft], such as the EGS project in Soultz-sous-Forêts, France. HDR wells, because they are in crystalline basement formations, are typically much deeper. As a con- sequence, HDR wells are likely to be character- ized by varied lithology and the extensively documented problems associated with deep drill- ing and completion.20
The Gap Owing to the obvious similarities between hydro- carbon and heat mining, it is tempting to assume that adapting the technology of the former to the latter is a matter of focus. Recent development of tools for use in some applications—HPHT oil and gas wells, hydrothermal fields and steam- flooding—encourages such assumptions. Geothermal energy resources, however, differ
across the world, and the ease with which this technology transfer will take place is a function of those differences. The highest grade of resource—hydrothermal—is shallow, permeable and hot and has a natural water-recharge system.
The techniques and methods used to tap that resource are and will continue to be familiar to oilfield personnel. Lower-grade resources that require interven-
tion in the form of injection or fracturing, or whose temperatures are below the boiling point of water, are also being produced at a profit through the use of technology adapted from the petroleum industry. Coproduction is a current technique that uses the hot water produced with oil and gas to run binary plants, which in some cases generate all the field’s electricity needs. But the real prize in geothermal energy pro-
AUT09–RVF–11
duction will come once the technology required for EGS and HDR reservoirs is widely available. Despite current barriers to commerciality, HDR projects do have an advantage over those for conventional hydrothermal systems in that they can be located near major electricity markets. That they still require much technological
innovation, however, has created a tendency among many of those best equipped to solve these problems—petroleum industry professionals—to abandon the notion of HDR developments in favor of more immediate and familiar pursuits. With the prospects of large payoffs, there has
been progress on making HDR projects economi- cally attractive, including the vital area of reser- voir-creation monitoring and control. In the Cooper basin of Australia, for example, geophysi- cists recently applied microseismic multiplet
matter of growth, but of a type with which the E&P industry is long familiar. It took the offshore industry more than 50 years of lessons learned between the first well drilled in shallow water just out of sight of land to routine placement of wells in water depths of more than 3,000 m [10,000 ft] and hundreds of kilometers from shore. Moving from shallow, high-grade hydro- thermal formations to deep, hot dry rocks will require a similar evolution in technology, equip- ment and trained personnel. Given the prize in the offing, however, it is certainly just a matter of time.
—RvF
Winter 2009/2010
13
Seismic volume, 1,000,000 m3
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