Many challenges arise when cementing geothermal wells. Lost circulation and temperature are
the main culprits for increased cost when trying to achieve zonal isolation. At the Puna
geothermal field, extreme lost circulation and bottom hole static temperatures in excess of 500°F
are not uncommon. The extreme conditions, coupled with the remoteness to drilling service
providers, represent a significant challenge. Reverse cementing was used to successfully
complete a job in a challenging environment and also significantly reduce cost in the cementing
phase of well completion. A demonstration of proper planning, designing, and execution of the
job is presented.
Complete cementing of casing strings is critical in geothermal wells to protect the casing and provide mechanical integrity to the well bore. Surface indicators allow drilling personnel to select the best method for remedial cementing. The ‘top fill’ method is selected when cement is observed at the surface during the primary cement job, but the cement subsequently falls down the annulus. The ‘top squeeze’ method is selected when there are no cement returns to surface during the course of the primary cement job. For each case, specific procedures must be followed to successfully complete a remedial cement job. These procedures should be planned in advance. In addition, these procedures are not dependent on the primary cementing technique. Either ‘top squeeze’ and/or ‘top fill’ may be used for any casing string that is run with a previously cemented casing string in place that has an annular preventer installed.
Cement plug setting is one of the most unpredictable and time consuming operations in the drilling process of a geothermal well, thus adding considerable cost and risk to drilling, completion, and workover operations. Setting of ten to twenty consecutive plugs for a single sidetracking job, each requiring up to 8 hours of wait time for the cement to cure, are not unheard of in the industry. Significant risk arises from the inability to support the cement slurry while it cures inside the wellbore.
Perigon’s cement support tool (CST™) was designed to increase the success rate of setting cement plugs by physically separating the plug from the drilling fluid while the slurry cures, just as if it was set at the bottom of a well or above a bridge plug. Another attractive feature of the CST™ tool is its drillability, and foldable aluminum and composite construction (Harestad, 2015), which enables it to be pumped through small diameter tubing and then enlarged in the well bore. This paper summarizes a recent, first-ever and successful plug setting operation using coiled tubing in a large diameter geothermal well casing.
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.
Obtaining fracture gradient data is a critical objective in oil, gas, and geothermal well drilling, from the well construction perspective. Fracture gradient data is important for properly executing many drilling phases and maintaining safe practices. Applying proper well design techniques ensures that a well can be shut in safely, mitigates underground well control issues Availability of fracture gradient data also results in significant improvements to the design and reduces the cost of future wells in the same field by allowing for the determination of the minimum number of casing strings required for safe drilling and completion. Thus, measuring the fracture gradient at relevant depths in a well is critical to reducing well cost, producing a safe well design and reducing the likelihood of downhole well control incidents. The step rate formation integrity test method is a safe and practical method of measuring the fracture gradient and leak-off pressure of a well while minimizing the risk of causing lost circulation.
The Salton Sea geothermal field is one of the largest geothermal
resources in the world. It was discovered in the 1950s
but has only been developed on the southeastern lake shore and
the actual field boundaries are not well known. In this paper we
describe a combined offshore/onshore Magnetotelluric (MT)
survey made over the known geothermal field and surrounding
region to determine the formation resistivity signature of the
geothermal field and to use this signature to map the external
field boundaries and internal structure.
The survey was made with land, marine and hybrid MT
field systems. These instruments use a portable, low-power
digital data acquisition system with sensors deployed on land,
and on the shallow sea bed. The survey consisted of 70 sites
arranged in 4 profile lines; 3 of these profiles cross the northeast
trending geothermal field in a NW-SE direction and the
4th profile crosses in a NE-SW direction. The data from the
sites were processed to provide apparent resistivity and phase
as functions of frequency for each site. The sites were then
grouped into profiles, and a 2D inversion code was applied to
provide a resistivity versus depth section along each profile.
The MT profiles show that the geothermal reservoir has a
lower resistivity than the background. This difference is largely
due to the higher temperatures and higher formation water
salinity. Based on the low resistivity signature, we estimate
that the field encompasses more than 200 km2, over half of
which lies offshore. Within the field, the MT profiles match the
known geology and borehole induction resistivity logs well.
The general stratigraphic section can be divided into three
vertical horizons: a shallow mud and silt cap rock, an upper
reservoir zone consisting of high temperature sand and clays
and a deeper, more continuous reservoir zone of consolidated
sand and silt.
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