Flue Gas, Greenhouse Gases, & Eor

Oklahoma City, OK EPRS Energy Co. Inc. 405-401-9426 Flue Gas, Greenhouse Gases, & EOR Table of Contents

ABSTRACT .......................................................................................................... 1 EOR AND CO2 SEQUESTRATION ......................................................................... 2 FLUE GAS COMPOSITION ..................................................................................... 3 FLUE GAS PROCESSING ....................................................................................... 3 FIGURE 1. US MAP OF FLUE GAS LOCATIONS ..................................................... 4 PROCESSING FLUE GAS NOX ................................................................................ 4 PROCESSING FLUE GAS SO2 ................................................................................ 5 PROCESSING FLUE GAS MERCURY, HG ................................................................ 5 EOR, GHGS, AND NITROGEN PROCESSING ......................................................... 6 FIGURE 2. US MAP OF LOCATIONS FOR GEOLOGICAL CO2 SEQUESTRATION ........ 7 CO-OPTIMIZATION FAILURE ................................................................................. 8 CO-OPTIMIZATION SUCCESSES ............................................................................. 8 BITUMEN GASIFICATION .....................................................................................10 CO-OPTIMIZING EOR AND REFINING ..................................................................10 LONG LAKE STATISTICS .....................................................................................12 A CO-OPTIMIZED PIPELINE FOR EOR..................................................................12 SUMMARY ..........................................................................................................14 APPENDIX: NITROUS OXIDE EMISSIONS .............................................................15 Abstract Co-optimization of greenhouse gas (GHG) sequestration (GHGS) with enhanced oil recovery (EOR) using CO2 seems an obvious opportunity, especially in the senses of engineering design challenge and scientific investigation. Processing flue gases from power plants seems compatible with EOR. The actual nature of typical flue gases raises several difficult issues, however. Cement plants, steel mills, and aluminum smelters are often much larger targets than power plants, however, and will probably provide economy of scale to improve co-generation and scrubbing economics. Nitrogen and nitrogen compound concentration in flue gases are very negative factors for EOR. Here is a brief primer on flue gas composition and processing. Then some issues of flue gases’ suitability for EOR are briefly addressed. Some examples of successful cooptimizations and also failures are presented. Finally, excellent new examples of integrated GHGS designs for EOR serve to provide engineering, scientific, and civic excitement. A perspective on the problem of nitrous oxide emissions is provided in the Appendix.

Jim Myers, MPE

Flue Gas, Greenhouse Gases (GHG’s), and EOR, 2009-09-07

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EOR and CO2 Sequestration New opportunities for environmental remediation, increased oil production, and job creation are emerging due to recently identified global and US priorities to reduce emission of greenhouse gases (GHQ’s) into the atmosphere. Naturally, CO2 withheld from such release must be impounded (sequestered) somewhere. The mature and successful enhanced oil recovery (EOR) technique of miscible displacement relies primarily on programs to inject CO 2 into oil reservoirs as a “solvent” to mix and dissolve with reservoir oil, including additional injection of various grades of water for reservoir fluid mobility control. There is a growing inventory of existing CO 2 sequestration (CO2-S) EOR (CO2-S-EOR) projects, and an expanding volume of related literature on screening for and co-optimization of new CO 2-S-EOR opportunities. Energy and environmental agencies have strong interest in co-optimization of EOR by gas injection and greenhouse gas sequestration (EOR-GHGS) by disposal of CO2, CO, oxides of nitrogen, H2S, SO2, etc., as exist in flue gases and especially in output of oil and gas processing plants. There are enough EOR-GHGS examples around the world (Algeria, Australia, Canada, Norway, etc.) in operation or post-proposal stages to help investigators and designers avoid previous wrong turns in planning. Two prominent Canadian projects are the widely publicized Encana Weyburn Pilot Project in Saskatchewan and the Zama oil field in Alberta. The Zama Field project injects both CO2 and H2S from its nearby processing plant into the top of a Devonian pinnacle reef. Oil is produced from a completion near the reef bottom, making this project somewhat gravity-stable. A shallower well serves to monitor leakage of these “acid gases.” These projects also use the term “carbon sequestration.” E&P companies are prepared to seek industrial sources of CO2 and other greenhouse gases (especially output from gas processing plants which scavenge these gases from crude oil and/or natural gas, and perhaps flue gases from power stations), and to formulate plans to sequester these undesirable emissions underground. So, actual feasibility of co-optimizing EOR, especially the gas-injection processes of immiscible and miscible displacements, is a crucial issue to be questioned in every realistic sense. 

Characterization of flue gas compositions, especially flue gases from the gas-fired and coalfired power plants which dominate the US power utility industry. Can flue gases be directly injected into oil reservoirs for these EOR processes?

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If processing is required to prepare flue gases for EOR injection, what are the nature, scale, and expense of these processes? Will existing flue gas processing methods be adequate, or must additional techniques be researched?

CO2 is NOT the only greenhouse gas: nitrogen oxides, NOX, are considered MUCH more hazardous, for example. Unprocessed flue gases are seldom good candidates for EOR by gas injection due to their very high (78-80%) atmospheric nitrogen (N2) content.

Jim Myers, MPE

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Flue Gas Composition Fuel Choices & OSHA: OSHA TWA Natural Fuel Oil Coal *ceiling, ppm Gas Chemical Species Nitrogen, N2 78-80% 78-80% 78-80% Carbon dioxide, CO2 5000 10 – 12% 12-14% Oxygen, O2 2-3% 2-6% 7% Carbon monoxide (CO) 50 70-110ppm 70-160ppm Nitrogen oxides (NOx) NO-25, NO2-5* 50-70ppm 50-110ppm 1% Ammonia, NH3 50 Used in removal of NOx. Sulphur dioxide (SO2) H2S-20*, SO2-5 180-250ppm >2,000ppm Hydrocarbons (CXHY) <60ppm Mercury, Hg >200lb/year/plant Fly Ash none minimal 12% Table. Summary of flue gas composition ranges for power plants fueled by gas, oil and coal. Given these inconvenient contaminants it is no surprise that EOR by flue gas injection has been discontinued, sometimes converted to nitrogen injection, in most projects which attempted that EOR implementation. OSHA’s TWA limits are allowed for 8-hour personnel shifts. OSHA’s Ceiling limits should not be exceeded at any time for personnel.

Flue Gas Processing An example of flue gas processing sequence is: 

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While flue gas is still hot, incineration under controlled temperature and pressure in a chamber, which may include a catalyst system, perhaps injecting a reagent, can produce required chemical reactions. Incineration reaction results depend on composition, temperature, pressure, catalysis, and residence time for which these conditions apply. Co-generation heat exchangers can scavenge heat from this hot gas and provide cooling. Sorbents like activated carbon, lime, or sodium salts, can be injected to adsorb mercury or SO2 gases. Electrostatic precipitators (ESP’s), wet or dry, can capture particulates like sorbents, fly ash, or soot, in a wide range of temperatures. These devices have been adapted to “ionic” household air cleaners. Wet scrubbers can accept high-temperature moist flue gas to remove particulates and/or gaseous contaminants. Dry scrubbers (cooling followed by carbon, lime or sodium reagent injection, and fabric “baghouse” filter) can remove particulates.

Carbon monoxide, CO, is a colorless, odorless gas that is tasteless and non-irritant. It is somewhat less dense than air and, although it is a product of imperfect combustion, it is inflammable. Carbon monoxide, like oxygen, has an affinity for iron-containing molecules, and it is about 210 times more effective than oxygen in binding to the ironrich hemoglobin in human blood; thus arises its tragic toxicity so often demonstrated in accidents and suicides. Blast furnace gas contains 25% carbon monoxide. Coal gas, which was used as a fuel in Europe up until North Sea (natural) gas became plentiful, contains 16% CO.

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Figure 1. US Map of Flue Gas Locations http://energy.er.usgs.gov/health_environment/co2_sequestration/co2_illustrations.html

Characteristics of power plant emissions: USEPA - U.S. Environmental Protection Agency, 2002, eGRID 2.01. Available online at:

http://www.epa.gov/cleanenergy/energy-resources/egrid/index.html

Processing Flue Gas NOx Nitrogen oxides (NOx) occur in all fossil fuel combustion, through oxidation of atmospheric nitrogen (N2) and also from organic nitrogen fuel content, and flue gas NO x concentrations are enhanced by high combustion chamber temperatures. Nitric oxide (NO) oxidizes with time and forms nitrogen dioxide (NO2), a brown, toxic, water-soluble gas that can seriously damage the lungs, contributes to acid rain and helps to form ozone. With or without Selective Catalytic Reduction (SCR), ammonia (NH3) ions react with both species: 4NH3 + 6NO  5N2 + 6H2O, 8NH3 + 6NO2  7N2 + 12H2O. Use of ammonia in NOx reduction technologies or for flue gas conditioning can have a substantial balance-of-plant impact on coal-fired plants. Ammonia adsorbs on fly ash within the flue gas processing system as both free ammonia and ammonium sulfate

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compounds, however. This ammonia can then desorb during subsequent transport, disposal, or use of the fly ash. This desorption of ammonia presents several technical and environmental concerns as fly ash disposal occurs in surface water and landfills. SCR can optimize the NH 3-NOx reduction with a minimum of downstream problems developed by ammonia slip. Since nitrogen oxide emissions are dominated by agricultural fertilizer use, however, they may not be valid sequestration or removal targets for flue gases. Nitrous oxide, N2O, is considered an especially hazardous input to the worldwide stratospheric ozone layer. See the Appendix on agricultural nitrous oxide emissions. Processing Flue Gas SO2 Almost all hydrogen sulfide, H2S (OSHA “ceiling” = 20ppm), oxidizes within a day to SO2. SO2 is smelly, toxic, and contributes to acid rain. SOX can be removed from flue gas by dry alkaline adsorption before particulate removal. Addition of sodium bicarbonate into the flue gas causes it to react in the following manner: 2NaHCO3  Na2CO3 + H2O + CO2. This allows for the sodium carbonate to react with the oxygen and sulfur dioxide in the flue gas to form sodium sulfate and carbon dioxide as follows: Na2CO3 + SO2 + 0.5CO2  Na2SO4 + CO2. With the creation of solid sodium sulfate, the desulfurization of the gas is complete, awaiting capture of solid sodium sulfate particles. In wet limestone scrubbing after particulate removal, limestone slurry in water comes into contact with the flue gas SO2 + CaCO3 + H2O  CaSO3 + H2O + CO2. This calcium sulfite (CaSO3) is then oxidized to form calcium sulfate, CaSO4, gypsum. Contaminants in “sheet rock” made from recycled gypsum are suspect household environmental hazards. Processing Flue Gas Mercury, Hg Since the average mid-sized coal-fired plant releases at least 200-300 pounds of mercury per year, and mercury pollution has immense environmental impact, mercury emission control is receiving large “doses” of money and professional attention, and benefits from specialized industry knowledge. Oxidized mercury, Hg2+, and Hg bound to particles are easily removed with ESP’s or wet flue gas desulfurization (FGD); removal of free elemental mercury is more challenging. Technologies that impact mercury speciation include most existing air pollution control methods: Selective Catalytic Reduction (SCR) mercury oxidation is gaining emphasis for mercury removal, since it is often already used to remove NO x; sorbent injection, dry

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scrubbers, dry and wet ESP's, and wet scrubbers are oldest and most commonly employed methods. The accepted existing activated carbon mercury sorbent process is that it takes many, many times more pounds of carbon per pound of mercury removed. Since the average mid-sized plant releases at least 200-300 pounds of mercury per year, it equates to anywhere from four hundred thousand to almost four and one half millions pounds of injected carbon needed per year. Once polluted with mercury and captured, this carbon is useless, cannot be recycled, and must sit in a landfill. ADA’s patented Mercu-RE process has been introduced to provide a sorbent that can be detached after capture to yield elemental mercury for resale. The Cloric acid laboratory process produces HgOCl: Hg + HClO3  HgOCl + H2O, and can also be used to oxidize NOX pollutants, and those can then pass through the system as nitrogen gas, without the problem of ammonia slip contaminating fly ash. http://www.wshinton.com/

EOR, GHGS, and Nitrogen Processing US Federal agencies DOE, DOI (especially USGS), and EPA are showing strong interest in co-optimization of EOR by gas injection and greenhouse gas sequestration (GHGS) for disposal of COX, NOX, H2S, SO2, CXHY, etc. There are enough EOR-GHGS examples around the world (Algeria, Australia, Canada, Norway, etc.) in operation or post-proposal stages to help researchers, planners, and developers avoid previous wrong turns in planning. Regarding power stations, separation of greenhouse gases from N 2 in flue gases seems a dominant problem, since N2 injection is only favorable for gravity-stable EOR displacement of light oils (API Gravity > 30 °) at depths beyond the common range of oil reservoir depths. So, most US oil fields would be eliminated “out” of screening processes for injection of raw flue gas. A possible example that might screen “in,” regarding depth, reservoir pressure, and temperature, is the Hawk Point Field of Campbell County, WY, a complex PermianPennsylvanian Minnelusa interbedding of with eolian sands. Naturally, such a complex reservoir has large variations in vertical permeability, flow barriers, and is generally very heterogeneous. Its reservoir has thickness 50’, porosity 12%, and permeability 60mD reported. Hawk Point reservoir depth is 11,500’, with 260 °F Temperature and 4,472psi initial pressure. Providing its crude oil contents are light enough (API Gravity > 30 °) and temperature is not too high (increases oil viscosity), Hawk Point a good candidate to further screen for a pilot project to investigate EOR using injection of nitrogen or flue gas. On primary production in 1986 and waterflood in 1989, in 2001 Hawk Point Field was already a candidate for abandonment due to economic limit.

Jim Myers, MPE

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Figure 2. US Map of Locations for Geological CO2 Sequestration http://energy.er.usgs.gov/health_environment/co2_sequestration/co2_illustrations.html

Oil and gas field classifications: NRG Associates, 2001, The significant oil and gas fields of the United States: NRG Associates, Inc., Colorado Springs, Colo., [includes data current as of May 23, 2001—database available from NRG Associates, Inc., P.O. Box 1655, Colorado Springs, CO 80901].

USGS: CO2 sequestration “Based on current projections, the United States faces the need to increase its electrical power generating capacity by 40% over the next 20 years and its total energy consumption by 24% by the year 2030. Fossil fuel usage, a major source of carbon dioxide emissions to the atmosphere, will continue to provide the dominant portion of total energy in both industrialized and developing countries. Overall reduction of carbon dioxide emissions will likely involve some combination of techniques, but for the immediate future, sequestration of carbon dioxide in geological reservoirs seems especially promising, as existing knowledge derived from the oil and gas production industries has already helped to solve some of the technological obstacles. The USGS has been studying geologic options for storing CO2 in depleted oil and gas reservoirs, deep coal seams, and brine formations.” http://energy.er.usgs.gov/health_environment/co2_sequestration/

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Co-optimization Failure The deepest oil reservoirs are generally shallower than 20,000 feet. The Semitropic Field in California produced oil from an interval between 17,610-18,060 feet. Heat levels at those depths eventually "cook" the oil, converting it to natural gas. Mexico’s Cantarell Field is considered the world’s biggest N 2-injection project, producing 500,000 BO/D incremental in recent reports. Bechtel/IPSI’s 2001 design report explores all the problems with flue gas injection and several other processes, culminating in the choice of N2 injection to provide pressure maintenance, immiscible displacement, and increased production in the huge Cantarell project. That report all but eliminates the practical potential for flue gases as EOR solvents. The extensive contamination of flue gases, reported in Table above, makes their processing to eliminate N2 a chemical engineering design nirvana, but a maintenance infinite nightmare. GHG contaminants in flue gas, including CO X, NOX, and sulfur compounds, are associated with corrosion and/or toxicity. In the “solvent” gas injection EOR processes they would not be processed once; they would be processed indefinitely in cycles for the life of the project. www.ipsi.com/Tech_papers/cantarell2.pdf

Co-optimization Successes While treatment of flue gas from power generation plants to produce CO 2 for injection in EOR projects is theoretically feasible, typical contamination by nitrogen and sulfur compounds limits its practicality. Flue gases from coal-fired plants also contain metals. Necessity to cool, separate, and compress these flue gases adds additional economic and operational challenges. Other sources are emerging, however, and successful EORGHGS co-optimization projects are on the horizon. The oldest and best-known of these is Encana’s and Apache’s Weyburn-Midale CO2 Project. Neither these projects nor Apache’s Zama project rely upon gas sources with the typical composition problems summarized above. The Weyburn-Midale project’s CO2 is transported via pipeline from the Dakota Gasification Company’s Great Plains Synfuels plant’s coal-based generating plant at the Beula, ND. The Great Plains Synfuels plant design features world class design sophistication. The design includes reaction components yielding sales of liquid nitrogen, krypton, and zenon, solid ammonium sulfate, and phenol and cresylic acid liquids. Enhance Energy Inc. has entered into long term CO2 Supply agreements with both Agrium Inc. and North West Upgrading Inc. The supply of CO 2 will be used in EOR projects under development by Enhance Energy, including joint ventures with Fairborne Energy Ltd. Both Agrium and NWU CO2 supplies are high purity streams that are ideal for EOR projects like Rowley field and the two Clive fields. Unlike flue gases from power generation from fossil fuels, the outputs from the fertilizer plant and bitumen refinery benefit from:

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No reliance upon fossil fuel combustion with atmospheric air with its N2 concentration of about 80%. Thus the NOX fraction is not fundamentally inevitable. Of course Agrium retains the Nitrogen fraction to produce that vital fertilizer component. Highly controlled and engineered specific chemical reactions take place in high-pressure reactor vessels. These controlled closed systems provide reaction control for vitally predictable reactions, results, and exhaust compositions. At least one of these installations was designed with generation of pure CO2 and/or hydrogen among its primary design priorities.

Figure 3. Schematic process design for Dakota Gasification Company’s Great Plains Synfuels plant’s coal-based generating plant at the Beula, ND, which provides the high-grade CO2 supply for the Weyburn-Midale Project operated by Apache and Encana in Saskatchewan.

Alberta’s Agrium is a major retail supplier of agricultural products and services in North and South America. A leading global wholesale producer and marketer of all three major agricultural nutrients, Agrium is a leading specialty fertilizer supplier in North America. North West Upgrading (NWU) of Alberta, a bitumen refiner committed to environmental and practical sustainability, has chosen a gasification process for new their bitumen refinery. http://www.ptrc.ca/weyburn_overview.php http://www.apachecorp.com/Operations/Canada/Stewardship/EOR.aspx http://www.encana.com/operations/oil/weyburn/ http://www.enhanceenergy.com http://www.northwestupgrading.com http://agrium.com/ http://www.netl.doe.gov/technologies/carbon_seq/core_rd/mva/41149.html

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Bitumen Gasification The huge molecules typical in a heavy oil or bitumen place ultimate refining emphasis on converting the large molecules into the smaller molecules of many marketable products. As an example of older bitumen refining processes, at the Syncrude ventures extracted bitumen is fed into a vacuum distillation tower and three cokers (thermal hydrocrackers) for primary upgrading. The resulting products are then separated into naphtha, light gasoil, and heavy gas-oil streams. These streams are hydrotreated to remove sulfur and nitrogen impurities to form light, sweet, synthetic crude oil (32° API). Sulfur and coke (solid bitumen residue) are by-products. Like Syncrude’s bitumen extraction by mining, that 1975 refining process became operational in 1978, and is somewhere between ancient and modern. A major innovation has been added, however, to provide improved options for refining of heavy oils and bitumens -- gasification. Gasification allows efficient elimination of environmental waste product problems, such as coke, sulfur compounds and metals, and significant reduction in consumption of natural gas and water resources. The entire process happens within in a reactor, making it possible to capture all of the CO2, virtually pure, before it is released into the atmosphere. Alberta-based North West Upgrading has chosen this new option, and reports these advantages for their choice of a gasification process for their new bitumen refinery: It will be fully operational in 2013.        

Recover sulfur and sell it to the market Produce critically needed ultra low sulfur diesel Eliminate coke and ashphaltenes as a disposal problem Eliminate the use of natural gas as a feedstock for hydrogen Recycle high quality diluent for transportation of heavy oil to customers Significant quantities of hydrogen for upgrading, refining and petrochemicals Recovery of heavy metals from the bitumen feedstock which would otherwise be lost economically and become potential environmental problems, Carbon capture and storage solution: production of pure CO2, ideal for EOR in nearby reservoirs of much lighter grades of crude oil.

http://www.northwestupgrading.com http://www.gasification.org/

Co-optimizing EOR and Refining Long Lake is the first of these integrated oil sands projects to combine Steam Assisted Gravity Drainage (SAGD) with the proprietary OrCrude™ technology of OPTI Canada, hydrocracking, and gasification, to produce a premium synthetic crude oil (syncrude). The input bitumen has API gravity less than 10° and is sour; Long Lake’s syncrude

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output is sweet and light, with gravity API gravity of 39°, low nitrogen, and superior qualities.

Figure 4. Nexen and OPTI’s Long Lake facility is one of the World’s most sophisticated and thoughtful designs, combining proprietary Or-Crude processing technology, further refining by gasification to produce hydrogen for hydrocracking and syngas for SAGD, diluent manufacture and recycling, sulfur recovery, and producing a premium synthetic crude oil suitable for further refining to produce valuable fuels, solvents, and lubricants.

The co-optimized Long Lake system addresses problems of SAGD bitumen production and bitumen processing:     

recovery of bitumen sulfur content disposal or marketing of solid bitumen residue (coke) high cost of natural gas to generate steam, power pumps, fuel refining equipment, and produce hydrogen cost and availability of diluent, which is manufactured and recycled in OrCrude™ process, ultimate cost of recovering, transporting, refining, marketing, and delivering bitumen and byproducts.

This energy-efficient technology uses A-fuel to produce the synthetic fuel gas (syngas) required to supply the commercial SAGD operation, a cogeneration facility and the Upgrader, as well as hydrogen to feed the hydrocracker. The gas is also burned in a cogeneration plant to produce electricity for on-site use and sold to the provincial electricity grid.

Jim Myers, MPE

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After treating, diluted bitumen is fed into the Upgrader, consisting of a proprietary OrCrude™ unit, a gasifier, and a hydrocracker. The patented OrCrude™ carbonrejection technology uses conventional distillation, solvent de-asphalting and thermal cracking to recycle diluent, removes heavy components (asphaltene residue, or “A-fuel”) and upgrades the remaining content. Remaining content is upgraded by hydrocracking to syncrude. A-fuel is gasified to the synthetic fuel gas (syngas) to generate steam, electricity, and hydrogen for the hydrocracker. Conventional stand-alone SAGD operations purchase natural gas, typically their largest cost, to generate steam for their wells. Similarly, many upgraders purchase natural gas to form hydrogen. Long Lake Statistics The Long Lake Upgrader’s energy conversion efficiency is about 90%, compared to 75% for a typical bitumen-fed coker, providing about $10/bbl operating cost advantage. Thus Nexen produces its syncrude from Long Lake bitumen at the industry’s lowest operating cost. Nexen estimates combined SAGD, cogeneration and upgrading operating costs are expected to average about $22/bbl, substantially lower than coking or other upgrading processes as a result of the reduced need to purchase natural gas. Nexen expects ongoing capital to average between $5/bbl and $10/bbl depending on well spacing, well depth/length and recovery factor. Phase 1 development includes approximately 70,000 barrels per day (b/d) of bitumen production from 81 SAGD well pairs. Recovered bitumen will be converted into approximately 60,000 b/d of premium syncrude and the products mentioned via onsite upgrading. Regulatory approvals are in place for an additional 140,000 b/d of bitumen extraction and 70,000 b/d of upgrading capacity. A Flash-animated diagram of Nexen’s 2001 Alberta Long Lake bitumen gasification refinery Steam and integrated Assisted Gravity Drainage (SAGD) project is viewable at http://www.longlake.ca/project/bitumen.html or http://www.longlake.ca/project/bitumen.swf.

A Co-optimized Pipeline for EOR Enhance Energy’s Alberta Carbon Trunk Line (ACTL) will gather CO 2 from sources in the Alberta’s Industrial Heartland region and transport the CO 2 to existing mature oil fields throughout south-central Alberta. These oilfields will see significant increases in production, as CO2 is permanently stored in the reservoir. This capture and permanent storage of CO2 will result in significant reductions in emissions of greenhouse gases in Alberta. The initial supply of CO 2 will come from West Upgrading Inc. and Agrium Inc, at the pipeline’s North end, North of Edmonton in Alberta’s Heartland Industrial Region. Drying and compression units located on those

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sites will prepare the CO2 for transportation. Agrium is a major international manufacturer of fertilizers. NWU processes Athabasca bitumen by a gasification process mentioned in the Bitumen Gasification section below. ACTL will have a design capacity of 40,000 tonnes per day with initial throughput planned at 5,000 tonnes per day. In the initial phase, the pipeline project will have the same impact as taking 330,000 cars off the road. This effect will expand to become equivalent to 2,600,000 cars at full capacity. ACTL will provide environmental benefits for Alberta and globally. http://www.enhanceenergy.com/

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Summary Without extensive treatment of flue gases, EOR and GHGS from power plants will not co-optimize except in exceptional and infrequent applications. GHGS of flue gases should then be directed toward storage in less valuable reservoirs, like depleted natural gas reservoirs, gas-depleted low-grade coal beds and coal beds too thin or deep for mining, etc. EOR-GHGS co-optimization using more highly engineered sources is mentioned above, in the Co-optimization Success section. CO2 sources are a fertilizer plant and a bitumen refinery. Those projects are practical, and will be online in the very near future EPRS will continue to investigate greenhouse gas processing and storage, including carbon capture by CO2 sequestration, using current research and operating results. EPRS is prepared to seek DOE, EPA, and/or DOI grants to cast light on scientific and logistical problems that obstruct long-term international and US goals. Commercial cooptimization with EOR needs pilot projects. Some pilot projects for EOR-GHGS co-optimization would be helpful for research and demonstration purposes, however. Just west of Hobbs, NM, are Xcel’s Maddox and Cunningham gas-fired power stations, for example. Their minor flue gas outputs could be combined for processing, and there are small oil fields nearby perfect for EOR pilot projects. GHGS in saline aquifers should be considered with great care, because they may eventually be needed to produce fresh water with desalinization technologies. Contaminating them with flue gas contaminants could render that water much less useful. The perhaps-obvious temptation to connect and co-optimize EOR’s need for carbon dioxide with CO2 emission from common sources like power plants may deserve reconsideration. Capture of CO2 will be most economical when combined with cogeneration and especially with custom process designs with integrated carbon capture. Several excellent examples of such designs, incorporating thermal recovery and refining bitumen, fertilizer manufacture, miscible recovery of light oils using CO 2, recovery of sulfur and/or metals, hydrogen synthesis, and/or CO 2 pipelines are included here. The most obvious targets for sequestration are industrial installations of very large scale, like steel mills and aluminum smelters, where nitrogen compound emission contents can be carefully managed.

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Appendix: Nitrous Oxide Emissions Nitrous Oxide: A Necessary Evil Of Agriculture, by Richard Harris http://www.npr.org/templates/story/story.php?storyId=112288478

August 28, 2009 Scientists are surprised to discover that a gas produced mainly in agriculture is doing more to damage the Earth's ozone layer than synthetic chemicals such as chlorofluorocarbons. The culprit is a gas called nitrous oxide, known in your dentist's office as laughing gas. But in the stratosphere, it's no laughing matter. The Earth is protected from harsh ultraviolet sunlight by a layer of ozone up in the stratosphere. That layer was being depleted by synthetic chemicals used in aerosol spray cans, refrigerators and air conditioners. We averted global disaster by phasing out those chemicals with a treaty called the Montreal Protocol. But the Montreal Protocol is silent about nitrous oxide. Nitrous oxide has always been a normal part of our atmosphere, "but since industrialization, its concentration has been going up," says A.R. Ravishankara at the National Oceanic and Atmospheric Administration in Boulder, Colo. Now that synthetic chemicals are waning in the atmosphere, he wondered if other gases posed any environmental threat. As he reports in the online edition of Science magazine, nitrous oxide, a byproduct of agriculture, is a serious problem for our planet. "There's so much being emitted, that right now, nitrous oxide emissions would be the largest ozone depleting gas emissions today, and it will continue to be in the future," Ravishankara says. Holes In The Ozone Nitrous oxide doesn't threaten to devastate the Earth's ozone layer the way the synthetic chemicals did. But it's still eroding a bit of our planetary sun shield, so it's increasing the risk of skin cancer, among other concerns. Ravishankara estimates that by the end of the century, we will have 4 percent less ozone in the stratosphere than we would have had before the Industrial Age, as a result of nitrous oxide. The biggest ozone problem is over Antarctica. There, the ozone thins to such an extent each autumn, scientists call it an "ozone hole.” That hole is slowly on the mend, and Ravishankara says he expects that healing to continue over the coming decades. "It turns out that nitrous oxide does not have a deleterious effect on the ozone hole. Its effect is on the global ozone layer," he says. That's because the ozone hole is influenced by supercold clouds found only over the poles. Those clouds release chlorine, which destroy ozone, but they actually neutralize nitrous oxide. So that's the good news. The Downside Of Fertilizer

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The bad news is that it isn't easy to reduce human production of nitrous oxide. Cindy Nevison of the University of Colorado says controlling chlorofluorocarbons and other synthetic chemicals that destroy ozone was relatively easy, since just a few factories produced them. "Whereas nitrous oxide is produced by microbes in the soil, and humans have greatly increased the amount of nitrogen available to these microbes," Nevison says. When we spread nitrogen fertilizer on the soil, we also feed those bacteria. And they produce more nitrous oxide. Bacteria in seawater also produce nitrous oxide when the fertilizer runs down the rivers and out to sea. Nevison says factories and automobile tailpipes produce some nitrous oxide, but not all that much. "I think that limiting nitrous oxide is going to be more difficult than, for example, limiting carbon dioxide emissions. And we know how difficult that is," she says. That's because we need nitrogen — it's an essential part of protein. Carbon dioxide comes mostly from smokestacks and tailpipes. "You can get your energy from other sources than carbon, but you really can't get your food from sources other than nitrogen." We can't phase out nitrogen fertilizers, Nevison says. And studies show we could make only a modest difference if we used them more carefully. And it's not just the ozone layer that's at issue here. Nitrous oxide also contributes to global warming — so there's another important reason to pay attention to this oftenneglected gas. KEYWORDS: Processing: incineration, co-generation, dry alkaline adsorption, ESP, scrubbing, maps. Reservoir Engineering: Enhanced oil recovery (EOR): miscible and immiscible displacement. Hawk Point Field, Cantarell Field, Semitropic Field, Weyburn Pilot Project, Saskatchewan, Zama oil field, Alberta, EOR, EPA, DOE, IEA, EIA of US DOE, Enhance Energy's Alberta Carbon Trunk Line (ACTL), Enhance Energy, Alberta Carbon Trunk Line, ACTL, Nexen, Long Lake Upgrader, Long Lake Project, gasification, Steam Assisted Gravity Drainage (SAGD), Steam Assisted Gravity Drainage, SAGD, bitumen, diluent, integrated oil sands project, Bitumen Gasification, synthetic crude oil, Syncrude, coke (solid bitumen residue), petroleum coke, ultra low sulfur diesel fuel, thermal hydrocrackers, hydrocracking, North West Upgrading (NWU), Agrium, agriculture, Fairborne Energy Ltd., Rowley field, Clive fields, GHG, GHG's, GHGS, steel mills, aluminum smelters, carbon electrodes, OrCrude™, OPTI Canada, Athabasca oil sands, Encana Weyburn Pilot Project, Encana, Dakota Gasification Company, Apache’s Weyburn-Midale CO2 Project.

Jim Myers, MPE

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