HomeMy WebLinkAboutSouthwest Alaska Regional Geothermal Energy Project NEA Application
Renewable Energy Fund Round 3
Grant Application
Application Forms and Instructions
The following forms and instructions are provided to assist you in preparing your application for
a Renewable Energy Fund Grant. An electronic version of the Request for Applications (RFA)
and the forms are available online at: http://www.akenergyauthority.org/RE_Fund-III.html
Grant Application
Form
GrantApp3.doc Application form in MS Word that includes an outline of
information required to submit a complete application.
Applicants should use the form to assure all information is
provided and attach additional information as required.
Application Cost
Worksheet
Costworksheet3
.doc
Summary of Cost information that should be addressed by
applicants in preparing their application.
Grant Budget
Form
GrantBudget3.d
oc
A detailed grant budget that includes a breakdown of costs by
milestone and a summary of funds available and requested to
complete the work for which funds are being requested.
Grant Budget
Form Instructions
GrantBudgetInst
ructions3.pdf
Instructions for completing the above grant budget form.
If you are applying for grants for more than one project, provide separate application
forms for each project.
Multiple phases for the same project may be submitted as one application.
If you are applying for grant funding for more than one phase of a project, provide
milestones and grant budget for completion of each phase.
If some work has already been completed on your project and you are requesting
funding for an advanced phase, submit information sufficient to demonstrate that the
preceding phases are satisfied and funding for an advanced phase is warranted.
If you have additional information or reports you would like the Authority to consider in
reviewing your application, either provide an electronic version of the document with
your submission or reference a web link where it can be downloaded or reviewed.
REMINDER:
Alaska Energy Authority is subject to the Public Records Act AS 40.25, and materials
submitted to the Authority may be subject to disclosure requirements under the act if no
statutory exemptions apply.
All applications received will be posted on the Authority web site after final
recommendations are made to the legislature.
In accordance with 3 AAC 107.630 (b) Applicants may request trade secrets or
proprietary company data be kept confidential subject to review and approval by the
Authority. If you want information is to be kept confidential the applicant must:
o Request the information be kept confidential.
o Clearly identify the information that is the trade secret or proprietary in their
application.
o Receive concurrence from the Authority that the information will be kept
confidential. If the Authority determines it is not confidential it will be treated as a
public record in accordance with AS 40.25 or returned to the applicant upon
request.
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SECTION 1 – APPLICANT INFORMATION
Name (Name of utility, IPP, or government entity submitting proposal)
Naknek Electric Association, Inc. (NEA)
Type of Entity:
501(c)(12) Not-For-Profit Electric Generation and Distribution Cooperative
Mailing Address
PO Box 118
Naknek, Alaska 99633
Physical Address
#1 School Road
Naknek, Alaska 99633
Telephone
907 246 4261
Fax
907 246 261
Email
dvukich@nea.coop
1.1 APPLICANT POINT OF CONTACT
Name
Donna Vukich
Title
NEA - General Manager
Mailing Address
Naknek Electric Association, Inc.
PO Box 118
Naknek, Alaska 99633
Telephone
907 246 4261
Fax
907 246 6242
Email
dvukich@nea.coop
1.2 APPLICANT MINIMUM REQUIREMENTS
Please check as appropriate. If you do not to meet the minimum applicant requirements, your
application will be rejected.
1.2.1 As an Applicant, we are: (put an X in the appropriate box)
X An electric utility holding a certificate of public convenience and necessity under AS
42.05, or
An independent power producer in accordance with 3 AAC 107.695 (a) (1), or
A local government, or
A governmental entity (which includes tribal councils and housing authorities);
Yes
1.2.2. Attached to this application is formal approval and endorsement for its project by
its board of directors, executive management, or other governing authority. If the
applicant is a collaborative grouping, a formal approval from each participant’s
governing authority is necessary. (Indicate Yes or No in the box )
Yes
1.2.3. As an applicant, we have administrative and financial management systems and
follow procurement standards that comply with the standards set forth in the
grant agreement.
Yes
1.2.4. If awarded the grant, we can comply with all terms and conditions of the attached
grant form. (Any exceptions should be clearly noted and submitted with the
application.)
Yes
1.2.5 We intend to own and operate any project that may be constructed with grant
funds for the benefit of the general public.
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SECTION 2 – PROJECT SUMMARY
This is intended to be no more than a 1-2 page overview of your project.
2.1 Project Title – (Provide a 4 to 5 word title for your project)
Southwest Alaska Regional Geothermal Energy Project
2.2 Project Location –
Include the physical location of your project and name(s) of the community or communities that will benefit
from your project.
Geothermal exploration and development will take place on a parcel owned by Naknek Electric Association,
Inc. The allotment resides within the Bristol Bay Borough in T17S, R44W, Section 131/2SW1/4 and Section
23, NE1/4NW1/4SM. Project related administration, accounts receivable and all accounting tasks will be
performed at NEA's headquarters building in Naknek, Alaska.
Geothermal Project Location Map
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Geothermal Project Distribution Network
Project Objectives: The Southwest Alaska Regional Geothermal Energy Project Phase s I and II will
identify and test the geothermal resource at the Pike’s Ridge site in King Salmon, Alaska for utility -scale
electric generation and district heating application. Although the project focuses on bringing firm, stable,
and reliable geothermal energy online in the region, additional value lies
in local project demonstration, manpower development and employment,
technology transfer and applicability to geothermal development in the
region.
In support of its goals to develop geothermal power NEA is currently
drilling a full-diameter well, Naknek-G #1. The planned depth and
completion for well G-1 is summarized in Figure 1. Because the
anticipated temperature gradient in the Naknek area is comparable to
most areas of the earth and does not appear to be elevated, this well will
be cased to 10,000 feet and drilled to a total depth (TD) of up to 14,000
feet. The production interval is anticipated to consist of Jurassic
crystalline basement rock, which will be found below Tertiary volcanics of
the Meshik Formation and probably the older sedimentary rocks of the
Stepovak Formation. Considering the lack of surface features that would
suggest the presence of a conventional hydrothermal resource, NEA is
preparing for the need to develop geothermal power using EGS
techniques. Therefore, the Naknek EGS project provides an opportunity
to demonstrate EGS technology in an environment that can support
higher energy costs than most places in the United States, and has
normal temperature gradients. These characteristics will enable the
Naknek EGS project to serve as a blueprint for EGS development not
only in the many remote regions of Alaska, but also across broad areas
of the United States that have normal temperature gradients.
The Southwest Alaska Regional Geothermal Energy Project is driven
forward by a particular set of circumstances relating to its demographics
and remote location. NEA is committed to pioneering geothermal
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development in service to the region and its environment, and has worked hard to make the program as
lean as possible without sacrificing integrity, either in terms of background science or project
implementation. Geophysical surveys were conducted and used to corroborate aeromagnetic surveys.
Based on confluent information a well was sighted and a drilling program designed to investigate a
greenfield environment. The resource confirmation and evaluation phase will test the validity and
interpretation of geophysical data. The project will demonstrate that geothermal energy technologies
including EGS can be applied in areas not normally considered for geothermal power development and
commercial implementation.
The project serves as a stepping stone to a regional geothermal power initiative for Southwest Alaska .
Poised both geographically and geologically for major economic productivity the transformation of natural
resources like seafood, oil, gas and minerals, into globally viable market commodities at the local level,
using geothermal energy will provide economic benefit to the region, state and the nat ion. Natural
resources, geology, proximity to international shipping lanes and the region's emerging role in the
international rush for control and exploitation of the Arctic make Southwest Alaska an attractive region for
public investment in geothermal development.
Project Scope: As part of the US Department of Energy’s objective of advancing the science, engineering
and practice of EGS, a comprehensive EGS field demonstration project has been proposed at Naknek,
Alaska. The Naknek EGS project is being undertaken to provide an alternative to fossil fuel for power
generation, thus ensuring predictable future energy costs , stabilizing communities in the region.
Consistent with DOE’s goals, this project seeks to characterize the region of Alaska lying b ehind the
volcanic arc, and will create and validate a sustainable EGS reservoir to initially supply a 25 MW geothermal
power plant. Long-term testing will be undertaken to enable scale-up to a project size of 50 MW or more,
which will supply an increased industrial demand and 30+ communities in Southwestern Alaska.
Phase I activities focus on characterizing the rocks encountered in well Naknek-G #1 in ways that will
facilitate the development of an EGS reservoir. A key element in the plan is the determination of stress field
orientation and the dominant mode of faulting in the area. Based on the tectonic history of this part of
Alaska, there was a compressional regime that resulted from active accretion, which resulted in the
formation of major NE-trending thrust faults. In more recent geologic time, these large, NE-trending fault
zones have changed to become both strike-slip and normal faults, and additional cross -faulting has
developed. Therefore, in Phase I of the project, the stress field will be evaluated using a variety of methods
including: 1) geology; 2) seismology to determine the mode(s) of faulting; 3) acquisition and analysis of
density and downhole image logs in well Naknek-G #1; 4) an extended leak-off test or “mini-frac”; and 5)
after installing an appropriate seismic monitoring network and developing a suitable protocol for induced
seismicity, the design, execution and analysis of a “pre-stimulation” injection test in well Naknek-G #1 to
confirm the direction of reservoir “growth” during the full stimulation that will be undertaken in Phase II.
After full stimulation, a second well would be drilled into the stimulated zone in Phase II, completing the
production-injection doublet. As the last steps in Phase II, the doublet would be tes ted for several months,
and the data from the test analyzed to permit modeling of future reservoir behavior and to make a
preliminary evaluation of the potential for scaling up to a larger development.
The Phase III goal is to generate 25 MW of geotherm al power to supply electricity and heating requirements
to three local communities and beyond as interconnection infrastructure is completed and continuous
monitoring for development of a scale-up plan based on analyses of long-term performance test data.
2.3 PROJECT TYPE
Put X in boxes as appropriate
2.3.1 Renewable Resource Type
Wind Biomass or Biofuels
Hydro, including run of river X Transmission of Renewable Energy
X Geothermal, including Heat Pumps Small Natural Gas
Heat Recovery from existing sources Hydrokinetic
Solar Storage of Renewable
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Other (Describe)
2.3.2 Proposed Grant Funded Phase(s) for this Request (Check all that apply)
Reconnaissance X Design and Permitting
Feasibility X Construction and Commissioning
Conceptual Design
2.4 PROJECT DESCRIPTION
Provide a brief one paragraph description of your proposed project.
Naknek Electric Association, Inc. is committed to lowering utility rates and the cost of living in the Bristol
Bay Region. To that end the utility has begun characterizing; developing and testing the geothermal
resource for production of utility scale electric, home heating and direct use applications. A transmission
network will extend the benefits of indigenous, clean and renewable energy to the region . The project will
create sustainable “New Energy” jobs during construction and career employment opportunities in
operations and maintenance throughout the life of the project. Long-term and regional in scope, both
energy generation and distribution aspects of the project are multi-phased to achieve near and long-term
economic development, energy security and independence. Initially a 25 MW generation plant, district
heating system and interconnection will serve eight communities in the Northern Bristol Bay area, and
later up to 50 MW for a larger region of Southwest Alaska. The project will increase economies of scale,
replace not displace the use of No.1 and No.2 diesel fuel, and reduce costly and potentially hazardous
transportation of fossil fuels along habitat sensitive waterways in Bristol Bay, home of the world’s largest
wild salmon runs.
2.5 PROJECT BENEFIT
Briefly discuss the financial and public benefits that will result from this project, (such as reduced fuel
costs, lower energy costs, etc.)
Project’s Ability to Offset Fossil Fuel Use
The primary driver for this project is to reduce the reliance on diesel power at Naknek and in other
communities in the Bristol Bay Region in Southwest Alaska. Naknek hosts the world’s premier salmon
runs, and most of its residents earn much of their entire year’s income during the summer salmon fishing
season. Exacerbating this situation, the need for heat and power are highest when income is lowest.
The alarming rise in diesel fuel costs and the resulting d ecline in the population are the primary drivers in
NEA’s search for a reliable, stably-priced alternative source of energy. That is the fundamental basis for
this project. Alaska is a young state with very little transportation infrastructure beyond a h andful of
population centers located along the railbelt. Building “New Energy” generation and transmission
infrastructure will allow exploitation of the region’s natural resources, seafood, oil and gas and minerals.
Bringing geothermal energy online in Bristol Bay will enhance economic and energy security by reducing
demand for high cost diesel and transportation fuels while decreasing the environmental liability and
associated regulatory compliance costs. Because of the extremely high energy costs in targeted
communities the project provides a unique opportunity for geothermal advancement in an environment
capable of supporting higher energy costs than most places in the US. At Naknek Electric Association,
Inc., diesel generation produces electricity at .43/kWh. In the cooperative’s service area alone the diesel
fuel surcharge reflected in electric rates charged to consumers from 2006-2007 increased by about 120%
or more than $150.00 per month for a typical residential customer. 2008 utility fuel cos ts surpassed 2007
records by 80%. 2009 costs are expected to remain stable. NEA belongs to the Western Alaska Fuel
Group; organized to exert purchasing power and control costs with coordinated fuel deliveries and bulk
purchasing. Even with this effort fuel prices increased 275% over a four-year period.
Alaska’s rural citizens in general and target communities specifically contribute larger portions of their
discretionary incomes to energy costs than urban counterparts, and are more conservative in their use.
End-user efficiency is not the issue. Home heating and electric generation represents 2/3 of the total
energy consumed by rural residents. Both industrial and residential consumers are dependent on a
single source of energy placing local communities at the mercy of a volatile global market. From a purely
socio-economic stand point regional communities are faced with an uncertain future. Out-migration is a
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major concern and a “eat or heat” sentiment is forcing rural populations off the land and int o larger rural
hubs and urban living situations where subsistence and cultural norms are not reinforced , placing
additional burden on housing, schools and social services. The situation is critical, a region and a culture
are at risk.
Regional geothermal energy generation will potentially displace 6 million gallons of diesel fuel used for
electricity and heating requirements. Over $15,000,000 per year in avoided fuel costs is a conservative
potential benefit estimate. Based on current fuel prices, NEA alone will see a $6 million dollar savings
annually. Stabilizing energy costs will foster economic development in the region’s resource based
industries, fishing and resource extraction. Tourism and service sector employment opportunities will
grow as will a perceived environment of security and well-being that is absent today as evidenced in
unprecedented outmigration
Project’s Role in Advancing EGS Technology
The Southwest Alaska Regional Geothermal Energy Project will advance EGS development and
demonstration technologies. There are many different types of site characterization and stimulation
activities that could be proposed. For the Naknek EGS project, we have focused on the essential
elements that will characterize the rock mass and enable an effect ive stimulation, based on previous
experience in enhancing permeability in deep reservoirs. The project will advance EGS development by
moving it beyond the hotter areas of the western US and into normal temperature gradient regimes,
particularly where high energy costs (as exist in Southwest Alaska) can support the higher drilling costs
required to reach greater depths and suitable temperatures for power generation. EGS has the potential
to provide a significant portion of the electrical energy requirement of the United States.
Climate Change
By reducing the demand for imported fuel and fossil energy related emissions the project will cut air
quality regulatory fees and costly band-aid solutions to emissions management. These costs will rise as
energy intense industries are held liable for environmental pollution. Air quality related savings due to
drastically reduced emissions in a geothermal system will shave $.01 / kWh from electric rates in NEA’s
service area. This benefit will increase as the costs of burning fossil increases.
Project’s Contribution to Understanding Regional Geology
Developing a geologic/geothermal model, including quantifying rock properties, stress, petrology and
mineralogy of target formations, etc., is a fundamental part of the proposed work that will benefit
geothermal development. Apart from the work undertaken by NEA (see Project / Site Characterization
document), there are no such existing data. That’s why the project will collect data to determine the
geologic model of the area in the course of drilling, logging and testing well Naknek -G #1, and Naknek-G
#2 and subsequent wells.
Renewable Energy Job Creation and ARRA
The project promotes the objectives of the American Recovery and Reinvestment Act of 2009 by creating
and preserving jobs in both the short-term and long-term, stimulating economic recovery through the use
of goods manufactured in the United States wherever possible, and assisting in demonstrating economic
efficiency through technological advancements in the renewable energy sector.
The Southwest Alaska Regional Geothermal Energy Project is providing renewable energy jobs in the
construction, drilling, engineering, consulting, operating and management of geothermal projects. As
owner of Drill Rig #7, NEA recognizes the importance of developing a workforce capable of operating
safely and efficiently on a geothermal drill site. In consultation with Alaska Department of Labor and
Workforce Development Division of Business Partnerships (DOL DBP) a pre-apprenticeship course is
being developed and 10 of the project’s local hires are daily attending 4 hours of classroom training
specific to Rig #7 and geothermal drilling operations, and 8 hours of on the job training.
Full apprenticeship course offerings will be tailored to meet the project’s workforce requirements . The
apprenticeship program will stress career path options, and prepare and retain workers in the geothermal
energy industry. High apprenticeship program enrollment numbers and accelerated learnin g and earning
behavior are likely program outcomes as trainees understand career path options. Training topics,
selected by veteran drillers, emphasize geothermal well drilling and provide trainees with basic
vocabulary, communication, task identification, safety awareness and skills required for safe and efficient
geothermal drill site operations. T he training course will provide survey and introductory information on
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well control and blow-out-prevention techniques as well as an opportunity to explore high-tech well
monitoring and testing.
NEA's geothermal drill site will host trainees at specified intervals during the 4 week course and facilitate
interface with professionals performing specialized drilling support operations. Trainees will complete a
certified Adult First Aid/CPR course, OSHA 10 and all other required safety certifications. Working with
SAVEC and the Alaska Department of Labor – Division of Business Partnerships, trainers will certify
course hours for college credits and apprenticeship requirement purposes. NEA will certify
apprenticeship on the job hours.
Davis-Bacon Act Assurance
NEA project management provides assurance that all employees whether compensated wholly or in part
by state and/or federal agency disbursement of public funds (ie. ARRA) are paid wages at rates not less
than those prevailing on projects of a character similar in the locality as determined by the Davis -Bacon
Act and that both applicant and project will comply with all provisions in the Act.
Economy of Scale - Transmission and Distribution
The annual cost of service for NEA is about $5.9 million. Of that, diesel fuel for generation amounts to
$3.5 million. With sales of 20,000 MWh annually the effective average cost of service for the residential
and commercial customers of NEA is .30/kWh, of which .18/kWh is fuel related. Under these conditions,
the net cost of NEA generation, transmission and distribution system is about .12/kWh. For a target
average cost of .13 /kWh the effective delivered cost to the NEA electric system for geothermal power
must be less than or equal to .01/kWh.
Geothermal systems in the “Lower 48” are expected to produce power at an effective cost of about
1.5/kWh. The cost of drilling production wells, transporting equipment and materials to Alaska, and
associated construction activities could result in busbar delivery costs two times higher or about .03/kWh.
The cost of energy would be about $585,000. However, provision of the hot water service and wholesale
power sales to regional utilities is expected to reduce that cost in return for undertaking the investment
and operating the facility. The expected utilization of the geothermal facility for the purposes of electric
sales to NEA would be about 50% (12 MW and annual energy of 22,000,000 MWh). Wholesale power
sales of the additional generation capacity to the regional utilities (increases sales to offset self -
generation of local commercial facilities) would offset costs, as would sales of thermal energy to offset
space and heating requirements. With a net O&M and carrying cost of the regional transmission system
of .05/kWh, sales of 15MW of the 25MW available would displace .18 power of other utilities. While the
full avoided cost is unlikely to be garnered by NEA, a reasonable assumption would be a margin on all
wholesale power sales. A geothermal facility of 25 MW installed in the NEA service area, would have the
capability of producing 155,700 MWh in excess of current NEA system requirements. Wholesale power
sales to regional utilities at a margin of but .03 / kW h will produce a cash flow of about $467,000 million,
offsetting NEA cost of energy.
Southwest Alaska Regional Geothermal Energy Project Resource Benefits
Preliminary Geothermal Impact Analysis – First Year Full Operation
Energy Resource Economics
Annual
Energy
MWh
Annual
Cost
NEA
Avg.
Rate
$000
¢/kW
h
Naknek Electric Distribution
System L
oad 12 MW
Annual Load Factor 20.5 % 21,550
Annual Non-Fuel System
Cost of Service 5,993 27.8
Annual Fuel Cost 15 kWh/gal
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2.50 $/gal 3,592 16.7
Naknek Average Cost per kWh
(net of fuel) 11.1
Geothermal Plant Capacity 25 MW
Plant Capacity Factor 85 %/yr
186,15
0
Geothermal Cost:
Nevada Facility 1.5 ¢/kWh
Alaska Differential (times 2) 3.0 ¢/kWh 21,550 646 3.0
Naknek Average Cost per kWh (all energy geothermal) 14.1
Potential Wholesale Power
Sales
Net Available for Wholesale
Gross MWh -
NEA
164,60
0
Energy 30 % of avail. 49,380
Margin Requirement (NEA) 10 % 148 0.7
Naknek Average Cost per kWh (after geothermal and wholesale power sales) 13.5
Other Revenues: Offset Fuel Oil Cost 4.00 $/gal*
30.30 $/MMBtu
B Btu
Heat Load Residential 700 homes
Fuel Displaced 100 gal/mo. 110.9 -3,360
Heat Load Commercial 100 buildings
Fuel Displaced 5000 gal/mo. 792.0 -6,000
District Heat Loop 15 mi.
Capital Cost (inc. conversion) 350 $000/mi.
Fixed Cost Recovery, 30 yr., 5%, $000 342
Operating Cost, 1% Capital 52.5 $000/yr.
Total Annual Cost 394
Avoided Fuel Cost 902.9 -8,966
Avoided Cost, Equivalent
¢/kWh* -3.4
Naknek Net Average Cost per kWh (after credit for heat sales) 10.1
* 1 kWh = 3413 Btu
2.6 PROJECT BUDGET OVERVIEW
Briefly discuss the amount of funds needed, the anticipated sources of funds, and the nature and source
of other contributions to the project.
DOE Cost-Share
Geothermal development is hampered by very high up-front costs. Government investment can
accelerate the development of geothermal energy resources by supporting initial exploratory drilling to
discover and confirm production potential. DOE’s Geothermal Technologies Program is focused on cost
cutting technologies for developing EGS and finding hidden geothermal systems. The Southwest Alaska
Regional Geothermal Energy Project was selected as one of only three Enhanced Geothermal System
(EGS) demonstration projects funded through the US Department of Energy Geothermal Technologies
Program by the American Reinvestment and Recovery Act. NEA’s EGS demonstration proposal
received a $12.3 million award.
Drill Rig #7 – In-Kind
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NEA has assumed $8.5 million in long-term debt to purchase Rig #7 which will be used as NEA match in
this proposal. Rig #7 day rates were established based on long-term debt, interest, and length of the
drilling season. In-kind value of Rig #7 is $2,750,409 million for Phases I and II Program Plans presented
in this proposal. Additionally, NEA established a $10 million line of credit to cover start-up and
encumbered expenses associated with drilling well Naknek -G #1.
Congressionally Directed Project Appropriation
The project is supported by Alaska’s federal delegation and thanks to sustained efforts by Senators
Murkowski and Begich, and Representative Young, two hard earmarks survived the legislative process
and $5.4 million has been appropriated in the 2009 and 2010 Water and Energy Bills through DOE’s
EERE.
Renewable Energy Fund Grant
NEA’s proposal to the Renewable Energy Fund Grant Program assigns $15,000,000 in state funding to
Phase I and II drilling activities. REFG investment in regional geothermal energy development will
reduce the burden to cooperative members who have assumed the up -front costs of exploration and
development. REFG funds will match DOE investment in the EGS demonstration project. REFG funding
will be applied to Phase I and II program development as specified in the proposal or as negotiated with
the funding agency.
The budget presented in the Grant Budget Form represents only the costs of Phase I and II program
development. They are based on actual quotes or, in instances where Phase I Program tasks have been
completed or are in progress, actual invoices where used in calculating cost estimates. Cost estimates
for subsequent phases are presented below to provide an overview of project phases and costs.
Southwest Alaska Regional Geothermal Energy Project – Phased Development
Project Resources Cost Share
Enhanced Geothermal Systems Demonstration
United States Department of Energy - Golden Field Office 12,376,568
Congressionally Directed Project - 2009 Water and Energy Bill
United States Department of Energy - Golden Field Office 2,854,500
Congressionally Directed Project - 2010 Water and Energy Bill
United States Department of Energy - Golden Field Office 2,500,000
NEA $5,400,000 - In-Kind Drill Rig #7 2,750,409
Research Scientist Stephen H. Hickman USGS
University of Wisconsin – In-Kind 25,000
Renewable Energy Fund Grant 15,000,000
TOTAL $35,506,477
Project Costs Costs
Phase III: Final Design and Permitting Construction
Resource Assessment - Permitting - EGS Testing 35,506,477
Phase IV: Construction, Commissioning, Operation, Reporting
Generation Facility - District Heating System 60,000,000
Phase V: Interconnection Phase I - 157 Miles 60,000,000
TOTAL $155,506,477
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2.7 COST AND BENEFIT SUMARY
Include a summary of grant request and your project’s total costs and benefits below.
Grant Costs
(Summary of funds requested)
2.7.1 Grant Funds Requested in this application. $15,000,000
2.7.2 Other Funds to be provided (Project match) $20,506,477
2.7.3 Total Grant Costs (sum of 2.7.1 and 2.7.2) $35,506,477
Project Costs & Benefits
(Summary of total project costs including work to date and future cost estimates to get to a fully
operational project)
2.7.4 Total Project Cost (Summary from Cost Worksheet
including estimates through construction)
$35,506,477
2.7.5 Estimated Direct Financial Benefit (Savings) $6,000,000
for NEA Fuel Annually
2.7.6 Other Public Benefit (If you can calculate the benefit in
terms of dollars please provide that number here and
explain how you calculated that number in your application
(Section 5.)
$328,000,000
SECTION 3 – PROJECT MANAGEMENT PLAN
Describe who will be responsible for managing the project and provide a plan for successfully
completing the project within the scope, schedule and budget proposed in the application.
3.1 Project Manager
Tell us who will be managing the project for the Grantee and include a resume and references
for the manager(s). If the applicant does not have a project manager indicate how you intend to
solicit project management support. If the applicant expects project management assistance
from AEA or another government entity, state that in this section.
Management Concept and Organizational Structure
NEA’s General Manager Donna Vukich is the project director and principal investigator. Ms. Vukich has
20 years of experience managing a small utility that each year experiences a highly variable load that
relates to the salmon fishing season, when the population and energy demand of the area increases by
nearly a factor of 5. With a proven track record of accomplishing complex and difficult tasks with limited
resources, she has driven a geothermal / EGS agenda from the start. Under the overall management of
NEA, the project has several sub-managers that will enable the proposed tasks to be conducted. For
geological interpretation and logistics for drilling, stimulation and testing operations, NEA has retained
Alaska Earth Sciences (AES). AES has overseen the interpretation of regional and local geologic data
and has provided both technical and logistical support to the drilling operation including mobilizing all the
needed subcontractors for specialized services. For permitting, NEA has retained The Castle Mountain
Group, which has significant experience in permitting oil and gas operations, and now, the first -ever deep
geothermal well in Alaska. GeothermEx will take the role of coordinating and managing the technical
activities associated with the EGS project, and has specified all of the activities in the EGS program.
GeothermEx will coordinate the efforts of the oth er EGS contractors during the project, and will compile
data from each to be included in reports and publications about the project. NEA management negotiated
a labor contract with ThermaSource who will provide drill rig operation and field supervision dur ing drilling
and testing operations. NEA’s company man Nick Scales and his relief, Dan Shearer, will manage the
site 24/7, provide contract services oversight and report regularly to NEA project management.
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3.2 Project Schedule
Include a schedule for the proposed work that will be funded by this grant. (You may include a
chart or table attachment with a summary of dates below.)
Start Completion
Technical Milestone Date Date
Concept Developmen:
1 Gather and review data 4/1/09 7/15/09
2 Prepare proposals 6/1/09 7/30/09
Funding Decisions 9/15/09
3 Agency Negotiations 10/1/09 10/31/09
Phase I Program Plan
0 Drill Naknek-G #1 8/1/09 11/20/09
1
Deploy temporary surface-based seismic array to collect baseline
seismic data, calibrate velocity model and prepare for later
stimulation
9/1/09 8/31/10
2 Mobilize geophysical logging equipment 8/15/09 9/15/09
3 Electric logging, 3,000-8,000 feet (sonic-gamma-density) 9/25/09 9/26/09
4 Mobilize PTS and pressure monitoring logging equipment 9/15/09 10/1/09
5 Electric logging, 8,000-10,000 feet (sonic-gamma-density) 10/14/09 10/16/09
6 Core and mini-frac (extended leak -off test) at 10,000 feet 10/22/09 10/26/09
7 Electric logging, 10,000-14,000 feet (sonic-gamma-density with
Stoneley wave and cross-dipole; FMI with gamma for correlation) 11/11/09 11/14/09
8 Core collection at TD (14,000 feet) 11/14/09 11/16/19
9
Pre-stimulation injection test using rig pumps, with TPS logging
and reactive tracer injection (air-lift/flow-back at end to recover
tracer)
11/17/09 11/20/09
10
Heat-up temperature profiles over ~6-8 weeks to enable
stabilized temperature and pressure (water rest level) data to be
obtained
12/1/09 1/31/09
11 Petrological/mineralogical analyses of cuttings from 10,000-
14,000 feet 12/1/09 1/31/10
12 Mechanical testing of cores from 10,000 and 14,000 feet 12/1/09 1/31/10
13
High-temperature reactor experiments on cuttings from potential
stimulation intervals to identify best agents for chemical
stimulation
12/1/09 1/31/10
14 Analysis of all logs (TPS, FMI, sonic), rock strength and mini-frac
data to develop stress model 12/1/09 1/31/10
15 Design of seismic monitoring system and permitting of ~6 core
holes for shallow downhole deployment of seismometers 1/15/10 2/28/10
16 Conceptual modeling of resource based on all data - FULL TEAM
MEETING 1/15/10 2/28/10
17
Progress Report: favorability of well Naknek G-1 for
stimulation (to enable funding for implementation of seismic
network)
3/1/10 3/15/10
Agency Feedback 3/31/10
18
Seismic monitoring system set-up (drill 6 shallow holes, install
equipment, calibrate system and velocity model, deploy 3
accelerometers for ground movement monitoring)
4/1/40 5/15/10
19 Pre-stimulation of well Naknek G-1 with thermally reactive tracer
injection and modeling to estimate fracture surface area 6/1/10 6/30/10
20 GROUP MEETING: Data integration and stimulation planning 7/1/10 7/15/10
21 Phase I Reporting
throughout
according to
Agency
requirements
7/31/10
22 Go / No-Go Decision Point: 1) favorability of Naknek G-1 for 8/1/10 8/15/10
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stimulation; 2) selection of site and depth for second well
(based on stress orientation and pre-stimulation results)
Agency Decision 9/15/10
Phase II Program Plan
1 Permitting and procurement for full stimulation 8/1/10 10/15/10
2
Chemical and/or hydraulic stimulation of well Naknek G-1;
seismic monitoring; post-stimulation injection test with detailed
TPS logging in Naknek G-1 and continued seismic monitoring
11/1/10 11/30/10
3 Integrated evaluation of stimulation results and finalization of site
and depth for new well 12/1/11 1/31/11
4 Go / No-Go Decision: Suitability of stimulated reservoir to
support drilling of second well 2/1/11 2/28/11
Agency Decision 3/31/11
5 Well design 12/1/10 12/31/10
6 Permitting and procurement 1/15/11 2/28/11
7 Road construction as needed; water supply to drilling site 9/1/10 11/30/10
8
Drill well G-2 following same EGS program (during and after
drilling) as in G-1. Downhole pressures to be monitored in G-1
while drilling G-2.
3/1/11 6/30/11
9
Heat-up temperature profiles over ~6-8 weeks to enable
stabilized temperature and pressure (water rest level) data to be
obtained
7/1/11 8/31/11
10
Geologic analysis of cuttings and core samples from new well;
mechanical testing of core samples; analysis of well logs;
evaluation of seismic data
7/1/11 8/15/11
11 Data integration and stimulation planning - GROUP MEETING 8/15/11 8/31/11
12 Progress Report: Suitability of new well to stimulation 9/1/11 9/15/11
Agency Decision 9/30/11
13
Chemical and/or hydraulic stimulation of G-2; seismic monitoring;
hydraulic monitoring in G-1; post-stimulation injection test with
detailed TPS logging in new well, continued seismic and hydraulic
monitoring
10/1/11 10/31/11
14 Integrated evaluation of stimulation results and design of
circulation test program 11/1/11 11/30/11
15 Progress Report: Suitability of circulation test plan 12/1/11 12/15/11
Agency Decision 12/31/11
16 Permitting and procurement for circulation testing 1/15/12 2/28/12
17 Circulation testing including tracer testing and fluid sampling 3/1/12 5/31/12
18 Analysis of testing results and modeling of future system behavior 6/1/12 7/31/12
19 Phase II Reporting
throughout
according to
Agency
requirements
8/31/12
20 Go / No-Go Decision: Suitability of enhanced reservoir for
geothermal power production 8/1/12 8/31/12
Agency Decision 9/30/12
3.3 Project Milestones
Define key tasks and decision points in your project and a schedule for achieving them. The
Milestones must also be included on your budget worksheet to demonstrate how you propose to
manage the project cash flow. (See Section 2 of the RFA or the Budget Form.)
Project Milestones are highlighted in 3.2 Project Schedule above.
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3.4 Project Resources
Describe the personnel, contractors, equipment, and services you will use to accomplish the
project. Include any partnerships or commitments with other entities you have or anticipate will
be needed to complete your project. Describe any existing contracts and the selection process
you may use for major equipment purchases or contracts. Include brief resumes and references
for known, key personnel, contractors, and suppliers as an attachment to your application.
Contract negotiations and the budgeting process have been approached very carefully, consistent with
NEA’s objective of getting the most information possible from the drilling, characterization and testing
activities in the program. For all major activities, multiple bids ha ve been sought to ensure fair pricing and
encourage competition. However, the lowest bid has not always been accepted; in some cases, the
experience of a contractor was deemed to be worth a higher cost. Other than for minor activities, all
costs presented herein are based on firm quotes from the contractors who will do the work.
The EGS team includes renowned experts in required fields: 1) conventional geothermal and EGS
resource drilling, characterization, testing and development (the GeothermEx team); 2) seismology and
active and passive seismic monitoring in volcanic areas (Stephanie Prejean of USGS and Clifton Thurber
of University of Wisconsin, and the e4sciences team led by Peter Malin); 3) stress analysis (Steve
Hickman of USGS and the team from GeoMechanics International); and 4) a pioneer in tracer
development and tracer test analysis (Dr. Peter Rose of University of Utah / EGI) is also a veteran of
several other EGS projects and long-term test programs. Wellbore logging (both geophysical and PTS
logging will be the domain of Baker Atlas, a firm with long experience and a great reputation for
commitment to data quality. Core testing and petrologic/mineralogic analyses will be conducted by
TerraTek, a world leader in these areas. Geological, logistical and environmental support is provided by
Alaskan experts Alaska Earth Sciences and The Castle Mountain Group. These entities have come
together to develop the plan described herein and execute a world-class EGS project in a remote area of
Alaska.
GeothermEx
In business since the early 1970s, GeothermEx is a world leader in geothermal resource development,
assessment and operations. GeothermEx’s involvement with Enhanced (or Engineered) Geothermal
Systems (EGS, also referred to as Hot Dry Rock or Hot Fractured Rock) began in the late 1990s in
support of a new effort by the US Department of Energy to advance the status of EGS technology. This
work included a technical evaluation of the results of the first-ever EGS project (at Fenton Hill, New
Mexico) and to identify sites for new EGS projects in the United States. Another major focus of this work
was to gain the interest and participation of the US geothermal industry in EGS developments, which was
approached by initially undertaking EGS activities in areas within or adjacent to existing hydrothermal
developments, thus advancing EGS techniques in locations where additional heat recovery can increase
the generation from existing projects. This approach was adopted in the first two DOE -supported EGS
field projects in the United States (Coso and Desert Peak).
Since 2003, GeothermEx has served as the technical manager of Ormat’s Desert Peak EGS project.
EGS techniques successfully used elsewhere are combined with GeothermEx’s long and practical
experience in the development and utilization of conventional geothermal resources to provide a practical
approach to EGS development. Novel well testing and well test analysis techniques have been
developed by GeothermEx to evaluate the characteristics and radius of the stimulated zone, and
numerical simulation techniques have been used to make the first comprehensive evaluation of the power
generation prospects. The latter work investigated a number of practical issues, including defining project
success criteria (net generation profile over the project life) and identifying the reservoir and operating
characteristics that have the most impact on long-term generation. The resulting estimations of heat
recovery and conclusions about the relative importance of d ifferent reservoir characteristics are much
cited in the EGS literature. In the field projects, GeothermEx serves as a liaison between the field
operator and numerous research organizations, enabling project activities to meet the needs of both
groups while advancing EGS technology. A successful mini-frac was recently completed in the target
well, which will be hydraulically stimulated later this year. GeothermEx has a similar role in Ormat’s
second EGS project at Brady's Hot Springs; this project is just getting underway.
In the Naknek EGS project, GeothermEx will provide technical support in nearly all tasks, and will take the
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role of integrating the various activities and analyses of multi-disciplinary data to ensure the best outcome
for NEA and DOE. Further, GeothermEx will have the lead role in well testing, well test / circulation test
analysis, and in modeling future reservoir behavior. In developing this proposal, NEA and GeothermEx
have focused on the essential elements of EGS development to pr ovide the best opportunity for
producing EGS power in a remote environment with a normal or near-normal temperature gradient. Ann
Robertson-Tait (Senior Geologist) will lead the effort and coordinate all work for GeothermEx. Eduardo
Granados (VP of Drilling Services) will take on all well design and drilling-related aspects of the work, and
Dr. Subir Sanyal (President and Manager of Reservoir Engineering) and the senior members of the
Reservoir Engineering staff will plan, execute and analyze all testing of individual wells, and the
circulation testing of the EGS doublet. Further, the GeothermEx reservoir engineering staff will develop a
numerical reservoir model for forecasting long-term behavior of the EGS reservoir.
GeoMechanics International - GMI
For its many commercial clients around the world, GMI has undertaken analyses aimed at understanding
the ambient stress environment and how it relates to natural resource development. Working mainly in
the oil & gas industry, GMI’s principals have pioneere d techniques aimed at evaluating fractured
reservoirs and estimating the pore pressures required to achieve effective results from hydraulic
stimulations. GMI has developed analytical techniques and specialized software for geomechanical
modeling and anal ysis; these will be employed in the Naknek EGS project. GMI has trained experts at
many resource companies in the fundamentals and applications of geomechanics to their particular
resource development issues. The GMI team will consist of the company principals Dr. Colleen Barton
and Dr. Daniel Moos, and Geophysicist Judith Sheridan, an expert in wellbore image log analysis and
interpretation.
e4sciences - Institute of Earth Science and Engineering - University of Auckland, New Zealand
Responsible for seismic monitoring system and analysis of MEQ data for the Naknek EGS, this team has
a long history of providing geological, geophysical and geotechnical evaluations in support of resource
development and major construction projects. Geothermal experience includes surface and/or borehole
MEQ monitoring in Krafla (Iceland), Wairakei (New Zealand), Longonot (Kenya), Mammoth / Long Valley
(California) and Puna (Hawaii), and MEQ monitoring of hydraulic stimulations for EGS projects in Basel
(Switzerland) and Paralana (Australia). This group has developed leading -edge hardware (seismometers
capable of withstanding temperatures to 200°C for long periods, ultra-slim seismometers for deployment
in the SAFOD hole drilled into the San Andreas Fault in California) and innovative MEQ analysis
techniques (shear-wave splitting tomography for estimating permeability anisotropy, joint analysis of
seismic and other geophysical data).
The design and implementation of the monitoring network, including the deployment of accelerometers in
the nearby communities, will be the domain of Mike Hasting and Daniel Rosales, veterans of numerous
similar projects, and data analyses will be undertaken by Dr. Peter Malin and Dr. Eylon Shalev of IESE.
For this project, a minimum 10 station seismic array will be deployed around the drilling site with a
maximum distance of about 4km, approximately one source depth, from the borehole location. The array
will be configured as a real-time network. Seismic ground motion data from each station will be forwarded
to a local field office where a data acquisition computer will record all waveforms and scan the data in
real-time for seismic events.
The primary objectives of the injection monitoring will be to provide NEA with a real -time picture of the
extent of micro earthquakes being produced during hydro-fracturing. Both the area and the direction of
fluid/fracture propagation will be determined. The injection monitoring data will also be processed later
using a double difference location algorithm to provide a detailed fracture propagation map. For this
purpose, a tomographic inversion model will first be developed for the velocity structure around the
borehole. e4sciences will evaluate the possibility of using first motions to determine micro earthquake
focal mechanisms, as well as trying to determine moment-tensor solutions for larger events. Standard
stress-drop calculations for the microseismic events will also be completed to allow better comparison of
the event sizes.
University of Wisconsin and the US Geological Survey
UW and USGS will install and maintain a 10-station temporary seismic array centered on the Naknek
geothermal site for passive MEQ monitoring. The array will be deployed for approximately one year
starting in late summer-early autumn 2009, spanning the time period of proposed mini-frac and
stimulation work. It will consist of 3-component stand-alone systems, mainly with short-period sensors
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but potentially one or two broadband sensors, powered by 12-volt batteries or air cells. Data will be
recorded continuously at a minimum sample rate of 100 samples per second. The array design is
intended to provide close-in recording to optimize detection of small, shallow earthquakes while having an
adequate array aperture and azimuthal distribution of stations to constrain the earthquake depths and
potentially infer focal mechanisms. The sites using 12-volt batteries will need to be serviced periodically to
swap in freshly charged batteries. Data will be downloaded at each visit to p ermit assessment of station
functionality and allow for on-going data analysis.
Several basic sets of seismic analyses will be carried out on the collected data. The seismic waveforms
will be integrated into a database allowing for preliminary automatic arrival time estimation and provisional
earthquake location. An initial seismic velocity model will be developed for locating events using
available geophysical and geological information. Borehole checkshot data would be particularly valuable,
for example. The primary focus will be on microearthquakes from the immediate vicinity of the site (i.e.,
within the array aperture), but we will also work with regional earthquakes, and possibly ambient noise, to
provide additional information on velocity structure. This preliminary processing will be followed by
waveform cross-correlation analysis and double-difference location to determine high-precision
earthquake locations. If the dataset permits we will also apply double -difference tomography to create 3D
models of the local seismic velocity structure. Earthquake focal mechanisms will be determined for
events with sufficient observations in order to constrain the stress field and identify potential fracture
planes.
Because the Alaska Earthquake Information Center cannot detect earthquakes smaller than M2.5 in this
area, we have no information on rates of small background earthquakes and no existing means to
monitor earthquakes induced through stimulation of potential geothermal resources. The analyses
proposed herein can provide detailed information on the seismic response to stimulation, local fault
geometries, the local velocity structure, and state of stress surrounding the site. In the best case scenario,
MEQs triggered by fluid injection during the stim ulation and mini-frac experiments might be used to track
paths of fluid propagation through the shallow crust.
The UW/USGS seismology team will be led by renowned seismologists Dr. Cliff ord Thurber (UW) and Dr.
Stephanie Prejean (USGS). Both are involved in seismic monitoring around active volcanoes along the
Alaskan volcanic arc. Another eminent USGS scientist will be part of the Naknek EGS team: Dr. Steve
Hickman, who will provide expertise in stress modeling. Dr. Hickman will conduct and evaluate th e mini-
frac (which enables the determination of the minimum horizontal stress) and will work with GMI to
integrate the analyses of well logs and develop the stress model of the field. Dr. Hickman has conducted
mini-fracs in about 100 wells, including more than 10 geothermal wells to date (at Desert Peak, NV; Blue
Mountain, NV; Coso, CA; Dixie Valley, NV). In addition, he has contributed significantly to the science of
EGS by presenting papers and workshops on the importance of understanding the stress env ironment
and working with the natural fracture population to develop underground heat exchangers.
University of Utah - Energy and Geoscience Institute
Dr. Peter Rose, a chemical engineer who has pioneered the development of tracers suitable for the
geothermal environment and has developed analytical techniques for tracer test data, will also participate
in the project. Dr. Rose’s role will be to supply thermally reactive tracers, manage the implementation of
tracer tests, and analyze tracer test data. Ne wly developed thermally reactive tracers will be injected into
the Naknek EGS wells, in the context of both single-well tests and a long-term circulation test, to enable
determinations of fracture surface area and swept reservoir volume. Dr. Rose has used similar
techniques in several EGS projects, including those at Coso (California), Desert Peak (Nevada), Soultz-
sous-Forêts (France) and Cooper Basin (Australia). Dr. Rose will identify the most effective agents to be
used in chemical stimulation, by undertaking mineral dissolution studies in EGI’s high-temperature reactor
and evaluating those results in the context of the specific mineral assemblages and vein fillings in the
Naknek EGS reservoir. This work will enable the selection of individual agents a nd combinations of
agents aimed at permeability enhancement via chemical reactions in the near -wellbore environment,
providing a complimentary method to hydraulic stimulation.
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3.5 Project Communications
Discuss how you plan to monitor the project and keep the Authority informed of the status.
Drilling operations are monitored by the project director Donna Vukich, NEA company man, Nick Scales,
AES project manager Gary Friedmann, and tool pushers. Current site and drilling operations status are
communicated daily at team meetings. Technical consultants and contract service representatives
teleconference these meetings when not on-site and are expected to resolve issues promptly. Drill rig
operators keep detailed safety and maintenance logs so issues can be communicated and addressed
properly.
Progress reports (based on project data) team meetings , go/no-go decision points, and reporting tasks
are built into the project management plan as presented above in 3.2 Project Schedule and will serve to
discuss, review, and evaluate resolution measures to any issues that may put the project at risk.
Stage-Gate Reports will be submitted at each of these points to enable the project to move forward with
full understanding of the basis for that decision. In addition, there are intermediate decision points
(referred to herein as “Progress Reports”) that precede the decisions to: 1) implement the seismic
monitoring network; 2) proceed with the stimulation of well G-2; and 3) proceed with the circulation
testing. In addition to the reports generated in connection with these decision points, quarterly agency
reporting will be undertaken throughout the project to keep everyone informed.
Well data and logging information will be kept on electronic medium and maint ained by management for
the life of the project.
3.6 Project Risk
Discuss potential problems and how you would address them.
Reservoir Characteristics
Geothermal energy development through the resource confirmation phase is high risk. Based on
resource characteristics generation design can mitigate some of the risks associated with less than
optimal resource temperatures, chemical composition, permeability and flow rates, but not all. The
development of new technology is in high gear to utilize the natural heat of the earth in efficient and cost
effective ways. Enhanced geothermal system technology development is one example. The only way to
know the characteristics of the reservoir is to confirm and qualify the resource with a deep drill program
that applies appropriate engineering and technology for cost effective development. This proposal seeks
investment, consultant and cooperative agreements between local, state, federal and private industry to
determine appropriate design and technology application through all phases of development maximizing
project success.
Adequacy and Extent of Characterization, Planning and Permitting at Proposed Site
In the absence of deep drilling data, the site characterization has involved regional and local geol ogic
interpretation, geochemical analyses of shallow wells, an MT resistivity survey, and a seismic survey.
These are all discussed and presented in the Project / Site Characterization document. The best
characterization data will be obtained during the drilling, logging and testing of well G-1, which will be the
first deep well in the region; the program presented herein focuses closely on this goal. A significant
effort has gone into planning the drilling program in the face of the logistical challenge s that come with
operating in remote regions of Alaska.
EGS Risks and Environmental Liabilities
To date, the environmental risks of the project have revolved around sit e construction and drilling
activities, for which The Castle Mountain Group is eminently qualified owing to its familiarity with
construction projects and oil and gas drilling operations throughout the state of Alaska. For the EGS
project, there will be an important additional environmental issue to manage: induced seismicity.
Together with e4sciences a plan is being developed to evaluate risks and inform the public. Although the
depth of stimulation (below 10,000 feet), the compliance of the overburden and the remoteness of the site
will serve as mitigating factors, the seismic monitoring program includes the deployment of
accelerometers in each of the 3 local communities, and NEA is planning its public outreach and
information program to develop a viable protocol for dealing with induced seismicity. The technical risks
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of the projects have been addressed by using experienced and reputable contractors that can deliver
what they promise. Further, the technical program includes no exotic or new technology but relies on
existing methods to achieve the ground-breaking objectives that drive this project.
Likelihood of Achieving Project Objective
The program includes a series of reasonable milestones for rational decision -making by NEA and funding
agencies throughout the project. The schedule is aggressive but achievable, and is driven by the desire to
advance the EGS project as quickly as possible, thus mitigating the deleterious effects of high energy
costs on the local communities and setting the stage for more geothermal development in the region. A
logical series of tasks have been pro posed that permit characterization, development and testing of the
EGS reservoir. These will be conducted by qualified contractors who are committed to the project.
Adequacy, Appropriateness and Reasonableness of Budget
The budgeting process has been approached very carefully, consistent with NEA’s objective of getting the
most information possible from the drilling, characterization and testing activities that are included. For all
major activities, multiple bids have been sought to ensure fair pricing and encourage competition.
However, the lowest bid has not always been accepted; in some cases, the experience of a contractor
was deemed to be worth a higher cost. Other than for minor activities, all costs presented herein are
based on firm quotes from the contractors who will do the work.
Appropriateness of Go / No-Go Decision Points
Agency input to the decision making process are anticipated before all major expenditures. Go/No -Go
points are reached: 1) at the end of Phase I to permit the project t o move into the stimulation phase; 2)
after the stimulation of well G-1 to enable a decision about moving forward with the drilling of a second
well; and 3) at the end of Phase II when a determination can be made about proceeding into the phase of
long term testing, power plant construction, and system operation / power generation. Stage -Gate
Reports will be submitted at each of these points to enable the project to move forward with full
understanding of the basis for that decision. In addition, there ar e intermediate decision points (referred
to herein as “Progress Reports”) that precede the decisions to: 1) implement the seismic monitoring
network; 2) proceed with the stimulation of well G-2; and 3) proceed with the circulation testing. In
addition to the reports generated in connection with these decision points, quarterly agency reporting will
be undertaken throughout the project to keep everyone informed.
Funding Support
Nationally, the negative spin on “Pork Barrel” funding may cripple successful investment in many projects
that are in the public’s best interest. Congressionally Directed Projects are sighted by those against
earmarking as a fraudulent use of federal funds. The Southwest Alaska Regional Geothermal Energy
Project is a Congressionally Directed Project and has received $5.3M specifically for drilling a deep
confirmation well. Those earmarked dollars are a substantial portion of the match in this proposal.
Funding for the project may be at risk because of the popular attitude toward “pork”. The upside,
renewable energy projects have considerable public support and the mandates for deep drilling
technology research and development are clearly evident in DOE funding.
Estimated Cost Overrun
Cost overruns are pandemic in grant funded projects. Project management experience and commitment
to cost control are evident in NEA’s ability to provide quality electric service at the lowest price consistent
with sound management. NEA’s financial management is note worthy in its commitment to r educe
spending and aggressively seek additional load which recently minimized the effects of a fisheries related
economic downturn in the region. NEA management has decades of experience with RUS borrower
requirements and government standard accounting, and reporting practices and consistently receives
unqualified opinions from auditors. The use of standard accounting procedures and record keeping and
reporting, diligent project monitoring and informed decision making will help prevent unnecessary cost
overruns. Cost estimates are guidelines for planning and in this project all estimated costs include
adjustments for location and transportation discrepancies. Although the remoteness of the site increases
both logistical complexity and costs, the team has developed and will implement a comprehensive EGS
program that includes all elements necessary to characterize the reservoir and plan and conduct
hydraulic and/or chemical stimulation. Sometimes this has required redundancies in equipment that are
not common in the Lower 48; for example, the logging unit will include back -ups of all required logging
tools and spare parts to ensure that the needed data are collected without undue delays to the project.
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Permitting and Regulatory Oversight
NEA has preliminary site control through ownership of the project site and approved access easements.
A drilling permit has been issued through the Department of Natural Resources Oil and Gas Division.
Regulatory compliance costs are anticipated, and compliance with AOGCC permitting stipulations have
been very high. As a greenfield exploration without precedence in the state regulators have been
challenged to initiate a process that ensures human safety and formation integrity without increasing
project costs that slow development.
Management recognizes the importance of permitting and regulatory compliance in keeping the project
moving forward and mitigating any circumstances that could result in costly delays. Development of a
road map and schedule for site development, well and generation facility construction, interconnection
network, environmental and ROW permitting, and all other regulatory compliance requirements will be
contractual and overseen by project management, corporate counsel and consultants.
Capital Equipment, Drilling Management and Material Acquisition
Drilling equipment availability, leasing and drilling project management contracting could pose significant
risks due to increased demand on capital equipment and manpower by new oil, gas and geotherm al
exploration projects. Cooperative agreements between the state and the oil and gas industry could
significantly decrease the risk.
Project Delays in Material and Capital Equipment Deliver
Individuals and organization doing business in remote Alask a anticipate delays due to weather and
transportation. Project management has experience and established working relationships with utility
industry vendors, barge service operators and local transportation companies, and after successful
negotiations for cost reductions from transportation vendors NEA management will continue pursuing cost
saving freight, handling and ground transportation rates for equipment and materials.
Interconnection ROW Permitting and Construction
Unanticipated delays in project completion caused by permitting and access could postpone the delivery
of affordable energy and magnify the problem in the region. Focusing on the distribution network, NEA
project management has begun a dialogue with land owners. Cooperation and open communication
between local, state, federal, private and native land owners, permitting agencies is being fostered.
SECTION 4 – PROJECT DESCRIPTION AND TASKS
Tell us what the project is and how you will meet the requirements outlined in Section 2 of the
RFA.
The level of information will vary according to phase(s) of the project you propose to
undertake with grant funds.
If you are applying for grant funding for more than one phase of a project provide a
plan and grant budget form for completion of each phase.
If some work has already been completed on your project and you are requesting funding for
an advanced phase, submit information sufficient to demonstrate that the preceding phases
are satisfied and funding for an advanced phase is warranted.
4.1 Proposed Energy Resource
Describe the potential extent/amount of the energy resource that is available.
Discuss the pros and cons of your proposed energy resource vs. other alternatives that may be
available for the market to be served by your project.
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Project Description Phase I and II Program Tasks
Phase I Program – Description and Tasks
0
Drill well Naknek-G #1. This well is scheduled to spud on 8 August 2009, and will take approximately 4
months to drill and test. A detailed series of EGS procedures during and after drilling are planned, as
described below.
1
Passive seismic array. A temporary surface-based seismic array will be deployed to collect baseline seismic
data, calibrate the seismic velocity model, and prepare for later stimulatio n. Waveforms will be integrated into
a database allowing for preliminary automatic arrival time estimation and provisional earthquake location. An
initial seismic velocity model will be developed for locating events using available geophysical and geolog ical
information. The primary focus will be on MEQs from the immediate vicinity of the site, but regional
earthquakes and possibly ambient noise will also be evaluated to provide additional information on velocity
structure. This preliminary processing will be followed by waveform cross-correlation analysis and double-
difference location to determine high-precision earthquake locations. If the dataset permits, double-difference
tomography will also be employed to create 3D models of the local seismic velocity structure. Earthquake
focal mechanisms will be determined for events with sufficient observations in order to constrain the stress
field and identify potential fracture planes. These analyses can provide detailed information on the seismic
response to stimulation, local fault geometries, the local velocity structure, and state of stress surrounding the
site.
2 Mobilization of geophysical logging equipment. Downhole geophysical logging equipment will be
mobilized to the Naknek G-1 well site to enable logging of all critical intervals.
3
Logging from 3,000 - 8,000 feet. Drilling will reach a depth of 8,000 feet. Before setting and cementing
casing, run sonic velocity and density logs (with gamma for log correlation in the interval from 3,000 -8,000
feet. Sonic logs will permit development of velocity model for later use in relocating micro -earthquakes
(MEQs) and the estimation of rock strength; density logs will be integrated to determine the magnitude of the
vertical stress (SV).
4
Mobilization of Pressure-Temperature-Spinner (PTS) logging equipment. PTS and pressure monitoring
logging equipment will be mobilized to the site in advance of reaching the next casing point at 10,000 feet,
where an extended leak-off test or “mini-frac” will be performed (downhole pressure and temperature
monitoring to be conducted during mini-frac). The equipment will stay on-site for the wellbore heat up period
and for the later monitoring of pressure and PTS profiling during and after stimulation.
5
Logging from 8,000 - 10,000 feet. Drilling will reach a depth of 10,000 feet. Before setting and cementing
casing, run sonic velocity and density logs (with gamma for log correlation) in the interval from 8,000 -10,000
feet, for same reasons as stated in Task 3 above.
6
Core collection and mini-frac at 10,000 feet. After setting and cementing casing, collect a 30-foot core
below casing shoe. Cores will be analyzed in two ways: 1) for mechanical properties; in combination with
sonic log data and mini-frac data, rock strength can be extrapolated throughout the open interval using the
results of this core testing; and 2) for macroscopic inspection of fractures to estimate fracture density, identify
vein-filling minerals and compare with wellbore image logs (see Task 7). Also, undertake an extended leak -off
test (“mini-frac”) in cored interval to estimate the magnitude of the minimum horizontal stress (SHmin). This
value is a fundamental element of the stress model; together with the estimate of the magnitude of S V, the
mode of faulting (normal, strike-slip or transitional between the two) can be determined.
7
Logging from 10,000 – 14,000 feet. Well G-1 will reach a depth of up to 14,000 feet (TD). In the open-hole
section below 10,000 feet, run the same suite of logs as for the previous two intervals, but run the sonic tool in
more comprehensive modes to enable additional interpretation of formation properties: 1) Stoneley wave
mode (to estimate shear modulus, identify permeable fractures and their properties, and to identify variations
in matrix permeability); and 2) Cross-Dipole mode (to determine shear-wave velocity anisotropy perpendicular
to the wellbore and identify and orient important fractures in the near -wellbore environment). In addition, run
wellbore image log to image borehole breakouts and drilling-induced tensile cracks (thus determining the
orientation of the stress field) and to characterize the orientations and dips of natural fractures (to estimate the
relative numbers of fractures that are oriented close to the direction of the maximum horizontal stress (SHmax)
and will therefore shear most readily upon increasing pore pressure during hydraulic stimulation).
8 Core collection at TD. Collect core collection at TD (estimated to be 14,000 feet) for the same purposes as
described in Task 6.
9
Baseline injection testing. After completing the well, undertake a baseline step-rate injection test using the
rig pumps and/or cementing pumps. Downhole pressure will be monitored during the test. PTS loggin g will be
conducted at slow (~25 feet per minute) and normal (~100 feet per minute) speeds during each rate step.
Thermally reactive tracer will be injected and later recovered either by air -lift or flow-back at the end of the test
to get initial estimate of fracture surface area. This is the last step of the program to be performed with the rig
on the hole - - the next 7 tasks are aimed at analyzing the data collected during and immediately after drilling.
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10
Heat-up temperature surveys. PTS logs will be run periodically (3 logs are planned over an 8-week period)
as the well heats up. This will provide stable formation temperature and pressure (water rest level) data for
both stimulation planning, power plant design and pump calculations and specificat ion (we envisage that the
production well will be pumped).
11
Petrologic / mineralogic analyses. Cores and cuttings from 10,000-14,000 feet (open-hole interval) will be
the subject of petrologic/mineralogic analyses undertaken by a reputable commercial l aboratory (TerraTek or
similar). This task will enable the lithologies within the target interval to be identified, and the primary and
secondary mineralization to be determined. At specified intervals, thin sections will be prepared and analyzed
and whole rock XRD analyses will be undertaken to determine chemical composition and clay content. This
permits characterizing the rock units in the target interval in terms of composition and texture, and initiates the
process of determining which chemical stimulation agents may be used and/or if adjustment of the stimulation
fluid composition will help retain the mechanical stability of the targeted formations.
12
Determination of mechanical properties from cores. The cores to be collected from 10,000 and 14,000
feet will be tested by a reputable commercial or university laboratory to determine their mechanical
characteristics, including compressive strength, elastic moduli, and thermal expansion coefficient. Other than
those to determine thermal expansion, all tests will be conducted at room temperature and over a range of
confining and pore pressures that bracket in-situ conditions. Sonic log data will be used to extrapolate these
properties through the target stimulation interval.
13
High-temperature reactor experiments. This task is directed at planning for chemical stimulation to improve
near-wellbore permeability and access to the reservoir at large. High-temperature reactor experiments on
cuttings from the open-hole interval will be undertaken to identify which agent or combination of agents will
work best to dissolve fracture and vein fillings, thus facilitating hydraulic stimulation and/or wellbore inflow
performance.
14
Stress modeling. The logs collected in well G-1 (PTS, sonic, density, and wellbore image logs) will be
analyzed jointly with certain critical drilling parameters (mud weights, etc), the estimate of S Hmin from the mini-
frac and the core testing results to develop the stress / geomechanical model of the Naknek system. This task
will be undertaken by a leading contractor with significant expertise in both oil & gas and geothermal projects,
with support and input from outside stress experts.
15
Design seismic monitoring system. Guided by the passive seismic monitoring, stress model, sonic log data
and the VSP results, the seismic monitoring system will be designed. The preliminary design shallow
downhole deployment in 6 shallow holes (~150m deep) and 4 surface mounted stations covering a radius of
approximately 4 km around the well. This task will include initiating and following up on all necessary
permitting activities that will enable the deployment of seismometers around the well site. In addition, the
induced seismicity protocol will be developed.
16
Conceptual resource modeling. A full team meeting will be convened to critically evaluate all data collected
from well G-1. This will include conceptual modeling of resource (based on data from geophysics, mineralogy
and rock geochemistry, stratigraphy, structure, fluid chemistry, permeability, fractures, geomechanics, in situ
stress, etc.) and assignment of tasks for preparing a Progress Report to
Funding Agency
17
Progress Report. This report will present data related to the overall favorability of well G-1 for EGS
stimulation, providing a rational basis on which to proceed with the implementation of the seismic monitoring
network that was designed in Task 15.
Agency Feedback
18
Seismic monitoring system set-up. Although the final design will be determined in Task 15, we currently
envisage that this task will include the drilling of 6 shallow boreholes for downhole deployment. As part of this
task, the equipment will be obtained, shipped to the site, installed, calibrated and tested. In addition, 3 radio -
linked accelerometers (one each in the communities of Naknek, South Naknek and King Salmon) will be to
monitor ground movements as part of the induced seismicity protocol.
19
“Pre-stimulation” of well G-1. This will be a short injection undertaken at pressures that will induce some
shearing, to confirm the primary direction of reservoir growth and calibrate the seismic network. As during the
baseline injection test, thermally reactive tracer will be injected and sampled during the post -injection flow-
back, providing a second estimate of fracture surface area.
20
Data integration and stimulation planning. A full team meeting will be convened to review the results of the
pre-stimulation and seismic monitoring and assign tasks for preparation of the Stage -Gate report that Funding
agencies will require to enable the project to move into Phase II.
21
Phase I Reporting. Reports and other deliverables will be provided in accordance with the Federal
Assistance Reporting Checklist, following the instructions included therein. In addition, papers will be
prepared for presentation and publication at various meetings and symposia, as appropriate.
22
Go / No-Go Decision Point. The decision about whether or not to proceed to Phase to will depend primarily
upon: 1) the favorability of well G-1 for stimulation; 2) the stimulation plan that is submitted; and 3) the
selection of the target for second well in the EGS doublet, based on stress orientation and pre -stimulation
results. A Stage-Gate Report will be prepared and submitted to funding agencies for review.
Agency Decision
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Phase II Program – Description and Tasks
1
Permitting and procurement for full stimulation. Vendors will be solicited for quotations, logistical and
transportation elements will be resolved, and all necessary permits will be obtained to implement the full
stimulation. An adequate water supply for the stimulation (which will require several million gallons) will be
developed.
2
Chemical and/or hydraulic stimulation of well G-1. Although the stimulation design will be finalized in
Phase I Task 20, at present we are considering that both chemical and hydraulic methods will be applied. It is
likely that chemical stimulation will precede hydraulic stimulation, thus increasing near-wellbore permeability
and improving the ability to access and increase pore pressure in the reservoir at large. The stimulation will
be conducted with seismic monitoring and installation and monitoring of accelerometers in the nearby
communities before, during and after the treatment. A post-stimulation step-rate injection test with detailed
TPS logging will be conducted, similar to that in the baseline injection test (Phase I, Task 9), including reactive
tracer injection and flow-back for re-estimation of fracture surface area. Using data from this test, a well-test
analysis method developed in another DOE-funded EGS project will be applied to estimate the hydraulic
properties of the stimulated volume and the un-stimulated region beyond, and to estimate the radius of the
stimulated zone.
3
Evaluation of stimulation results and identification of drilling target for well G-2. Although seismic data
will be collected and evaluated in near-real-time during the stimulation, there will a period of post-stimulation
seismic data processing that will result in more accurate MEQ locations and elucidation of geologic structures
in the subsurface that will influence the selection of the target for the second well. Injection and tracer testing
results will also be integrated into the well targeting process.
4
Go / No-Go Decision Point. This decision will be made to determine the suitability of the stimulated reservoir
to support the drilling of second well, and will permit the project to move ahead. A Stage-Gate Report will be
prepared and submitted to funding agencies.
Agency Decision
5
Design of well G-2. In accordance with the target selection and analyses of previous results, a well design
will be prepared. It is possible that well G-2 may be drilled from the same surface location as well G-1; in this
case, well G-2 will be drilled directionally into the stimulated zone. An alternative surface location will be
identified and chose if this approach is not viable. The drilling program will be prepared for submission to the
appropriate regulatory agencies.
6
Permitting and procurement for well G-2. The drilling program and associated documents will be submitted
for permitting by ADNR. The required services will be contracted, and all needed equipment will be mobilized
to the site.
7
Road construction and water supply. If necessary, a new access road will be constructed to reach the
drilling site (this will not be needed if the well can be located adjacent to well G-1). A water supply for drilling
and testing operations will be developed as needed.
8
Drilling of well G-2. The drilling will include many of the same EGS data collection activities as conducted in
well G-1; the specific EGS-related activities to be undertaken while drilling well G-2 will be specified in the
Stage-Gate Report described in Task 4 above. Post-completion injection testing will be conducted, similar to
that described in Phase I Task 9 (step-rate injection test with PTS logging and pressure monitoring, and
reactive tracer injection and flow-back). In addition, we will monitor pressures in well G-1 during the drilling of
G-2 to detect any pressure pulses transmitted through the enhanced fracture system.
9 Heat-up temperature surveys. PTS logs will be run periodically (3 logs are planned over an 8 -week period)
as the well heats up, as described in Phase I Task 10.
10
EGS analyses of well G-2. As for well G-1, this will include petrologic/mineraolgic analyses of cuttings and
core samples, mechanical testing of cores; and analysis of well logs to flesh out the stress model and prepare
for stimulation, if needed.
11
Data integration and stimulation planning. A full team meeting will be convened to review the results of the
drilling and follow-on analyses and preparation of a Progress Report to funding agencies prior to stimulating
the well, if needed.
12 Progress Report. This report will discuss the data analyses that indicate whether or not the second well
requires stimulation (for planning and budgeting purposes, we are assuming that stimulation wil l be needed).
Agency Decision
13
Chemical and/or hydraulic stimulation of well G-2. As for well G-1, at present we are considering that both
chemical and hydraulic methods will be applied, following the same plan described in Phase II Task 2 (i.e.,
with seismic monitoring, post-stimulation step-rate injection test with detailed TPS logging and reactive tracer
injection, etc. In addition, we will continue to monitor pressures in well G-1 during stimulation of G-2.
14
Integrated evaluation of results and design of circulation test program. A full team meeting will be
convened to review the results of drilling, testing, and stimulation of well G-2, and the observed pressure
responses in well G-1. From this evaluation, a circulation test plan will be developed for a 3-month circulation
test that will include tracer testing, PTS logging and pressure monitoring in the injection well (we assume that
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the production well will be pumped, which will preclude downhole pressure monitoring), and the application of
variable flow and injection rate steps, and various pressure transient testing methods to help understand the
long-term operation of the system.
15 Progress Report. This report will present the circulation test plan in detail, providing a rational basis on which
to proceed with the circulation testing.
Agency Decision
16 Permitting and procurement for circulation testing. Any additional permits needed will be obtained, and all
needed testing equipment will be sourced and mobilized to the site.
17 Circulation testing. A three-month circulation test will be conducted, including tracer testing and fluid
sampling at the production well (for both tracer analysis and evaluation of reservoir fluid chemistry).
18
Analysis of circulation testing results. The team will evaluate the results of the testing and the implications
for both long-term operation of the system. Numerical modeling will be undertaken to evaluate future
performance and consider the possibility of scale-up to a project size that would support power generation for
communities in southwestern Alaska beyond the Naknek area.
19
Phase II Reporting. Reports and other deliverables will be provided in accordance with the Federal
Assistance Reporting Checklist, following the instructions included therein. In addition, papers will be
prepared for presentation and publication at various meetings and symposia, as appropriate.
20 Go / No-Go Decision Point. Suitability of enhanced reservoir for geothermal power production
Agency Decision
4.2 Existing Energy System
4.2.1 Basic configuration of Existing Energy System
Briefly discuss the basic configuration of the existing energy system. Include information about
the number, size, age, efficiency, and type of generation.
The information presented below is a snapshot of the NEA facility and operations. Nushagak Cooperative,
Inc. has a similar profile. Other regional stand-alone diesel generation and distribution facilities have poor
economies of scale, and less efficient and hig her cost profiles.
NEA’s generation plant was first energized in November 1960. The utility is primarily engaged in
generation and distribution of electricity to the target communities, Naknek, South Naknek, and King
Salmon. The utility currently maintains the following operations:
10.3 MW diesel generation plant
10 generation sets
7.2 KV and 14.4 KV distribution lines
90 miles of distribution
Service to three communities
District heating to school, clinic, ambulance garage, pool, residences and NE A facility
1,049 meters
Service agreement with two neighboring utilities
Service to large power seafood processors
Service to government consumers, United States Air Force, Federal Aviation Administration, United
States Fish & Wildlife Service, Alaska Department of Fish & Game, United States Weather Service,
National Park Service
Service to Bristol Bay commercial fishing, sport fishing and tourist industry
Just under 20,000,000 kWh were sold in 2007
Newest engine was installed in 2005 and the oldest, a White Superior, was installed in 1974
Efficiency 15.1 kWh / gallon
24-hour plant
The generation facility consists of a steel building containing ten diesel generator sets, control panels and
feeder switchgear, situated on 3.66 acres owned by the cooperative. Fuel, battery, cooling, ventilation,
and recaptured heat systems are housed in the generation building. A separate building houses
distribution inventory and equipment. Construction costs of a new vehicle maintenance facility are included
in NEA’s 2009 capital budget. The generators are fueled from a 2.1 million gallon capacity DEC compliant
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tank farm s located directly behind the generation plant, inside the fence on NEA property.
4.2.2 Existing Energy Resources Used
Briefly discuss your understanding of the existing energy resources. Include a brief discussion of
any impact the project may have on existing energy infrastructure and resources.
Regional baseload electric generation, heating and transportation energy requirements are fueled with
diesel and gasoline. Grant assisted new energy infrastructure development will make the near-term
transition to an energy independent future possible. Yes, the region is highly invested in diesel generation
and petroleum fueled transportation systems, but many small stand-alone diesel generation facilities are
unable to bear the costs of fuel and are becoming a liability to the state. The electric generation industry as
a whole is approaching the point in the cost-benefit analysis where renewable energy system development,
even with initial capital intense investments, is feasible. Concerns in the region about energy costs, the
environment and the political attitude toward climate change are making geothermal energy development
not only necessary but desirable. Renewable energy alternatives should be developed for Alaskans, used
and managed locally with state supported one-time capital investment for generation and interconnection
infrastructure. HB 152 Alternative Energy Grant Fund is a giant step in the right direction and must be
followed by sustained commitment to the prospect of renewable energy for Alaska. Renewable alternative
energy policy makers should look 50 years into the future and understand that these kinds of projects are
pathways to unlocking hydrogen’s potential and a renewable energy future.
4.2.3 Existing Energy Market
Discuss existing energy use and its market. Discuss impacts your project may have on energy
customers.
The cost of electricity in Southwest Alaska is high by a ny standard. Nearly all electrical power is provided
by stand-alone diesel generation systems. That same fuel provides most space and water heating
requirements. Southwest Alaska communities are in trouble. High energy costs are destabilizing rural
population and as a result, village life and culture are in decline. Schools are closing, businesses are
failing and residents are moving to larger hubs and cities increasing demand on resources already
struggling to keep up with population increases. Lowering and stabilizing the cost of energy will radically
improve local economies, enhance resource development, expand employment opportunities and stem
outmigration.
Significant returns are anticipated from quality enhancement and local value -added manufacturing in the
seafood industry. Project management knows the value of the fishery in Bristol Bay. With cost -effective
energy on-shore processors have indicated that local secondary manufacturing processes are feasible.
Low cost energy would allow affordable icing infrastructure and cold storage options for large and small
seafood processors for improved quality and price. There will be many economic development
opportunities, both direct and indirect, with affordably energy that will help return the regio n to its once
independent and self-sufficient status.
Southwest Alaska is poised both geographically and geologically for major economic productivity. Potential
oil and gas lease sales in Bristol Bay, strategic mining development in the Lake Iliamna regi on, value-
added manufacturing opportunities in a sustainable commercial wild salmon industry, world class trophy
hunting, sport fishing and tourism should be powered by locally produced renewable energy. How we
develop energy capacity and for who renewabl e resources are exploited are questions that must be
addressed by all stakeholders. Transforming strategic natural resources like seafood, oil, gas and
minerals, into globally viable market commodities locally using geothermal energy will provide economic
benefit to the region, state and the nation
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4.3 Proposed System
Include information necessary to describe the system you are intending to develop and address
potential system design, land ownership, permits, and environmental issues.
4.3.1 System Design
Provide the following information for the proposed renewable energy system:
A description of renewable energy technology specific to project location
Optimum installed capacity
Anticipated capacity factor
Anticipated annual generation
Anticipated barriers
Basic integration concept
Delivery methods
The Southwest Alaska Regional Geothermal Energy Project has 6 major phases of development. Phase I
Interconnect from King Salmon to Dillingham and 5 communities is 157 miles long with 6 substations.
Phase I Interconnection Infrastructure is designed but engineering and ROW permitting is incomplete.
Survey and design of Phase II Interconnect from King Salmon to Egegik is 50%. Project management is
submitting information on Phases I-VI including project timeline, tasks, milestones and cost estimates in
this proposal. NEA project management is in communication with BLM and DNR regarding access to the
proposed interconnection network.
Other renewable energy resources viable in the region are not firm / baseload and require 100% firm
power back-up or are not considered reliable.
Southwest Alaska Regional Geothermal Energy Project - Naknek Estimated Resource Potential
Temperature of Shallow Resource (Mt Martin shallow temperature used): 94°C
Depth of Shallow Resource: Unknown
Temperature of Deep Resource: 200°C
Depth of Resource: 10,000 ft
Capacity of Resource or Flow: Unknown
Distance From Load or Intertie: 2 Miles
Size of Project: 25 MW
Road Miles Needed: 2 Miles
Transmission Line: Phase I King Salmon to Dillingham and 5 Communities 157 Miles
Deep Resource Assumed Temperature: 392°F
Estimated Potential MW/Well: 4.34 MW
Number of Production Wells Needed: 6
40% Success Rate: 8
Geothermal Energy Project Components
25 MW geothermal generation facility + 12.5 MW capacity additions with demand/growth
Gathering field
Binary system
District heating system for domestic hot water and home heating application
Project integration utilizing existing distribution systems in the region
Phased construction of 34.5 KV interconnection infrastructure delivering wholesale power
450 miles of phased construction of interconnecting infrastructure linking 25+ communities
157 mile Phase I Interconnection links King Salmon to Dillingham and 5 other communities
Initial Load: 18 MW with full potential to use 25 MW within two years and 50 MW with growth
4 miles of distribution line upgrade from single phase to three phase
50% capacity factor with geothermal generation
100% capacity factor with hydrogen production
Hydrogen storage facility
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District Heat System Components
Production of geothermal fluids from production wells and gathering field
Holding tanks
Production pumps
Valves
Heat exchangers
Closed district heat loop
Above ground pre-insulated pipes with leak detection
Metering and billing system integration with current operations
Reinjection pump
Renewable energy system integration for reliability and efiiciency
4.3.2 Land Ownership
Identify potential land ownership issues, including whether site owners have agreed to the
project or how you intend to approach land ownership and access issues.
NEA owns the 120 acre parcel and has full site control through permit acquisition.
A copy of the deed is included as an attachment to this proposal.
4.3.3 Permits
Provide the following information as it may relate to permitting and how you intend to address
outstanding permit issues.
List of applicable permits
Anticipated permitting timeline
Identify and discussion of potential barriers
Naknek-G #1 is currently being drilled as the project moves forward. The project site is situated on a 1 20-
acre parcel owned by NEA. Agreements were reached earlier with the owner of the surrounding land for
ROW access to build a 1.8 mile road to the site. These agreements will also enable seismic monitoring
and other surface-based operations in surrounding areas during the implementation of EGS project, and
for drilling additional wells.
Required permits for drilling and testing activities are in place, and the need for any additional permits for
stimulation activities is being investigated by The Castle Mountain Group. NEA has a strong commitment
to preserving environmental quality in this project. The project requires review and/or permitting by various
government, regulatory and environmental agencies. In accordance with the NEPA process and
guidelines for federally funded construction projects, documents have been filed on EERE’s Project
Management Center and an Environmental Assessment document is being compiled , with most of the
work complete. Project Coastal Consistency Determination documentation was submitted to DCOM on
May 22, 2009. Application for a Permit to Drill a Geothermal E xploration Well was submitted to ADNR on
June 1, 2009 and permit # 2215 was issued on July 30, 2009 to drill the first geothermal well in the state.
Required Permits
Project Coastal Consistency Determination, Alaska Department of Natural Resources
Division of Coastal and Ocean Management
Submitted May 22, 2009
Permit to Drill a Geothermal Exploration Well
Alaska Department of Natural Resources
Submitted June 1, 2009
Permitted July 30, 2009
Inert Waste Monofill Permit
Alaska Department of Environmental Conservation
Submitted June 1, 2009
Temporary Water Use Permit
Alaska Department of Natural Resources, Division of Water Resources
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Submitted May 9, 2009
Temporary Storage Plan Approval
Alaska Department of Environmental Conservation
Submitted July 1, 2009
EPA Class I Non-Hazardous Industrial Disposal Well UIC Permit
EPA Region 10
Individual State Disposal Permit (concurrent with EPA Class I Permit)
Alaska Department of Environmental Conservation
Notice of Intent to Operate under Construction General Permit 2008
EPA Region 10
4.3.4 Environmental
Address whether the following environmental and land use issues apply, and if so how they will
be addressed:
Threatened or Endangered species
Habitat issues
Wetlands and other protected areas
Archaeological and historical resources
Land development constraints
Telecommunications interference
Aviation considerations
Visual, aesthetics impacts
Identify and discuss other potential barriers
NEA project management and consultants have completed many of the tasks requ ired for an
Environmental Assessment and have been in communication with the appropriate agencies. According to
the Alaska Department of Fish and Game and the Bristol Bay Borough Coastal Management Plan, the
project area does not contain either significant or critical habitat areas, and does not support any
threatened or endangered species.
NEA commissioned HDR-Alaska to conduct a wetlands survey of the project’s road alignment and drill pad
areas. According to the survey report compiled by Ann Claerbou t, an Environmental Scientist with HDR, it
was determined that areas covered by the road alignment and drill pad do not contain wetlands.
The location of the proposed geothermal exploration project is greater than 15 miles from the coastline
and approximately 4 miles inland of the Naknek River on a flat to gently sloping upland moraine, at
approximately 280 ft elevation. No 100-year flood plains reside in or near the project area. The nearest
such floodplain resides along the Naknek River, roughly four miles from the project location.
The project area resides within the Bristol Bay Borough Coastal District and is therefore, subject to a
Project Consistency Determination under the Alaska Coastal Management Program and the Bristol Bay
Borough’s Coastal Management Plan. Review of the Bristol Bay Borough Coastal Management Plan
determined that the project will have no impact on coastal resources and is not subject to any of the
District Enforceable Policies.
Army Corp. of Engineers has been contacted regarding groundwater sources and no issues or constraints
exist. Geothermal generated energy is a renewable resource, and project development will not result in
the depletion of any non-renewable resources.
The project will result in the injection and extrac tion of geothermal fluids associated with electrical power
generation in a geothermal electrical power generation circuit. Fluid injection associated with this process
will be done under the authority of a Class I Non-Hazardous Underground Injection Control Permit to be
issued by EPA. A concurrent Individual State Permit will be issued by the Alaska Department of
Environmental Conservation for the re-injection of geothermal fluids.
The project is located approximately 5 miles from the nearest inhabited a rea. Drilling equipment is
equipped with noise mufflers and natural barriers will be used to further muffle noise associated with
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project activities.
NEA’s project does not reside within or near a Non-attainment area. The Project location is greater than
100 miles from the nearest Non-Attainment or Maintenance Area. Air emissions associated with the
project will not exceed the NAAQS for the seven criteria pollutants.
The only Class 1 airshed in Alaska is Denali National Park. The project is not locate d near, nor will it have
any effect upon, any Class 1 airshed. The project resides more than 20,000 ft from nearest airport and will
have no impact on navigable air space. No FAA Air Traffic Notification filing is required. The project does
not reside in or near any Areas of Special Designation and it has been determined that there is no prime,
unique, or important farmland within or in the vicinity of the project area.
Communities in Rural Alaska, including the Village of Naknek, roughly 16 miles from the project location,
are implementing voluntary pilot programs for the control of PM10 fugitive dust associated with vehicle
traffic. Dust control measures, such as watering of the access road and drill pad, will be employed at the
project location.
In June, 1998 the Bureau of Land Management undertook a Section 106 Review of the project area as a
part of preparations for a negotiated sale of the allotment on which the project is located. A determination
of “No Historic Properties Affected” was made and concurred upon by the Alaska State Historic
Preservation Office.
The outreach plan for this project includes town hall events and meetings with local government officials to
address public concerns and disseminate information about geothermal power generation
All project work will be undertaken in a good and workmanlike manner, ensuring that the project area is
maintained in a professional and organized fashion. Surface disturbance will be limited to the maximum
amount practicable, thereby maintaining as much of the natural aesthetic as possible.
4.4 Proposed New System Costs and Projected Revenues
(Total Estimated Costs and Projected Revenues)
The level of cost information provided will vary according to the phase of funding requested and
any previous work the applicant may have done on the project. Applicants must reference the
source of their cost data. For example: Applicants Records or Analysis, Industry Standards,
Consultant or Manufacturer’s estimates.
4.4.1 Project Development Cost
Provide detailed project cost information based on your current knowledge and understanding of
the project. Cost information should include the following:
Total anticipated project cost, and cost for this phase
Requested grant funding
Applicant matching funds – loans, capital contributions, in-kind
Identification of other funding sources
Projected capital cost of proposed renewable energy system
Projected development cost of proposed renewable energy system
4.4.2 Project Operating and Maintenance Costs
Include anticipated O&M costs for new facilities constructed and how these would be funded by
the applicant.
(Note: Operational costs are not eligible for grant funds however grantees are required to meet
ongoing reporting requirements for the purpose of reporting impacts of projects on the
communities they serve.)
4.4.3 Power Purchase/Sale
The power purchase/sale information should include the following:
Identification of potential power buyer(s)/customer(s)
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Potential power purchase/sales price - at a minimum indicate a price range
Proposed rate of return from grant-funded project
Phase I Interconnection links King Salmon to Dillingham and 5 other communities. The project will supply
wholesale electricity for distribution to Nushagak Electric Cooperative at the cost of power plus the cost of
distribution. All wholesale power sales agreements will follow this model. The goal is to increase
economy of scale with interconnection infrastructure linking stand-alone diesel generation and distribution
systems for improved efficiency and cost reduction.
See Preliminary Geothermal Impact Analysis – First Year Full Operation in 2.5 Project Benefit.
4.4.4 Project Cost Worksheet
Complete the cost worksheet form which provides summary information that will be considered
in evaluating the project.
NEA is an efficiently run rural utility that is celebrating its 50 th year energized. The cooperative has been
virtually self-sustaining in its delivery of cost-effective electricity. Costs presented in this proposal are
based on decades of experience operating a small rural utility, cost of service studies by RUS and private
consultants, and knowledge of the costs and restraints of doing business in off -the-grid communities that
out of necessity rely on stand-alone generation and distribution systems.
See Project Cost/Benefit Worksheet attached.
SECTION 5– PROJECT BENEFIT
Explain the economic and public benefits of your project. Include direct cost savings,
and how the people of Alaska will benefit from the project.
The benefits information should include the following:
Potential annual fuel displacement (gal and $) over the lifetime of the evaluated
renewable energy project
Anticipated annual revenue (based on i.e. a Proposed Power Purchase Agreement price,
RCA tariff, or cost based rate)
Potential additional annual incentives (i.e. tax credits)
Potential additional annual revenue streams (i.e. green tag sales or other renewable
energy subsidies or programs that might be available)
Discuss the non-economic public benefits to Alaskans over the lifetime of the project
Geothermal Energy Benefits
Stable, firm, renewable, secure and cost-effective co-generation of electric and district heat
requirements
Lower cost electric and home heating energy to end-user
70% decrease and controlled cost of power compared to volatile fossil energy market
Annual avoided fuel costs $21,600,000 (5,400,000 gallons diesel at $4.00/gallon)
$648,000,000 over the life of the project
Long-term reliable (95%) baseload energy
Lower life cycle costs offsetting high upfront project costs
Increased employment with local production of renewable energy supporting healthy economic
growth
Support for other direct-use activities
Higher capacity factor than other renewables
Increased generation capacity with decreased environmental liability and air-quality associated
costs
Offsets environmental fossil fuel pollutants with little or no greenhouse gases
Demonstration and deployment of renewable energy for strategic natural resource development
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Promote value-added manufacturing in the fishing and resource extraction industries
Protect Bristol Bay fisheries resource by decreasing fossil fuel transportation on resource sensitive
waterways
Deployment of absorption cooling “Fire-to Ice” technology for increased quality and value in the
fisheries
Increased tax revenue from increased value of seafood
Increased property value and property tax revenue to local governments
Substantial decrease in Power Cost Equalization (PCE) payments to regional utilities
Increased security and decreased dependency on foreign supply energy
Reversal of negative perception that rural Alaska communities are non-sustainable and a liability
to the state
Renewable energy produced hydrogen heralding in an era of new energy de velopment
Regional Economic Benefits
Fuel $ 8,000,000
Value Added Fishing Operations $50,000,000
Employment 200 Renewable Energy Jobs $10,000,000
Tourism $10,000,000
Reducing stress on urban areas that must accommodate refugees $250,000,000
TOTAL $328,000,000
SECTION 6– SUSTAINABILITY
Discuss your plan for operating the completed project so that it will be sustainable.
Include at a minimum:
Proposed business structure(s) and concepts that may be considered.
How you propose to finance the maintenance and operations for the life of the project
Identification of operational issues that could arise.
A description of operational costs including on-going support for any back-up or existing
systems that may be require to continue operation
Commitment to reporting the savings and benefits
The Southwest Alaska Regional Geothermal Project will be owned and operated by NEA. NEA is
incorporated as a not-for-profit 501 (C) (12) cooperative and employs the cooperative model to provide its
members with reliable electric energy at the lowest possible cost consistent with sound business pract ices.
This model returns excess margins to its members on a patronage bases. Net margins above expenses
belong to consumer members and may be allocated for distribution or retained as working capital to
expand, improve or maintain operations. Short-term gains are not the focus in a cooperative business
model but rather the creation of long-term value and sustainability for consumer members and in this case
the region.
NEA is an efficiently run electric utility and has a proven record with RUS. In over 48 years of operation
debt service expenses have not posed difficulty. Since 1960 most capital improvements were financed
with member money. NEA will apply the cooperative business model and all audit, regulatory and reporting
for grants, financing and contractual agreements will be accomplished according to funding agency
guidelines and NEA management standards. In the long-term, building locally produced renewable energy
electric generation and distribution infrastructure will bring security and sustainability to the region.
Southwest Alaska is poised both geographically and geologically for major economic productivity.
Transforming strategic natural resources like seafood, oil, gas and minerals, into globally viable market
commodities will provide economic benefit to the region, state and the nation. Government renewable
energy systems investments supporting natural resource development is important for long -term rural
sustainability and independence. By whom and for whom these resources are develo ped is a question that
needs to be addressed by all participants. The development of low-cost renewable energy for seafood
processing and cold storage will bring sustainable economic benefits to the region. As a result of resource
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availability, geography, potential strategic oil, gas and mineral value-added manufacturing such as refining,
smelting, cold storage, and transportation and service sector growth local economies will stabilize and
diversify.
SECTION 7 – READINESS & COMPLIANCE WITH OTHER GRANTS
Discuss what you have done to prepare for this award and how quickly you intend to proceed
with work once your grant is approved.
Tell us what you may have already accomplished on the project to date and identify other grants
that may have been previously awarded for this project and the degree you have been able to
meet the requirements of previous grants.
To achieve energy independence, lower energy costs and reduce the environmental impacts of power
production, NEA has taken the bold step of embracing geothermal development. The cooperative has
funded $2M in scientific research over the last 8 years including r econnaissance, geological and
geophysical surveys and analysis, most recently designing a drilling program and project management
plan for Phase I and II.
In a effort to control the costs of exploration and development the cooperative’s board and management
made the decision to purchase Rig #7 based on the understanding that developing a gathering field and
reinjection system would require multiple wells and that the cost of mobilization, standby, contingencies
are extremely high.
NEA project management has diligently pursued state and federal funding and has been rewarded with
two consecutive years of Congressionally Directed Project earmarks appropriated in the 2009 and 2020
Water and Energy Bills, and a major EGS demonstration grant. The funding appropriations and
demonstration grant are currently being negotiated with DOE.
Addressing manpower requirements for geothermal energy exp loration, production and transmission NEA
will interface with DOL DBP to create an apprenticeship program tailored to geothermal drill site operations
and Rig #7. NEA’s geothermal drilling operation will serve as a remote training site for local hire
roustabouts interested in career path opportunities and post-secondary education credits.
SECTION 8– LOCAL SUPPORT
Discuss what local support or possible opposition there may be regarding your project. Include
letters of support from the community that would benefit from this project.
The Southwest Alaska Regional Geothermal Energy Project will demonstrate cost-effective renewable
energy development in the region. The project is supported by regional economic development
organizations and native associations. There is virtually no opposition to geothermal development in the
region, much to the contrary it is serving as a bellwether for renewable energy exploitation in a region
poised for major economic growth.
Resolutions and letters of support are included as attachments to this REFG proposal.
SECTION 9 – GRANT BUDGET
Tell us how much you want in grant funds Include any investments to date and funding sources,
how much is being requested in grant funds, and additional investments you will make as an
applicant.
Include an estimate of budget costs by milestones using the form – GrantBudget3.doc
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See discussion in 2.6 Project Budget Overview and attached Grant Budget Form.
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SECTION 9 – ADDITIONAL DOCUMENTATION AND CERTIFICATION
SUBMIT THE FOLLOWING DOCUMENTS WITH YOUR APPLICATION:
Attachments:
a. Resumes of Key Participants
b. Cost Worksheet
c. Grant Budget Form
d. Regional Support Resolutions and Endorsements
e. NEA Resolutions
f. Electronic Version of Application
g. Resolutions and Letters of Support
h. Pike’s Ridge Property Deed - AA-7906, Parcel B
i. Pike’s Ridge Access Easement Map
j. Certification
The undersigned certifies that this application for a renewable energy grant is truthful
and correct, and that the applicant is in compliance with, and will continue to comply
with, all federal and state laws including existing credit and federal tax obligations.
Print Name Donna Vukich
Signature
Title General Manager – Naknek Electric Association, Inc.
Project Director – Southwest Alaska Regional Geothermal Energy Project
Date November 8, 2009