Unconventionally Speaking

What is Net Energy Ratio or NER?

Net Energy Ratio

The Net Energy Ratio or NER of an energy technology is used to show how ‘efficient’ that technology is in terms of providing energy to society.  For example photovoltaic solar power has often been criticized due to its perceived low NER.

The NER is a ratio expressing the relationship between outside energy required to release useable energy and the useful energy itself.  In the case of some solar power this can be quite low due to the large amount of energy required to make solar devices in the first place.  For example published studies indicate it requires an input of 5600 kiloWatt hours of electricity to produce a solar panel with a power capacity of 1 kW.  In an average situation that panel would produce around 900 kWh of electricity in a year.  With a lifetime of 20 years the panel would produce 18,000 kWh.  So the ratio between the amount of energy required to make the panel and the energy it generated is 3.2.  This means the panel will produce over three times more energy than it took to manufacture it over its life time.

Conventional oil and gas historically have had high NER values, but those numbers have been falling in recent years.  According to Wikipedia, the NER for imported oil in 1990 was 35, but has since fallen to 12 in 2007.  This is largely due to the increasing proportion of heavy oils and tar sands in the imported oil mix. These alternative oil resources tend to have much lower NERs– 3 in the case of tar sands.

One of the great advantages of Geothermic Fuel Cells is that they generate net energy far more efficiently than many other technologies.  Because GFCs use energy that would otherwise be wasted to heat hydrocarbon formations our NER is around 22.

IEP has identified most if not all of the energy costs associated with manufacturing and installing GFCs to produce shale oil.  These energy costs include drilling, casing, manufacturing, shipping, installing, etc.  As shown by the graph these energy costs all add up to 8.7 billion BTU of energy.

Energy Inputs to NER

Once installed and operated the GFCs produce net energy in the forms of oil, electricity, and gas.  One well in one lift will produce a total net energy output of 200 billion BTU:
Net energy produced over life of product

Energy out compared to energy in gives us a Net Energy Ratio of 22.
Net Energy Ratio

Unconventionally Speaking

Do we even need Unconventional Fuels?

The headlines say the United States is becoming “energy independent”.1   A wave of new gas and oil production will carry the country to the broad sunlit uplands of energy independence…  Or so the pundits tell us.  If we take a hard look at the numbers, however, we see a very different story.  The  United States produced 6.5 million barrels of crude oil every day in 2012.  But we still consumed  18.6 million barrels per day, the lowest rate in 16 years.2    So imports in 2012 were something like 11 or 12 million bpd, depending on how much refined product were exporting.    To achieve independence means we will have to increase oil production by another five or six million barrels per day.   Is that something that can be achieved without recourse to Unconventional Resources?  Probably not.

According to the US Energy Information Administration, US oil output increased from 5 million barrels per day in 2008 to 6.5 million bpd in 2012.3   That is a stunning success and represents a reversal in decline that dates back to 1986.  This has caused a great stir in the world of oil and there are breathless headlines about the US exceeding Saudi Arabia by 2020.4   The good news includes significant reductions in demand for oil.  In the EIA’s Reference Case oil demand in the US is projected to decline until 2019.5   This combination of rising production and declining demand will result in net oil imports falling to as low as 33% of our supply.  Under the EIA’s projections for the Reference Case out to 2040 the US will still depend on imports for 37% of its oil supplies.  This is a great improvement over the 60% level we experienced in 2005, but it is still a long way from Independence.

EIA Energy Outlook 2013 Report, page 2

It is highly probable therefore that the US will still be dependent on imports of 5 or 6 million barrels of oil per day for the foreseeable future.  Filling that gap will require a large contribution from Unconventional Fuel sources like oil shale.  A huge oil shale industry might produce 1.5 million bpd, which would still leave a large gap of 3.5 or 4.5 million bpd to be filled by other Unconventional Fuels or more conservation, etc.  Therefore our conclusion here at IEP is that our efforts to produce oil from oil shale and other Unconventional sources will still be essential work for decades to come.

1Oil mogul says U.S. is close to energy independence, By John Ingle, Times Record News, April 25, 2013.
2U.S. Oil Demand Falls to 16-Year Low, API Reports, By Moming Zhou, Bloomberg, Jan 18, 2013
According to the Statistical Abstract of the United States 2012, Table 938, total domestic oil production in 2010 was only 5.5 million barrels per day and imports were 11.75 million.

3U.S. Energy Information Administration, Energy Outlook 2013, Dept. of Energy, Washington, D.C., April 2013, p. 2.
4U.S. To Become World’s Largest Oil Producer, Exceeding Saudi Arabia, By 2020: International Energy Agency, By PABLO GORONDI , Huffington Post, Posted: 11/12/2012.

Unconventionally Speaking

Development Project Update: First Prototype Complete

These are exciting times at Independent Energy Partners Technology.  Initial testing of the first prototype, a single stack module, has been completed.  The testing to date has demonstrated that the Geothermic Fuel Cell (GFC) concept of using fuel cells to generate heat to convert kerogen to oil while producing valuable green electricity will work.  The testing indicates that the fuel cells can provide sufficient heat to support the oil shale conversion process.

This validates the study that was conducted by the Department of Energy’s Pacific Northwest National Lab (PNNL) to prove the technical viability of the concept. It has also validated the design direction of the overall system.  Additional testing will be conducted over the next few months to further validate the control mechanisms.

Our philosophy at IEP is the application of existing technology in an unconventional way to extract value from unconventional resources.  In our case, we are taking proven technologies, repackaging them and integrating them in such a way as to reduce the cost of heating the ground.  Our first application is oil shale conversion and we have made significant progress lately.  We began by working with PNNL to study the viability of using solid oxide fuel cells (SOFCs) to generate heat to convert the kerogen in oil shale to oil.

After a couple years of study, PNNL established that the concept was technically viable and proposed a design that could work.  Rather than start from scratch and develop a purpose built GFC heater, we looked to industry leaders with products that were proven in their specific scope.  This led to the relationship with Delphi Corporation for the SOFC hardware and the Colorado Fuel Cell Center at Colorado School of Mines for testing.

The design of the second prototype is complete and the manufacturing process has started.  This unit is a 6ft long module integrated with multiple fuel cell stacks, all the interconnections and components needed for a full-scale system.

Unconventionally Speaking

White River Water

Talking about water in Colorado is like talking about the weather in Colorado, it is not all the same thing everywhere in the state.  Colorado in general and Western Colorado particularly, are considered to be part of the arid west.  But many places in the state, including Rio Blanco County, where IEP plans to develop oil shale experience annual precipitation of 35 inches. Rio-Blanco county precipitation maphttp://www.co.rio-blanco.co.us/development/pdf/RBC_Precipitation.pdf

The state’s water situation is often discussed as if it was some coherent unity.  In reality the situation is highly fragmented.  The states hydrography is separated into at least 10 different river basins.  Situations vary from basin to basin.  IEP’s property is situated in the White River Basin where there is a large surplus of water over and above present needs for all purposes.

First and foremost of those purposes are minimum river flows necessary to sustain fisheries and wildlife, including habitat for the endangered Colorado pikeminnow.  Diversions for fisheries in the White River during the late 1990’s were around 23,000 acre feet per year, equating to a continuous flow of about 32 cubic feet per second.1


However, most western rivers, and especially the White River, do not flow uniformly.  Water flows are seasonal with a pronounced peak in the spring as snow melt leaves the basin.Monthly flows - White River


These peak flows greatly exceed the minimum stream flows needed for fish and wildlife.  If storage structures are available, some of this peak surplus can be held and released over the course of the year when stream flows are much lower.  This stored water can be released in times of drought when fisheries need additional stream flow and they can be diverted through pipelines or by other means to supply industrial needs like oil shale development.  Water from the spring flood can both help insure adequate flows for wildlife while also supplying industrial water without depleting the river during periods of low flows.

Historic hydrology on the White River (1923 to 1997) shows that base stream flows have fallen below 200 cfs 5% of the time and below 150 cfs 1% of the time.2   Minimum stream flows for endangered fish in the White River have been identified as 161 cfs.3

White River profile 1995 and 1996


If we take it as a given that minimum streamflows in the White River must be maintained at 161 cfs, then this equates to a discharge from the basin of 116,500 acre feet.

The White River flows over 600,000 acre feet per year on average, but consumptive use of this water in Colorado, amounts to less than 37,000 acre feet, so only around 5% of the water in the White River is consumed.4   IEP will use no more than 2 barrels of water per barrel of oil produced (probably substantially less).  Our baseline development calls for peak production of 250,000 barrels of shale oil per day.  That will result in consumption of not more than 24,000 AF per year.  This would increase the total of all depletions in the White River to less than 10% of the total flow.


White River flow near Meeker


If stream flows for fisheries of 116,500 AF are added to consumption for all other uses of 37,000 AF, then the White River can supply over 500,000 AF for other uses, including oil shale development.


1THE WHITE RIVER AND ENDANGERED FISH RECOVERY: A HYDROLOGICAL, PHYSICAL AND BIOLOGICAL SYNOPSIS, Final Report September 1998, Updated and Edited September 2000, Utah Division of Wildlife Resources, 1594 W. North Temple,Salt Lake City, Utah John F. Kimball, Director, Table 2, P. 20.
2White River Base Flow Study for Endangered Fishes, Colorado and Utah, 1996-1996, U.S. Fish and Wildlife Service, Feb. 2004, Vernal, Utah, p. 21.
3Ibid. p. 17.

Unconventionally Speaking

What is Oil Shale?

Different types of shale plays

Oil and gas from shale is a popular topic and in the unconventional oil and gas industry, there are two types of shale plays that are important.  I thought it important to make the distinction between the two main types of shale plays from which oil and gas products are recovered.  Shale is basically a fine grain sedimentary rock that is made up of many thin layers. The most frequently discussed type, is an oil-bearing shale, which occurs when the oil and gas are fully formed but trapped within the layers of shale due to the low permeability of the shale itself.  Hydraulic fracturing, or “fracking” combined with horizontal drilling is the most effective method used today to recover the oil and gas from the shale.  These plays include the Barnett Shale in Texas, Bakken Shale in North Dakota and Marcellus Shale in Pennsylvania.  The oil and gas recovered from these types of shale plays are commonly called “tight-oil” or “tight-gas” and is very similar to conventional oil and gas.

The other type is oil shale. The difference is oil shale contains a solid organic matter called kerogen.  The kerogen is typically heated to a high temperature, which converts through pyrolysis into liquid and gaseous hydrocarbons.  Our Geothermic Fuel Cell™ (GFC) technology was designed to recover oil and gas from this type of shale.  Instead of using hydraulic fracturing as the production method, the GFCs produce very clean heat and electricity in-situ (in place) and converts the kerogen into oil and gas.  Most of the oil shale plays in the United States are concentrated in Colorado, Utah and Wyoming.  These include the Green River basin, the Uinta basin and the Piceance basin.  Oil shale deposits in the United States are estimated to contain over a trillion barrels of shale oil.  The cost of heating the ground has always been a barrier to recovering oil from oil shale.  High thermal efficiency is the key to unlocking this incredible resource and our GFC technology was designed to do just that.

More information on oil shale resources can be found here:


Unconventionally Speaking

Low Carbon Emissions Technology

Carbon dioxide emissions are a matter of growing concern.   Some potential liquid fuel sources produce more carbon than others.  For example, oil from Canadian tar sands  produces 5 to 15% more green house gases than average crude oil.[i]

Despite this seemingly small difference, Shell and the Canadian government are spending $1.3 billion to sequester CO2 from tar sands at a cost of $72/ton.[ii]

Production of oil from oil shale can also produce excess green house gases compared to conventional oil.  Estimates of carbon intensity for processes like Shell’s ICP process, which uses electrical resistance heaters, produce motor fuels at an intensity of 311 grams of carbon dioxide per kilometer driven, versus conventional oil’s 218 g/km.[iii]  This is a difference of almost 43% more carbon dioxide —  a major disadvantage of oil shale produced by the ICP process.

However, if shale oil is produced by the ICP insitu process, but GFCs are used instead of electrical resistance heaters, then the carbon intensity of shale oil falls to 183 g/km.[iv]  This is 16% less than conventional oil.

The huge gap between in situ production of shale oil with GFCs instead of electric heaters is due  to the “profound benefits of utilization of waste heat for retorting”.[v]    Using GFCs will allow us to produce shale oil from the world’s vast reserves of this unconventional oil stock while producing less carbon dioxide than from other sources including conventional oil.

[i] “Oil Sands, Greenhouse Gases, and US Oil Supply”, IHS CERA, (Cambridge Energy Research Associates) Cambridge, 2010.

[ii] “Shell Launches First Canadian Carbon Capture Project”, The Globe and Mail, Calgary, Nathan Vanderklippe.  Sept 5, 2012.  http://www.theglobeandmail.com/globe-investor/shell-launches-first-canadian-oil-sands-carbon-capture-project/article4520968/

[iii] “Oil Shale as an Energy Resource in a CO2 Constrained World: The Concept of Electricity Production with in Situ Carbon Capture”, Energy & Fuels 2011, 25, Hiren Mulchandani and Adam R. Brandt. Table 5, p. 1639.

[iv] Ibid.

[v] Ibid. p. 1638.

Unconventionally Speaking

Unconventional Green Energy

Conventional green energy is typically produced by harnessing wind, water or solar power.  These sources are considered green because they produce practically no pollution while converting these natural energy sources into useful electricity, unlike traditional fossil fuel combustion processes.

The increase in electricity generation using solar and wind power have given rise to discussions around reliability and availability of green power and driving many power companies to provide backup capacity.  Wind and solar energy are subject to climate conditions and not always available, which make them an imperfect renewable power solution. The alternative is to reduce power consumption, or to store the energy somehow and draw from it when needed.

Our technology sidesteps many of the issues around conventional green technology by providing constant power 24/7 that is not dependent on climate conditions.  This is considered “baseload” power. The fuel cell stack uses the energy contained in natural gas to generate heat and electricity via an electrochemical process instead of combustion, resulting in the exhaust being mostly air, water and some CO2 versus nearly all noxious gases.  Further, we are able to capture the exhaust stream, preventing any CO2 emissions.  Our expectation is that 20% of the green electricty produced will be consumed by our operation, and the remaining 80% sold to the local utility as green, baseload power.  The fuel cells provide clean electricity and heat while not requiring any backup capacity.  Both the heat and the electricity are put to good use.

Unconventionally Speaking

Upgrading shale oil

Shale oil has many unique characteristics, some of which can create problems for conventional refineries.  Shale oil produced from in-situ conversion processes have better properties and when the process is designed and operated properly, has the potential to produce oil of such high quality that some of the upgrading and refining process can be eliminated.

Shale oil typically contains 1 to 2% nitrogen. This is a lot compared to conventional crude oils that are usually only .2% nitrogen. This high nitrogen content can poison conventional refinery catalysts.  The nitrogen can be a problem, but also represents an opportunity.  When shale oil is upgraded, an abundance of ammonia, NH3, is produced as a valuable by-product.  The reduced-nitrogen shale oil is then suitable as a petroleum feedstock for conventional refineries.  After nitrogen removal by hydrotreating and or other means, shale oils can contain less than 1 part per million of nitrogen (compared to 0.66 ppm for conventional crude oils).

There are many methods for nitrogen removal.  Many techniques involve simple washes of shale oil with solvents, usually acid solutions; other methods involve special catalysts, including halides of zinc, lead, copper, etc.  Economical catalysts for hydrodenitrogenation include nickel-molybdenum on alumina, cobalt molybdenum on alumina and nickel-tungsten on alumina. Nitrogen removal proceeds in the presence of these catalysts at temperatures and pressures which are also conducive to removal of sulfur and other hydrogenation reactions.  The result is denitrogenated shale oil with less than .3% nitrogen content. (U.S. Patent 4,272,362)

Hydrotreating is typically used to remove sulfur from crude oil, but can also remove nitrogen, and other contaminants like arsenic from shale oil.  In general terms, hydrotreating means the reaction of hydrocarbons with hydrogen, often in the presence of a catalyst.  Hydrotreating crude oil is an old technology that has been undergoing revitalization in the past decade due to more stringent requirements on sulfur content in diesel fuel and the availability of new technology.  British Petroleum contends that the rate of improvement in hydrotreating has matched the speed of technical advancement in computers for the last 10 years.  According to BP, over the past 20 years the sulfur content of diesel has been reduced by two orders of magnitude, while the cost of hydrotreating a barrel of diesel has fallen by 40%.

Catalysts are the key to hydrotreating. There are two main types commercially available, cobalt-molybdenum or nickel-molybdenum.  In a typical hydrotreatment process, crude oil is heated in the presence of hydrogen to temperatures in the range of 300°C – 380°C.  In the presence of the catalysts, hydrogen combines with sulfur to form H2S, and with nitrogen to produce ammonia. Metal contaminants like arsenic are deposited on the catalysts.

Hydrogen sulfide is a dangerous pollutant and requires further processing.  Typically, a solvent like diethanolamine (DEA) is bubbled through the crude after hydrotreating.  Hydrogen sulfide dissolves in the DEA which is then separated from the oil stream.  The DEA is then heated under low pressure, releasing the hydrogen sulfide in concentrated form.  The H2S gas is then treated in a two stage oxidation reaction involving catalysts to form water and pure molten sulfur.  The pure sulfur removed from the crude oil is, in itself, a valuable byproduct.  Ammonia recovered from nitrogen removal is also valuable, either as a byproduct, or as a feedstock for additional chemical processes.

Although shale oil has higher concentrations of nitrogen, it is typically lower in sulfur than many crude oils.  In the right facility, shale oil can be hydrotreated, through a hydrodenitrification process, to form a high quality refinery feed stock with a premium value.  Typical hydrogenation of shale oil requires hydrogen at 600-650 SCF/BBL to remove 1% nitrogen.  Therefore nitrogen removal could consume up to 1,300 SCF/BBL.  The in-situ recovery process used with Geothermic Fuel Cells involves substantial in-ground upgrading of the shale oil product.  As a result, substantially less hydrogen will be required for conventional upgrading in surface facilities.

In addition to the rapidly improving conventional hydrotreating technologies now available, new technical approaches are on the horizon.  For example, ultrasound has now been introduced as a means for low cost hydrotreating of crude oil.  Once nitrogen removal and hydrogenation have been completed, the shale oil will comprise a premium quality feedstock for refining into transportation fuels.  Typical product characteristics anticipated from Green River shale oil originating in the Piceance Creek Basin is as follows:


API Gravity 49
Specific Gravity .784
Sulfur 50 ppm
Nitrogen <1 ppm
Distillation   yields: Weight percent:
<200oC. 32%
200 -275 oC. 38%
275-325 oC. 20%
325-400 oC. 9%
400-538 oC. 1%

Strategic Significance of America’s Oil Shale Resource, Volume II Oil Shale Resources Technology and Economics, Office of Naval Petroleum and Oil Shale Reserves U.S. Department of Energy Washington, D.C., March 2004

For additional information check out these links:



Unconventionally Speaking

Unconventional Return on Energy

The exciting prospect regarding hydrocarbon recovery with our GFCs technology is the idea of self-fueling.   Initially, GFCs are fueled by natural gas or propane. After the resource is brought into production, the GFCs operate off of fuel derived from the resource.

There is a pre-production phase during which the ground around the GFC heaters is warmed sufficiently to establish full production from the collection wells. As the formation is warmed, available fuel gas from the formation gradually increases such that the GFCs become self fueling. Natural gas or propane provides the supplemental fuel for the GFCs during the warm up phase.

The variance between gas yields produced by Fischer assay and those resulting from in-situ heating, like that employed by IITRI (The IIT Research Institute of Chicago), is due to the thermal history of the shale oil as it is extracted. The Fischer assay process is a small batch laboratory procedure which involves rapidly heating oil shale in a closed vessel with an inert atmosphere. The Fischer assay method involves heating a small shale sample to 500°C at the controlled rate of 12°C per minute. At this heating rate the shale sample is raised to maximum retorting temperature in just over 40 minutes. In-situ retorting, by contrast will raise the temperature of oil shale or other hydrocarbon resources much more slowly. This longer temperature regime results in some fundamental changes to oil and gas yields and compositions.

The table below shows the variation between gas composition under Fischer assay (FA) conditions and those under in-situ (IS) conditions.

Table: in-situ Gas Composition

Gas % – FA % – IS
Carbon dioxide – CO2 24 15
Hydrogen – H2 26 45
Methane – CH4 18 20
Higher carbons – C2+ 26 17

 Under the long heating regimes that will prevail under in-situ conditions, like those that will be created by GFCs, oil shale and other hydrocarbons will show decreases in oil yield and corresponding increases in gas yields. Under the longer heating regime, oil yield falls from 100% of assay to 80%. This is due to degradation of the oil as it is exposed to heat for longer periods of time. Oil degradation leads to increased production of “char”, or fixed carbon, which remains on the shale in solid form.   By injecting steam into the pre-heated formation, we can produce “syngas” that can be collected and used by the GFC as fuel.  This allows us to recover an estimated, 18 units of energy for each unit of energy spent.

Unconventionally Speaking

What do you do about water in oil and gas formations?

One concern I hear often is groundwater contamination.  The ground water on our property is non-potable and must be removed before any work begins.

In our geothermic process ground water is first removed from the target formation through a process called “dewatering”.  The dry formation can then be heated.   As part of dewatering, formation is cut off from ground water infiltration with underground dams called “grout curtains”.  After shale oil has been removed and the remaining char has been gasified for additional energy recovery, the formation is secured and left dry.  This is accomplished through a combination of processes.

The first line of defense is complete surface reclamation through a process called “phytoremediation”.  Phytoremediation involves planting a dense community of trees, shrubs, and grass, on the surface overlying the treated formation.  As the plant community grows it forms an increasingly dense network of roots in the topsoil.  These roots absorb moisture, which is then filtered through the plant’s metabolism and is then released to the atmosphere through plant respiration.  Phytoremediation reduces water infiltration into the underground by 90%.  Typical rates of percolation into the subsurface in the Piceance Basin are less than an inch a year.  Phytoremediation will reduce this to less than a tenth of an inch.  If nothing else were done, it would require over a hundred years to accumulate one foot of water in the dry aquifers.  The dry oil shale formation in the Piceance will be over a thousand feet thick.

Through use of guard wells and addition of grout curtains, and possibly the installation of drainage passages under the formation, water will be entirely prevented from accumulating in the treated zone.  Water removed from the formation either through guard wells or through the drainage system will be monitored for pollutants and treated to drinking water standards prior to being released into streams or being reinjected into the existing aquifers.  In any case the process will be carried out by methods that prevent any degradation of ground water quality.