San Diego Gas and Electric and its wholly owned subsidiary New Albion Resources Co. have been affiliated with Magma Power Company, Magma Energy Inc. and Chevron Oil Company for the last 2-1/2 years in carrying out geothermal research and development in the private lands of the Imperial Valley. The steps undertaken in the program are reviewed and the sequence that must be considered by companies considering geothermal research and development is emphasized. Activities at the south end of the Salton Sea and in the Heber area of Imperial Valley are leading toward development of demonstration facilities within the near future. The current status of the project is reported

Hinrichs, T. C.

English

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SAN DIEGO GAS & ELECTRIC COMPANY 
IMPERIAL VALLEY GEOTHERMAL ACTIVITIES: 
A STATUS REPORT 
Thomas C. Hinrichs 
San Diego Gas & Electric Company 
San Diego, California 
San Diego Gas & Electric and its wholly owned subsidiary 
New Albion Resources Co. have been affiliated with Magma Power 
Company, Magma Energy Inc. and Chevron Oil Company for the las t  
2 - 1 /2 years in carrying out geothermal research and development 
in the private lands of the Imperial Valley. The steps undertaken ' 
in the program will be reviewed and the sequence that must be con- 
sidered by companies considering geothermal research and develop- 
ment will be emphasized, 
Sea and in the Heber a rea  of Imperial Valley a r e  leading toward 
development of demonstration facilities within the near future. 
current status of the project will be reported. 
Activities a t  the south end of the Salton 
The 
Sari Diego Gas & Electric Company became interested in entering the 
geothermal arena in 1971. Two factors weighed heavily in making the decision. 
One was the realization that the availability of low cost natural gas fo r  boiler 
fuel in our electric power plants was to diminish very rapidly. The other factor 
was that the work being carr ied out in the Imperial Valley by the University of 
California Riverside team, under the sponsorship of the United States Bureau 
of Reclamation was demonstrating a potential geothermal resource within an 
economic distance of our Company's service area.  San Diego Gas  & Electric 
serves San Diego County and a portion of southern Orange County with their 
electric distribution sys tem. 
San Diego Gas  & Electric Company actually became involved in geothermal 
activities through an agreement with San Diego Gas & Electric Company's wholly 
owned resource subsidiary New Albion Resources Company (NARCO) and the 
Magma Power Company and Magma Energy Inc. 
in return for funding drilling and testing on Magma leases in the Imperial Valley 
NARCO could obtain an interest in the leases. 
The agreement provided that 
During early 1972 drilling was carried out in several areas  of the Valley 
to identify locations that appeared promising for development. 
ising a reas  were the Niland area  at the south end of the Salton Sea and the 
Heber a rea  south of the town of El  Centro. 
these locations to confirm the initial findings and also to provide a reinjection 
capability for flow testing. 
The most prom- 
A second well was drilled a t  each of 
194 
https://ntrs.nasa.gov/search.jsp?R=19750012775 2020-03-22T23:18:50+00:00Z
Flow testing at  the Niland site was carr ied out in mid-1972 with a large 
wellhead separator that was loaned to  us by the Union Oil Company. ’ The test  
performed provided information on well deliverability, fluid characteristics 
and other necessary information needed to initiate design work on a test  facil- 
ity to determine if power generation from the resource would be feasible. 
In August of 1972 the C. F. Braun Company of Alhambra, California, was 
contracted with to design and procure major  equipment for a geothermal tes t  
facility. The facility was designed on the binary system using a single steam 
flash with the steam and brine from the flash tank being directed through heat 
exchangers, which would heat isobutane. 
1973. A n  a rea  of uncertainty in the design was the longevity of the brine heat 
exchangers. The Company chose to run some small scale field tests prior to 
starting construction on the geothermal test  facility. 
This work was completed in early 
During 1973 a small scale test facility was constructed and installed at  
Figure 1 illustrates the flow diagram for the 1973 test  hard- 
Well fluids from the producing well entered the separator a t  150 psig. 
the Niland site. 
ware. 
Steam f rom the top of the separator passed through the heat exchanger, and 
brine leaving the bottom of the separator flowed through another heat exchanger. 
The temperature of both the s team and the brine was approximately 370°F. 
The mineral content of the geothermal brine from the Niland reservoir being 
produced was approximately 200,000 ppm. The solids in the steam leaving 
the test  separator were 40,000 to 80,000 ppm. In both the steam and brine 
exchangers heat transfer performance declined from an initial value to the 
design limits in approximately 100 hours of operation. 
Testing continued until the fall of 1973 and a satisfactory solution for  
mitigating the brine and steam scaling was not developed and starting of con- 
struction of the large geothermal test  facility was delayed. 
In early 1974 test  work was resumed to develop effective methods of 
separating s team from the geothermal brine and scrubbing the steam to achieve 
as pure a product as  possi-ble. 
Figure 2 shows the flow diagram of the 1974 test  apparatus, 
were completed during the summer of 1974, consisted of passing steam through 
separators, scrubbers and heat exchangers. 
scrubbing the s team would eliminate the severe scaling problems. 
Brine heat exchanger testing was discontinued. 
These tests, which 
The goal was to determine if 
The first phase of the testing consisted of evaluating different types of 
s team separators. The separator selected yields s team on the outlet with a 
solids content of approximately 200 ppm, thus yielding a reduction from the 
initial well fluid of 200,000 ppm. 
showing the interior of the vessel, 
second stage (50 psig) separators a r e  the same in configuration. 
enters the separator a t  the port  located in the bottom left side and impinges on 
the vessel end dome where a plate provides for protection of the vessel wall. 
Separator s team leaves through the upper port  at the right. Brine collects a t  
the bottom of the vessel and flows to  the second stage unit through the port a t  
the lower right of the figure.- 
Figure 3 is a cutaway view of the separator 
Both the f i r s t  stage (150 psig) and the 
Well fluid 
195 
Figure 4 illustrates the internals of the steam scrubber. Steam from the 
separator enters the scrubber through the lower left-hand port. The steam 
then flows upwards through five trays which hold pure water. The water con- 
tacting the s team scrubs entrained solids in the steam. Clean steam exits a t  
the top and wash water continuously added to the scrubber enters a t  the top of 
the vessel and cascades to the drain at  the bottom. During the 1974 tes t  the ' 
solids in the steam leaving the scrubber were 10 ppm to 20 ppm in comparison 
to the 100 to 200 ppm entering the scrubbers from the separator. 
Figure 5 illustrates the type of heat exchangers used during the test. 
f i r s t  stage heat exchanger utilized steam flowing on the outside of the tubes while 
the second stage utilized s team flowing through the tubes. Approximately 
1,000 pounds per  hour of steam for both the f i rs t  and second stage flowed 
through the heat exchangers and was completely condensed. 
was circulated in a closed loop through the heat exchanger to provide the cooling 
mechanism. 
The 
Distilled water 
Figure 6 illustrates some most encouraging results by comparing the 
overall heat transfer coefficient versus time of operation for the 1973 and 1974 
f i rs t  stage tests. 
operate for 3200 hours before reaching the design conditions requiring cleanup 
whereas the 1973 results reached the design condition in 108 hours. 
operating time for  the first stage heat exchanger during the 1974 test  was 
398 hours, which was sufficient to establish the trend to predict the number of 
hours of operating before reaching design. 
The 1974 test  results indicate the heat exchangers will 
Total 
Figure 7 shows similar data f o r  the second stage steam heat exchangers. 
1973 test  results indicated 81 hours to reach design conditions requiring clean- 
ing. 1974 tes t  data indicates the second stage heat exchangers will operate 
10,050 hours before reaching design conditions. Operating time for the second 
stage heat exchangers during the 1974 test was 587 hours. 
Figure 8 illustrates the flow diagram of what we anticipate the major 
geothermal test  facility to consist of, utilizing three stages of steam separation 
instead of two used during the recent small scale tes t  work. This three stage 
steam flash process would not make use of the brine in the heat exchangers, 
but rather would flash the brine to s team in three stages and then upon recon- 
densing the s team would be combined with the residual brine and reinjected in 
the injection wells. 
cleaned after separation a n d  run through heat exchangers against an isobutane 
working fluid which would power the turbine generator. 
& Electric Company has contracted with the Ben Holt Company of Pasadena to 
do the necessary redesign work on the geothermal test  facility and it is antici- 
pated that field construction will s ta r t  in early 1975. 
The steam would be passed through scrubbers to be further 
The San Diego Gas 
At the Heber location, following the .drilling of two wells by NARC0 and 
Magma Energy Inc. , Chevron Oil Company drilled a well on their adjacent lease. 
In 1973 the three companies entered into an acreage pooling agreement and a r e  
carrying out extensive testing in the Heber a rea  with Chevron acting as  operator 
for the parties. 
196 
I 
Because the resource at Heber i s  in the moderate temperature range the 
fluid must be pumped to enable a sufficiently high temperature to be maintained 
at the surface. The process anticipated to be applicable at Heber is  Magma 
Energy's Magmamax Power Process  illustrated in  Fig. 9. 
Since ear ly  this year Chevron has been operating two shaft driven pumps 
Through in two wells at Heber and injecting the pumped fluid into a third well. 
this operation valuable reservoir information has been accumulated and oper- 
ating experience in pumping gained. - -  
Recently San Diego Gas & Electr ic  Company has installed a heat exchanger 
tes t  module at the si te and i s  collecting information on heat exchanger perform- 
ance. 
(approximately 1/10 of the total dissolved solids) and i t  may be feasible that 
direct  heat exchanger operations can be performed with the Heber fluids. 
The Heber fluids are much l e s s  in salinity than the Salton Sea fluids 
With the information obtained f rom the well production activity Chevron 
Three additional wells have been is carrying out evaluation of the reservoir.  
drilled in the a rea  to gain more  needed information relative to reservoir poten- 
tial. An additional two months a r e  anticipated before the heat exchanger testing 
is completed. 
197 
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206 


San Diego Gas and Electric Company Imperial Valley geothermal activities

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