Well 29-1


0 500


1,000 1,500 2,000


2,500 Truckee and Desert Peak Fms


Chloropagus Formation


Rhyolite (lower) PT-2 (lower) PT-2 (upper) Quartzite PT-2 (lower) 0 Dolomite m 1,000


Faults dashed where inferred Lost circulation zone


Tr-J mudstone


Rhyolite (upper)


Dacite PT-2 (upper)


(upper) PT-1


PT-2


Rhyolite (lower)


Well 27-15


0


1,000 2,000 3,000 4,000 5,000 6,000


7,000 8,000 9,000


> One of two Desert Peak cross sections. This conceptual cross section of the geothermal field shows the stratigraphy and interpreted structure from Well 29-1 in the south to Well 27-15 in the north. The key features of this section are the gently dipping top of the basement rocks in the north, the presence of a pre-Tertiary 1 (PT-1) interval in Well 27-15 and the thick Tertiary section (green) in the southern wells. Faults and structural interpretations are based on lithologies and stratigraphic sequences encountered in each well, and locations of lost circulation zones identified from well cuttings and well logs. Well 27-15 is the candidate for hydraulic stimulation. (Adapted from Lutz et al, reference 13.)


interactions and heat transfer must be consid- ered when determining injection rates, pumping times and injection temperatures for fracturing geothermal formations. In recent years, stimulation of oil-bearing for-


mations by fracturing has become increasingly sophisticated and efficient as the industry devel- oped methods for modeling, plotting, tracking and even controlling fracture direction. But most of these techniques rely heavily on electronic sensors placed downhole near the sandface depth. Temperature limitations render these devices useless in geothermal zones. Still, oilfield-style interventions are being


applied successfully in many of the world’s larg- est geothermal fields, which are typically the highest temperature volcanic-hosted systems. These operations are essentially EGS and include such established projects as the Salak geother- mal field, operated by Chevron. The largest of its kind in Indonesia, the Salak field is located within a protected forest about 60 km [37 mi] south of Jakarta (next page, top right). Chevron has maintained steam production


The model proposed is based on analysis of


mud logs and cores and incorporates new data from three wells drilled in the production portion of the field. Two cross sections have been con- structed based on correlations observed in these three wells (above). Researchers logged a candidate stimulus well,


27-15, adjacent to the current production area to aid in evaluating lithologies and characterizing stress and fractures. Gamma ray and caliper data were recorded and borehole images were also acquired. Features identified from these resistivity-contrast–generated images include bedding planes, lithologic contacts, foliations, con- ductive mineral grains, drilling-induced fractures and natural fractures.14 In combination with other petrologic and petrographic studies incorporated into a GeoFrame model, this imaging provided a more complete understanding of the geological charac- teristics of the well as a candidate for EGS. Further rock mechanics testing conducted at the Schlumberger TerraTek Geomechanics Center of Excellence in Salt Lake City, Utah, USA, will characterize rock strengths and stress behavior of potential reservoir rocks within the proposed stimulation interval. The researchers noted that the productive


portion of the Desert Peak geothermal field lies within an older structural horst bounded by north-


west-trending faults. The results of tracer tests indicate that fluids injected into the production area can cross into currently non productive areas along younger northeast-trending faults. The sci- entists were unable, however, to determine the depth of the fluid transmissivity and whether the basement fault served as a barrier or conduit to geothermal fluids. Upcoming hydraulic and chemi- cal stimulation experiments are expected to increase permeability and fluid-fracture connec- tivity in this enhanced system.


AUT09–RVF–07


Making the Good Better The dominant tools of EGS—reservoir model- ing, drilling, hydraulic fracturing and water injection—are familiar to petroleum engineers. Unfortunately, their use in geothermal applica- tions is more than a matter of adapting them to increased temperatures. For example, in oil and gas formations, both


induced and natural fracturing are reasonably well-understood concepts. But because oil sands are fractured to increase flow in discrete strati- graphic intervals—and the goal in a geothermal resource is to maximize heat exchange in large volumes of fractured crystalline rock—the oper- ations differ greatly in their application. Whereas traditional hydraulic fracturing operations are constrained predominantly by rock stresses and boundary considerations, complex rock and fluid


levels and optimized heat recovery at Salak through infill drilling and water injection into deep wells on the field’s margins where permea- bility is low. Through the use of tracers, chemical and microseismic monitoring, and pressure- temperature surveys of individual wells, Chevron has been able to gauge the impact of its injection strategy and to move injection wells farther from the field’s center and closer to its edges. This approach has simultaneously generated more area for infill drilling and expanded the field. It has also allowed the company to convert several injection wells into producers once the formation has thermally recovered. More recently, geophysical data, including MT


and time-domain electromagnetic surveys on the field’s margins, have identified potential reser- voir extensions to the west and north of the proven area. To the west, the Cianten Caldera exhibits a low-resistivity layer at depths similar to those in the Salak reservoir, and microseismic data show distinct depth distribution of the proven reservoir through the western area. Drilling results in the caldera indicated non- commercial temperatures. Ring dike intrusions appeared to preclude fluid circulation from the proven reservoir. Geothermal reservoir boundar- ies tend to be vague, and new wells often encoun- ter low-permeability but hot formations that must be stimulated to provide adequate injection rates. The operator therefore began a long-term,


10


Oilfield Review


Depth, m


Depth, ft


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