Abstract:

Drilling cost and risk is the greatest impediment to global geothermal development. In the early 1990s, the use of lower cost slim holes was introduced for geothermal exploration. Although the industry was slow to adopt this method, slim holes are now commonly drilled and tested to evaluate geothermal resource potential. With the advancement of novel drilling techniques and miniaturized instrumentation, microbore exploration wells can reduce drilling cost and risk in EGS and conventional geothermal development.

Of critical importance in the use of a surrogate slim hole or microbore to assess resource capability is the assumption that test results can be accurately scaled to larger, more expensive production bores to be completed after successful discovery of a resource. The accuracy of this scaling varies with test bore diameter, resource conditions and the degree of scale-up to larger bores. Geothermal exploration wells are typically evaluated by discharging the well to surface equipment at atmospheric pressure to measure flow rate, enthalpy, and fluid composition. Reservoir characteristics are further evaluated by conducting injection tests, step-rate production tests, and pressure recovery measurements. However, low temperature resources or small diameter bores are often incapable of continuous, unassisted flow. In such cases, flow to the surface can sometimes be induced, or temporarily maintained, by air- or nitrogen-lift, or pumping, but these methods add significantly to the cost and complexity of the test operation. In addition, atmospheric flow tests require relatively large liquid storage facilities (sumps or tanks) or a nearby injection well, and test duration may be limited due to steam and gas emission considerations, hazardous liquid composition, or water disposal restrictions.

Using innovative test methods, slim hole and microbore resource evaluation can be completed using a drill stem test. This method eliminates errors associated with surface flow tests, and requires substantially less infrastructure and reduce the time required for resource evaluation.

Abstract:

The Momotombo geothermal field has been in development since the 1960s, with most drilling completed in the 1970s, and was on line with its first 35 MWg geothermal flash power plant in September 1983. The field has had several operators in its operational history, with installed capacities of 35-77 MWg and generation from 8-69 MWe. Generation was 22.5 MWe at the time of the study.

Momotombo Power Company recently became the owner/operator of the concession of the Momotombo field, and a complete assessment of wellfield performance and well conditions was initiated to assess the feasibility of increasing generation to 42 MWg. This review included a numerical simulation of the field, which also requires a strong geologic conceptual model. Previous reservoir models focused on the producing field, but did not account for sources of pressure support to several wells from outside the core of the field area. A new conceptual model was developed, and a numerical simulation of the field was used to validate and adjust assumptions in the conceptual model, resulting in a very robust conceptual and numerical model.

The resulting, integrated model suggests the existence of an area of primary recharge and upwelling that is currently undeveloped and partially connected to the existing development, providing pressure and heat support to wells closest to that area. There appear to be significant developable reserves in this area, and additional exploration is recommended to determine the extent and possible secondary outflow areas.

Within the history matching process of the numerical model, two downhole well bore failures were identified. Candidates for well remediation have been identified to increase generation from existing wells to increase generation to 42 MWe. Areas for expansion were revealed to better utilize installed capacity, and a plan to increase generation through the 15-year contract life will be implemented.

Abstract:

Interim results of a new conceptual modeling effort for the Salton Sea geothermal field (SSGF), in the Salton Trough of southernmost California, show that this resource: (1) is hotter at depth (up to at least 389°C at 2 km) than initially thought; (2) is probably driven by a still-cooling felsic intrusion rather than (or in addltion to) the primitive mafic magmas previously in- voked for this role; (3) may be just the most recent phase of hydrothermal activity initiated at this site as soon as the Trough began to form -4 m.y. ago; (4) is thermally prograding; and (5) in spite of 30 years’ production has yet to experience signifi- cant pressure declines. Thick (up to 400 m) intervals of buried extrusive rhyolite are now known to be common in the central SSGF, where tem- peratures at depth are also the hottest. The considerable thick- nesses of these concealed felsic volcanics and the lack of corre- sponding intermediate-compositioni gneous rocks imply coeval granitic magmas that probably originated by crustal melting rather than gabbroic magmatic differentiation. In the brine-satu- rated, Salton Trough sedimentary sequence, granitic plutons inevitably would engender convective hydrothermal systems. Results of preliminary numerical modeling of a system broadly similar to the one now active in the SSGF suggest that a still- cooling felsic igneous intrusion could underlie deep wells in the central part of the field by no more than a kilometer. The model results also indicate that static temperature profiles for selected Salton Sea wells could have taken 150,000 to 200,000 years to develop, far longer than the 20,000 years cited by pre- vious investigators as the probable age of the field. The two viewpoints conceivably could be reconciled if the likely long hydrothermal history here were punctuated rather than pro- longed. Configurations of the temperature profiles indicate that portions of the current Salton Sea hydrothermal system are still undergoing thermal expansion. A newly consolidated, field-wide reservoir database for the SSGF has enabled us to re-assess the field’s ultimate resource potential with an unprecedented level of detail and confidence. The new value, 2330 MW, (30+ year lifetime assured) closely matches an earlier estimate of 2500 MW, (Elders, 1989). If this potential were fully developed, the SSGF might one day satisfy the household electrical-energy needs of a fourth the present population of the State of California.

Abstract:

An empirical graphical method, based on type curve matching is presented. Using only flowing pressure-temperature surveys, the flowing enthalpy vs depth in two-phase wellbores can be determined. Also fluid entries are identified in the two-phase as well as the single-phase region. In some cases the relative flow rates of each entry and the enthalpy of the entry itself can be determined. Six example surveys from the Coso field are given and interpreted.

Abstract:

An injection stimulation test begun at the Raft River geothermal reservoir in June, 2013 has produced a wealth of data describing well and reservoir response via high-resolution temperature logging and distributed temperature sensing, seismic monitoring, periodic borehole televiewer logging, periodic stepped flow rate tests and tracer injections before and after stimulation efforts. The hydraulic response demonstrates continually increasing injectivity, reflected in varying flow rate response to nearly constant injection pressure, but features of the hydraulic response provide information about different characteristics of the reservoir. Changes in injectivity immediately following high-flow rate tests suggest that hydro shearing has altered the near-well permeability structure, while pressure response during those tests indicates that near-well permeability is relatively homogeneous and low but that the well is near, but not well connected to, a zone of higher transmissivity. Long-term changes in injectivity are believed to reflect propagation of the injection cooling front through low permeability zones. Two dimensional flow and heat transport simulations are used to demonstrate how the timescale of pressure response may relate to length scales of permeability distribution.

Abstract:

This paper presents a simple method of designing a suspended fracture of a desired conductivity. The design balances volume, pump rate, and fluid loss to get the desired length. A sand schedule then is calculated to give the optimum flow capacity. The fluid and sand used to build the excess flow capacity in an equilibrium pack design are used to obtain better vertical coverage and deeper penetration.

The method is most applicable to low permeability reservoirs where the conductivity of an equilibrium pack is not needed. In this type of reservoir, the surface area of a fracture face will give up only a finite amount of fluid. It is not necessary for the fracture to have a greater flow capacity to the well­ bore than the formation has into the fracture. The design also can be applicable in some massive zones where the permeability is higher, but the cost to build an equilibrium pack is prohibitive. With a suspended pack design using the same amount of fluid, a deeper fracture with 100% vertical coverage can be obtained. In many cases, this produces a higher productivity increase with a lower cost.

The design centers on the sand concentration of the sand slurry in a finite number of segments along the fracture length. Using a compound-interest formula, the approximate amount of fluid that has leaked off in each segment is calculated. Then, with the final desired slurry concentration known, the sand concentration needed in each segment when pumped can be calculated.

The design is done in 10 easy steps with a program written for a TI-59 that will do almost all of the calculations included. The design is not applicable to every well, but where it does apply it can (1) give better vertical coverage, (2) get deeper penetration, (3) reduce costs for the same productivity increase, and (4) reduce the amount of load to recover.