Introduction: Fossil Bay Energy
Fossil Bay Energy (FBE) is commercializing a novel method of Enhanced Oil Recovery that revitalizes production of depleted oil fields,
doubling recoverable crude oil reserves.
The Fossil Bay management team will utilize its contacts within the oil industry to develop strategic relationships with oil producers in
Michigan and throughout North America to secure Exhaust Gas EOR development rights on millions of barrels of “Stranded Oil.”
75% of the world’s proven oil reserves are stranded underground
after conventional extraction is complete.
Currently, the best method for increasing crude oil production
after conventional methods is to flood the reservoir with CO2
The problem is that sources of CO2 are very limited, and the
pipeline infrastructure needed to transport CO2 gas makes the
method viable only for very large oil reservoirs.
The Fossil Bay process utilizes a mobile gas producing unit,
producing exhaust gas directly at the wellhead for Enhanced Oil
Recovery. This method makes gas flooding economically viable for
thousands of oil fields, effectively capturing hundreds of millions of
barrels of stranded crude oil.
Example of oil recovery through primary, secondary, and tertiary methods.
Unique Opportunity as Exclusive Operator
During Equipment IP exclusivity with Weatherford International, LTD, Fossil Bay will have control over deal terms and our ability to extract profit
from these relationships.
If and when exclusivity expires, Fossil Bay will still be able to operate effectively and will have a head start in terms of knowledge and ability to
execute, but FBE will be operating in a more efficient market with the potential for heated competition.
Fossil Bay co-founder and CEO, Dan Kulka, is the author of a
granted patent titled ‘Method and system for extraction of liquid
hydraulics from subterranean wells,’ which covers the method of
using exhaust gas as a source for gas flooding.
The other key IP fence that Fossil Bay Energy can exploit is the
exclusive license with Weatherford International. Weatherford
controls intellectual property around the equipment from which
FBE will benefit.
U.S. & Canada Patent # 6,662,885 describes a method of
producing a pressurized stream of substantially inert gas.
The method involves collecting the exhaust gases from an
internal combustion engine, directing the exhaust gases into the
intake of a compressor for compressing to a desired pressure,
and recirculating a portion of the compressed exhaust gases
back to the intake of the compressor such that the pressure of
the exhaust gases within said compressor intake is maintained
above atmospheric pressure.
Also disclosed is an apparatus for producing a pressurized
stream of substantially inert gas utilizing the described method.
Wm. Cobb and Associates, Petroleum Engineering Adviser
Mr. Kulka has 30+ years of experience in the Oil and Gas Industry as an “explorationist” developing prospects in the Michigan, Illinois and Appalachian
Basins. From 1997-2000, Mr. Kulka managed an EOR Joint Venture with Shell Oil Noreast, American Natural Resources Pipeline and Gas Storage Companies
(ANR), and Forcenergy, Inc. This JV aimed to exploit the depleted Niagaran Reefs of Northern Michigan using Methane gas.
Mr. McGhan has 30+ years of experience in gas compression. Mr. McGhan was co-founder and CEO of Hanover Compressor (now “Exterran”) during the
1990s and Valerus Compression Services starting in 2004. Mr. McGhan will oversee Fossil Bay’s manufacturing and exploitation of its first-to-market,
patented, portable exhaust gas compression and injection equipment.
Mr. Marshall consults as CFO and M&A advisor for energy businesses in various stages of development ranging from start-ups to mature firms. Previously,
Mr. Marshall served in an ‘operating partner’ role working with PE-backed portfolio companies on behalf of Luther King Capital Management. Mr. Marshall
began his career with PwC in New York and has 12+ years of experience in M&A, financial management, accounting/controls, and board-level leadership.
Mr. Marshall earned Masters and Bachelors degrees in Accounting from Texas A&M University and earned his MBA from Rice University.
Mr. Hosking has 40+ years of domestic and international experience in the acquisition, processing, and interpretation of 2D and 3D seismic data. He is the
author of “Static Corrections” which is widely used today in the processing and interpretation of seismic data. Mr. Hosking has expertise in generating and
screening prospects and developing oil and gas fields throughout North America.
Hung Bui, PE
Senior EOR Manager
Mr. Bui is a registered Petroleum Engineer from Penn State University with 30+ years of experience modeling, designing, and developing reservoirs for gas
storage throughout North America on behalf of ANR Gas Storage Company, Coastal Corporation, CNG, El Paso Gas, TGP and Trans Canada. Mr. Bui has
extensive experience designing reservoirs for maximum injection and withdrawal rates and liquid recovery. Mr. Bui is an advocate of new technology and
reservoir modeling and simulation software and was the first to use underbalanced drilling and high-angle wellbores with spurs in the development of gas
storage reservoirs. Mr. Bui is proficient in maximizing reservoir capacity.
Problem: Stranded oil
When oil is discovered in a new reservoir, typically only 25% of the discovered oil reserves can be extracted with traditional
drilling and extraction methods, called ‘primary production.’
Secondary & Tertiary Production
In order to recover additional crude oil from an oil reservoir, a number of ‘secondary’ and ‘tertiary’ production methods
have been developed to mobilize crude oil trapped in rock formations and to re-pressurize the reservoir by replacing the
volume of gas and oil extracted during primary production.
‘Secondary production’ typically refers to water floods, and ‘tertiary production’ typically refers to gas and steam floods.
The most effective tertiary method of Enhanced Oil Recovery is CO2 gas flooding. The key benefit of CO2 gas is that it is
‘miscible’ with crude oil; under pressure conditions, CO2 gas molecules combine with the crude oil, swell the oil and lower
the viscosity pressure.
CO2 gas Injection has been successfully used for over 60 years in the very large oil fields located in Texas, Kansas,
Oklahoma, Michigan, Louisiana, Mississippi, Wyoming and Oklahoma. CO2 projects are financially sound and represent
some of the most profitable projects for companies like Kinder Morgan, Anadarko, Merit, Denbury and Whiting.
Historical solution: CO2 (gas) flooding
The chart below shows a typical result for gas flooding; this project
is in the Salt Creek reservoir of Wyoming.
After six months of gas injection, the field produced 800 bopd.
After one year, the field produced over 2,000 bopd.
EOR can double the recoverable oil reserves within most oil fields.
Problems with CO2 flooding: Transportation costs and supply
CO2 flooding is restricted to fields where large quantities of CO2 can be transported by pipeline from natural or industrial sources.
Pipelines are costly with capital expenses reaching hundreds of millions of dollars.
Due to the cost of transporting CO2, only
the largest oil fields in certain geographic
areas will be developed. The capital
required for CO2 flooding, as well as the
scarcity of natural or industrial sources of
CO2, results in a significant gap in the
industry’s ability to optimize crude oil
production in the world’s known reserves.
The Jackson Dome in Eastern Louisiana is
the only natural source of CO2 east of New
Mexico. In 1999, Denbury purchased the
reservoir for enhanced oil recovery.
Denbury has since built 1,100 miles of
pipeline in Louisiana, Mississippi, and Texas
to transport CO2 for gas flooding projects at
a total cost of $2.2 billion .
Fossil Bay solution: Portable exhaust gas
Combustion gas is comprised of approximately 13% CO2 and 87% Nitrogen.
Researchers at Louisiana State University compared exhaust gas to pure CO2 in simulated conditions and found that exhaust gas
performs significantly better than pure CO2 in the recovery of crude oil.
Combustion gas from a standard internal combustion engine provides an ideal gas for enhanced oil recovery.
In a pure CO2 flood, CO2 combines with oil under pressure, increasing the volume of oil and reducing viscosity.
Exhaust gas provides increased oil volume, reduced viscosity, and pressure-induced drive – without adding water.
This allows the oil to flow more freely towards the producing well. However, CO2 does not provide drive.
In a pure CO2 flood, gas injection is followed by water (WAG, Water And Gas) which provides pressure and drive to push the oil
towards a producing well.
The 13% CO2 separates from the Nitrogen and combines with the oil under pressure, providing the needed swelling, lowering
viscosity, and increasing oil flow.
The 87% Nitrogen gas rises to the top of the reservoir, providing a pressure source which is more effective than water at driving
oil towards a producing well.
Evolution of exhaust gas as EOR solution
In the 1960s, exhaust gas was used in a number of projects. For
example, the Spring Hill Field in Kentucky increased monthly oil
production from 100 barrels per month to over 5,000 barrels
per month after four months and a total of 8 million cubic feet
of exhaust gas injection.
A critical step in using exhaust gas for EOR is post-production
processing: drying the combustion gas, cooling it, and
pressurizing it for injection. Without the drying step, loose
water molecules in the gas create carbonic acid, which is a
corrosive substance, damaging a well’s casing.
Exhaust gas production lost favor because the original
equipment did not have the ability to effectively produce very
large volumes of gas and deliver the post-production capacity
(non-corrosive) needed to economically use the gas for
Exhaust gas was initially promising but held back by technology. New technology allows effective use of exhaust gas for EOR.
Weatherford International owns the technology IP needed to
produce very large quantities of pressurized exhaust gas for
Enhanced Oil Recovery.
The system has been built, the gas output is fully characterized,
and the equipment is field-ready. Exhaust gas volume and
pressure are expandable to meet most gas injection
Fossil Bay Energy has negotiated an exclusive contract with
Mobile Injection Gas Equipment
Gas Assisted Gravity Drainage with Horizontal Wellbores
Gas Assisted Gravity Drainage with horizontal wellbores will increase reservoir exposure, resulting in
greater injection and production rates. Horizontal wellbores are essential for maximum oil recovery.
Oil & CO2
Case study: Block 31, exhaust gas pioneer
Block 31 was discovered in the Permian Basin by Atlantic-Richfield in 1945.
Estimated OOIP was 300 million boe with pressure exceeding 4,000 psi; however, the
reservoir rock was quite impermeable, around 1 md.
Consists of three reservoirs: upper, middle, and lower.
Major reservoir (middle) is at depth of 8,500 ft with a net pay zone
averaging 170 ft.
Porosity is intercrystalline and averages 15%.
Initial well rates were essentially zero, and no oil was extracted under primary or
In 1949, Atlantic-Richfield began compressing and injecting natural gas from a nearby
source into Block 31, and production finally commenced under this revolutionary
By 1965, cumulative production from Block 31 approached 90 million boe.
In 1966, to avoid using marketable natural gas, Atlantic-Richfield developed
a system to inject flue (exhaust) gas from a nearby processing plant.
Production peaked at 20,000 bopd from the field in 1978 but slid steadily to
2,500 bopd in 1998 with average production per well of 15 bopd.
Projected ultimate recovery through gas flooding is greater than 65% of
OOIP; to date, about two-thirds of the ultimate oil recovery has been
Case study: Springhill Grove exhaust gas projects
The Springhill Grove field was discovered in 1958, and the two wells produced 1-2 bopd.
In 1961, the operator bought an 80 mcfd Exhaust Gas Processor (EGP), and production increased to 6 bopd.
In 1964, the field was sold, and the new operators employed additional EGPs for a total of 200 mcfd and started injection.
Within four months, the Springhill Grove field was producing at rates over 5,000 bopm.
The offsetting Boswell-Walker Leases saw production increases from 150 bopm to 1,300 bopm by virtue of the exhaust being
injected in the Hart Lease.
In 1964, a full scale development was initiated on this lease which produced 54% of the OOIP using Exhaust Gas.
Competing EOR methods: Water flooding
Water injection wells are used both onshore and offshore to increase oil recovery from an existing reservoir.
Water is injected to support reservoir pressure and sweep oil from the reservoir and push it towards a production well.
Normally, only 25% of the oil in a reservoir can be extracted; water injection often increases oil recovery by 8-12%.
Water floods are typically inexpensive but slow in affecting incremental oil recovery.
Competing EOR methods: Steam injection
Steam injection is the most common method of extracting heavy crude oil. It is considered an EOR method and is the main
type of thermal stimulation used in heavy oil reservoirs.
There are several forms of steam injection: the two dominant methods are Cyclic Steam Stimulation and Steam Flooding. Both
methods are most commonly applied to oil reservoirs which are relatively shallow and contain crude oils which are very
viscous at the temperature of the native underground formation. Steam injection is widely used in the San Joaquin Valley of
California (USA), the Lake Maracaibo region of Venezuela, and the oil sands of northern Alberta (Canada).
Competing EOR methods: Carbon sequestration (coal-fired)
Carbon sequestration is a potentially-attractive method of EOR
which involves the use of flue gas from coal-fired power plants
for CO2 gas flooding. While promising, flue gas produced in this
manner is an imperfect tool: there is not yet an economical way
to remove H2S and NOX from the emissions. Also, transporting
the gas is still a challenge due to the distance between power
plants and oil reservoirs.
A number of emerging projects are connected to new coal
gasification power plants located near oil reservoirs. Coal
gasification is a more expensive and energy-intensive process
but eliminates the emissions and, thereby, the need for post-
processing the gas to remove contaminants. These projects are
also designed specifically to deliver gas to oil fields which makes
transportation more tenable. Since these projects require
billions of dollars in capital and years to complete, they are only
feasible for very large oil fields.
EOR industry leaders
A number of major international companies have ventured heavily into EOR projects. These companies have the capital resources to
exploit new opportunities and the reserves in place to develop significant projects:
Non-major leaders in the EOR Industry include the following:
Denbury - CO2 , developing projects
Kinder Morgan - own fields, supply and transport CO2
Apache - own fields, purchasing CO2
Whiting - own fields, purchasing CO2
Anadarko - own fields, purchasing and developing its own source of CO2
Merit - own fields, purchasing CO2
Occidental Chemical Company - 350,000 barrels from EOR in Calgary and California
These companies are invested primarily in traditional CO2 flooding methods. Fossil Bay plans to partner with oil producing companies like
these on mobile exhaust gas flooding projects. In order to protect market position, FBE will invest in extending and deepening its
intellectual property position around exhaust gas EOR.
Domestic and Global Oil Markets
Domestic and Global Oil Reserves
The DOE and ARI estimate that approximately 72 billion barrels of
reserves hold EOR potential in the United States alone. The United
States proven reserves are 200 billion barrels with another 1,130
billion barrels in place.
Globally, it is difficult to estimate proven reserves since the data is
highly political and closely-held. The US Energy Information
Administration estimated 1.7 trillion barrels of global proven oil
reserves in 2014.
The United States produces 2.3 billion barrels of oil annually while
the global oil industry produces 32 billion barrels of oil annually.
United States Domestic Market
In the United States alone, there are roughly 225,000 crude oil wells
in production with 1,330 billion barrels oil in place: 200 billion
recovered and 200 billion stranded.
Of the 230,000 crude oil fields in the United States, Fossil Bay
estimates that 114,805 have geologic merit and are potentially
addressable for mobile gas flooding.
Initial development focus: Michigan Basin
The Michigan Basin will be the initial developmental region. Fossil Bay currently
has two pilot projects engineered and in the final permitting process in the
Southern Niagaran Reefs.
Fossil Bay has Options on other reservoirs and will pursue acquisition of
plugged and abandoned reservoirs throughout the Northern and Southern
These reefs are some of the best reservoirs for Gravity Assisted Gas
Injection EOR due to certain reservoir properties: thick pay columns,
impermeable cap seal, compact size, low primary recoveries, and highly-
Fossil Bay has identified over 200 reefs in Michigan which meet the EOR criteria,
representing over 150 million barrels of oil. Over 75 of those reefs are plugged
and abandoned and could be obtained through direct leases. The remaining
producing fields can be obtained through Joint Venture agreements with small
Pure CO2 flooding has been successful in a handful of Michigan reefs with
production rates as high as 1,200 bopd. However, pure CO2 flooding in Michigan
would be limited to less than 10 total projects due to the lack of scalable CO2
supply and the costly infrastructure required to move the gas.
Fossil Bay’s mobile exhaust gas process is the only known process which is
scalable enough to have a major impact on the recovery of stranded oil in
Michigan and other North American basins.
Michigan Basin: Brief EOR history, attractive Niagaran characteristics
EOR in Michigan
Historic oil production primarily from Ordovician, Silurian and
Cumulative oil production exceeds 1.2 billion boe.
Most fields produced through primary phase only.
A few dozen water floods have been mostly successful. Water
flood production nearly equals primary production in some
ANR-designed gas storage operations have recovered long-
term liquids at rates upwards of 7,000bpd from the Niagaran
CO2 flooding began in Niagaran Reefs in 1996; only three
fields developed to date due to limited pipeline access.
Completely sealed vertically & laterally by evaporitic lithologic
Readily identifiable by seismic.
Ideal for gas re- pressurization.
Dover 33 CO2 – EOR project Michigan
High Angle Production Well
Cased Hole Completion
Crestal position Horizontal Production well
Open Hole Completion
1974 1978 1982 1986 1990 1994 1998 2002 2006
Oil Production (bbl)
1, 280 MBO Primary Recovery
447 MBO CO2 Flood Recovery to date
2.2 Bcf to reach MMP – 9 months
Northern Reef Trend
Over 650 Separate Reefs
390 Million boe and 2.2 TCF gas produced
28% average primary recovery
Only a limited number of waterflood attempts
Thickness 150 to 700 ft
Average Porosity (Range) 7% (3 to 18%)
Average Permeability (Range) 12 md (0.1 md to 8 darcies)
Oil Gravity 40º to 42º api on average
Average Reservoir Temperature 100º to 120º F
Oil Formation Volume Factor 1.2 to 1.6
Lithology Dolomite and/or Limestone
Average depths to top of reservoirs 3600 to 6000 ft
Key Engineering Properties - Northern Trend
Bottom Line – Spectacular Tertiary Recovery and Sequestration Targets
Michigan Basin: Typical project economics
A small to medium-sized reservoir with 2 million barrels of proven reserve will require approximately $5 million in upfront capital for all
project development expenses.
Direct project development expenses include the following:
Seismic, Geology, Geophysics, Engineering
Drilling a new horizontal production well
Converting the existing production well into a horizontal gas injection well
Leasing the exhaust gas equipment
Provisioning fuel required to run the equipment during the re-pressurization phase
Ongoing recirculation and reinjection of gas extracted as a byproduct of the oil production
Michigan Basin: Typical project economics
Pure CO2 projects range in yield from 17% to 34% of original oil in place. Fossil Bay estimates a 25% yield over 5 years for total gross
proceeds of $25 million at $50 oil.
Ave MI Reef Mid-Case
Year Assumptions 0 1 2 3 4 5 Total
Oil In Place Barrels 2,000,000
Oil in Place Recovery 25% - 130,293 121,757 97,957 84,643 65,350 500,000
Price per Barrel $ 50
Gross Proceeds $ - $ 6,514,627 $ 6,087,861 $ 4,897,869 $ 4,232,133 $ 3,267,509 25,000,000
Work Over $ 75,000 $ - $ - $ - $ - $ - $ -
Completion $ 275,000 $ - $ - $ - $ - $ - $ -
Project Development $ 100,000 $ - $ - $ - $ - $ - $ -
Rotary Rig $ 1,300,000 $ - $ - $ - $ - $ - $ -
Injection Gas $ 1,430,000 $ - $ - $ - $ - $ - $ -
Operating Cost $ 200,000 $ 200,000 $ 200,000 $ 200,000 $ 200,000 $ 1,000,000
Total Project Cost $ 3,180,000 $ 200,000 $ 200,000 $ 200,000 $ 200,000 $ 200,000 $ 4,180,000
Mineral Rights Owner 20% $ 1,302,925 $ 1,217,572 $ 979,574 $ 846,427 $ 653,502 $ 5,000,000
Severance Tax 4% $ 260,585.06 $ 243,514 $ 195,915 $ 169,285 $ 130,700 $ 1,000,000
Well Operator 0% $ - $ - $ - $ - $ - $ -
Total Expense $ 3,180,000 $ 1,763,510 $ 1,661,087 $ 1,375,489 $ 1,215,712 $ 984,202 $ 10,180,000
Net Proceeds $ (3,180,000) $ 4,751,116 $ 4,426,775 $ 3,522,381 $ 3,016,421 $ 2,283,307 $ 14,820,000
Carry 20% $ 950,223 $ 885,355 $ 704,476 $ 603,284 $ 456,661 $ 3,600,000
Management Fee 0% $ - $ - $ - $ - $ - $ -
Proceeds $ 950,223 $ 885,355 $ 704,476 $ 603,284 $ 456,661 $ 3,600,000
Proceeds $ (3,180,000) $ 3,800,893 $ 3,541,420 $ 2,817,905 $ 2,413,137 $ 1,826,646 $ 11,220,000
Cash Multiple 4.5x
Partnering with oil production companies
Fossil Bay will partner with existing well owners and operators to increase the ultimate recovery of oil from their pressure-depleted
reservoirs. As a general rule, gas flooding methods are geologically appropriate for roughly 50% of conventional oil reservoirs.
Fossil Bay’s initial primary market of Joint Venture partners will be small and medium-sized oil production companies that operate
reservoirs with between 1 million and 5 million barrels of original oil in place (OOIP).
Fossil Bay Energy is essentially a project finance, engineering, and management company.
Fossil Bay is partnering with existing oil producers who will be highly motivated to increase the yields on expiring and depleted holdings.
FBE production partners will have detailed geology, engineering, and production data for each field - reducing the cost and risk associated
with choosing projects.
Project drilling and completion costs are contained at the operating company level and are funded by Fossil Bay’s partners with whom FBE
will share the risk and reward for each project. The resources needed to mobilize a project are industry standard and readily available in
any oil producing region.
The key activities and related expenses for Fossil Bay will include the following:
Project Origination: recruiting, educating, and managing relationships with a highly-fragmented group of independent oil producers
as well as large production companies.
Project Engineering: the key technical risk for this opportunity is correctly selecting projects with economic merit and accurately
producing the geologic and engineering analysis needed to spec drilling and injection operations.
Project Finance: the total market opportunity will potentially require billions of dollars in capital. Best-in-class financial controls will
be essential to success.
Project Management: the opportunities for enhanced oil recovery span the globe. Capitalizing on these opportunities, while at the
same time ensuring operational control and efficiencies, will be an extremely complex and difficult task. Fossil Bay plans to start
locally and scale in a controlled way, establishing strong local partnerships in order to distribute responsibility to parties with working
knowledge for each new region.
Six-project portfolio: Projected cash flow and project timeline
TASKS Sept Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar
Eng, Land & Legal Evaluation PeriodEvaluation Per.
Drilling Operations Production
Investors’ Net Cash Flow
Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8
Project 1 (1,880,000) 1,476,175 1,371,612 1,080,047 916,932 680,586
Project 2 (1,980,000) 1,476,175 1,371,612 1,080,047 916 819,373
Project 3 (3,180,000) 3,800,893 3,541,420 2,817,905 2,413,137 1,826,646
Project 4 (3,180,000) 3,800,893 3,541,420 2,817,905 2,413,137 1,826,646
Project 5 (3,180,000) 3,800,893 3,541,420 2,817,905 2,413,137 1,826,646
Project 6 (3,180,000) 3,800,893 3,541,420 2,817,905 2,413,137 1,826,646 Net Cash Flow to Investors
(7,040,000) 393,243 10,706,430 15,861,732 12,508,215 10,970,784 6,066,429 1,826,646 51,293,479
Cash Multiple 4.1x
2 Year CAPEX with Net Revenue after Op. Cost, Royality, State Taxes
Overview: Cigna 1-23
Cigna 1-23 is a 25 acre Niagaran Reef having produced 176,000 boe since
1994; the well is located in Livingston County, Michigan and has recovered
18% of the OOIP.
The Cigna 1-23 had 1779# BHP at discovery, 140 ft. of net oil pay with an
average of 6.5% porosity.
OOIP was estimated between 861,000 and 1,000,000 boe; CO2 floods could
reasonably yield 18-32%.
Fossil Bay estimates OOIP of 861,000 boe and projects 25% additional oil
recovery through mobile exhaust gas EOR.
Historic Prod -vs- Pressure Decline
OIL Prod. Rate
Cigna 1-23: Prediction of reservoir performance
The simulation model and data developed in the history match analysis were
used to design and forecast field performance that could achieve the objective
target rate. To enhance the mixing of injected flue gas of N2 and CO2 with the
residual oil in place, the compositional model was used for the prediction
analysis. A compositional sample of the reservoir was also constructed based
upon data from various reservoirs in the reef trend.
One new horizontal well would be completed in the lower zone as the
producing well with a spur leg extending into additional unproduced areas of
the reservoir. The existing vertical production well will be converted into the
injection well. The new horizontal producing well would have approximately
1,200 feet of open-hole exposure to the reservoir. Special procedures should be
used to complete the producer as an upward (toe up) slanted horizontal well.
Prediction analysis indicates that oil production could begin after three months
of injection. Cumulative injection of 90 MMscf would raise reservoir pressure
to approximately 1,200 psi. Field production could duplicate the primary
volume in two-to-three years. However, the CO2 concentration in the produced
vapor would be less than 4% over time, and, occasionally, a fresh patch of flue
gas may be necessary to enhance oil mobility.
Overview: State Cleon 2-13
The Cleon 13 field was discovered by Federal Oil in December 1993 in
Cleon Township, Manistee County, Michigan.
The St Cleon 2-13 well penetrated the Brown Niagaran reef at a True
Vertical Depth (TVD) of 5,609 feet and encountered the Gray Niagaran
formation at a TVD of 6,034 feet.
From the well log analysis, the reservoir net pay extended from the top of
the Brown Niagaran to approximately 5,965 feet TVD and a net pay of 356
The discovery field data indicated that the Cleon 13 field is an under
saturated oil reservoir. The initial produced oil has an estimated gravity at
about 42 degrees API, and the separator gas gravity was about 0.6.
Bottom hole pressure was 2,380 at 5,907 feet. In December 1996, the
original perforation interval was squeezed, a casing window was milled,
and the well was completed with a lateral open hole from 5,879 to 6,512
The first lateral extended 660 feet south and 400 feet west of the original
well location at an average depth of 5,040 feet TVD.
State Cleon 2-13: Production History
The production history of the field indicated that the original 21 feet perforation interval and the perforations added in October 1995
produced 124.6 Mbbls of oil and 242 MMscf of gas from December 1994 to December 1996.
After the well was recompleted with the lateral, production increased for a short period, then fell off.
The reservoir produced an additional 62.3 Mbbls of oil and 66MMscf of gas since that time and is currently producing at a rate of 5 bopd.
This reef recovered approximately 22% of the Original Oil in Place.
The Cleon 13 project will utilize the existing wellbore as the injector well, and a new well will be drilled to act as the producer. The
Injection Phase is expected to last approximately 90 days. Once the reservoir is partially re-charged, a shut-in soaking period will take
place before the well is returned to production.
State Cleon 2-13 Reservoir: EOR production profile
We are currently raising funds for Fossil Bay Energy LLC to execute its initial Exhaust Gas EOR Projects. The first $6 million of
the planned $30 million raise will fund our first two projects in southern Michigan. The initial projects are fully engineered
and will be ready to begin the 1st quarter of 2017.
The Funding Parties shall have the right to participate with Fossil Bay Energy in future projects within the State of Michigan.
Participation Rights outside of Michigan shall be negotiated by the parties. All Participation Terms and Conditions shall be
mutually agreed upon by all parties and detailed in a legally-binding agreement.
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