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Depleted Oil Fields? Are your oil and gas revenues declining along with revenues due to reservoir production decline or other well problems? We may be interested in buying your existing oil and gas production lease as we now have investors interested in these acquisitions as well as purchasing depleted oil fields. Alternatively, we may also be interested in a joint-venture with existing producers. Would you like a proven, little-to-no-cost solution that will significantly increase your well's oil and gas production? EOR Technologies represents several technologies that can increase your oil & gas production by 30% to 50%! We
also offer a "guaranteed" joint-venture program for qualified
oil and natural gas properties, wherein we will cover all the investment
and costs of increasing your oil production, at little to no
out-of-pocket expenses. (Must have current reservoir engineering study
and production history.) "Enhanced Oil Recovery"
Coming
July 1st, our new "dedicated" website on:
www.Co2Injection.com
For more information about advertising or sponsorship opportunities call: 800-983-0672
There's
only ONE:
Does your company provide Enhanced Oil Recovery products, services, technologies or other information? You need to advertise your company on "the" website for Enhanced Oil Recovery!
Enhanced Oil Recovery, or "EOR," is the use of any process or technology that enhances the displacement of oil from the reservoir, other than primary recovery methods. Enhanced Oil Recovery methods and technologies' enhancements or improvements of the primary recovery methods are also known as secondary recovery methods and may be utilized in the recovery of oil at any stage of production. Enhanced oil recovery method refers to any recovery method other than primary and the conventional secondary recovery methods through "flooding" (water or fire) or through injecting steam or gas such as nitrogen or carbon dioxide. All tertiary recovery methods are enhanced, but not all enhanced methods are tertiary. Our company acquires and invests in oil and gas production properties that have potential for our Enhanced Oil Recovery technologies. We also buy and invest in gas gathering systems/companies. Cooler, Cleaner, Greener Power & Energy Solutions project development services are one of our many specialties. These projects are Kyoto Protocol compliant and generate clean energy and significantly fewer greenhouse gas emissions. Unlike most companies, we are equipment supplier/vendor neutral. This means we help our clients select the best equipment for their specific application. This approach provides our customers with superior performance, decreased operating expenses and increased return on investment. Cogeneration
Technologies provides
project development services that generate clean energy and
significantly reduce greenhouse
gas emissions and carbon
dioxide emissions. Included in this are our
turnkey "ecogeneration"
products and services which includes renewable
energy technologies, waste to
energy, waste to watts and waste
heat recovery solutions. Other project development
technologies include; Anaerobic
Digester, Anaerobic Lagoon, Biogas
Recovery, BioMethane, Biomass
Gasification, and Landfill Gas
To Energy, project development services.
For more information: call us at: 832-758-0027 We are Renewable Energy Technologies specialists and develop clean power and energy projects that will generate a "Renewable Energy Credit," Carbon Dioxide Credits and Emission Reduction Credits. Some of our products and services solutions and technologies include; Absorption Chillers, Adsorption Chillers, Automated Demand Response, Biodiesel Refineries, Biofuel Refineries, Biomass Gasification, BioMethane, Canola Biodiesel, Coconut Biodiesel, Cogeneration, Concentrating Solar Power, Demand Response Programs, Demand Side Management, Energy Conservation Measures, Energy Master Planning, Engine Driven Chillers, Geothermal Heatpumps, Groundsource Heatpumps, Solar CHP, Solar Cogeneration, Rapeseed Biodiesel, Solar Electric Heat Pumps, Solar Electric Power Systems, Solar Heating and Cooling, Solar Trigeneration, Soy Biodiesel, Trigeneration, and Watersource Heatpumps. Other products and services include: For more information: call us at:
832-758-0027 Enhanced
Oil Recovery and
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DOE's
Enhanced Oil Recovery Program Goal |
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Crude oil development and production in U.S. oil reservoirs can include up to three distinct phases: primary, secondary, and tertiary (or enhanced) recovery. During primary recovery, the natural pressure of the reservoir or gravity drive oil into the wellbore, combined with artificial lift techniques (such as pumps) which bring the oil to the surface. But only about 10 percent of a reservoir's original oil in place is typically produced during primary recovery. Secondary recovery techniques to the field's productive life generally by injecting water or gas to displace oil and drive it to a prouction wellbore, resulting in the recovery of 20 to 40 percent of the original oil in place. However, with much of the easy-to-produce oil already recovered from U.S. oil fields, producers have attempted several tertiary, or enhanced oil recovery (EOR), techniques that offer prospects for ultimately producing 30 to 60 percent, or more, of the reservoir's original oil in place. Three major categories of Enhanced Oil Recovery have been found to be commercially successful to varying degrees:
Each of these techniques has been hampered by its relatively high cost and, in some cases, by the unpredictability of its effectiveness. CO2 Injection Offers Considerable Potential Benefits
The Enhanced Oil Recovery technique that is attracting the most new market interest is carbon dioxide (CO2)-EOR. First tried in 1972 in Scurry County, Texas, CO2 injection has been used successfully throughout the Permian Basin of West Texas and eastern New Mexico, and is now being pursued to a limited extent in Kansas, Mississippi, Wyoming, Oklahoma, Colorado, Utah, Montana, Alaska, and Pennsylvania. Until recently, most of the CO2 used for Enhanced Oil Recovery has come from naturally-occurring reservoirs. But new technologies are being developed to produce CO2 from industrial applications such as natural gas processing, fertilizer, ethanol, and hydrogen plants in locations where naturally occurring reservoirs are not available. One demonstration at the Dakota Gasification Company’s plant in Beulah, North Dakota is producing CO2 and delivering it by a new 204-mile pipeline to the Weyburn oil field in Saskatchewan, Canada. Encana, the field's operator, is injecting the CO2 to extend the field's productive life, hoping to add another 25 years and as much as 130 million barrels of oil that might otherwise have been abandoned.
A turning-point in CO2-EOR advances is a project funded by DOE in the Hall-Gurney field in Kansas that seeks to demonstrate this technology's time has come - providing energy, economic and environmental benefits. A companion project underway in the Hall-Gurney field involves testing the feasibility of 4-D high resolution seismic monitoring of CO2 injection in thin, relatively shallow mature carbonate reservoirs. Incorporating such time-lapsed monitoring data into CO2-EOR programs could dramatically improve the efficiency and economics of using the technology in many Midcontinent fields. New breakthroughs in CO2-EOR recovery technology could further enhance oil recovery in Texas and other oil producing states. One DOE-industry partnership project is investigating gravity-stable CO2 injection in the Permian Basin in West Texas, where the goal is to increase oil recovery in the Scurry Canyon Reef field. DOE Basin-Oriented CO2-EOR Assessments
In February 2006, a series of technical reports released by the Department on Energy (DOE) Office of Fossil Energy highlight the significant potential for state-of-the-art and enhanced oil recovery technologies to significantly contribute to the development of the large volume of remaining undeveloped domestic oil resources in the United States. Ten basin-oriented assessments – four new, three updated and three previously released – estimate that 89 billion barrels of additional oil from currently "stranded" oil resources in ten U.S. regions could be technically recoverable by applying state-of-the-art CO2-EOR technologies.
Additional
work has examined potential improvements in CO2-EOR technologies
beyond the state-of-the-art that can further increase this
potential. This work evaluating the potential of
"game changing" improvements in oil recovery
efficiency for CO2-EOR illustrates that the wide-scale
implementation of next generation CO2-EOR technology advances
have the potential to increase domestic oil The presence of an oil bearing transition zone beneath the traditionally defined base (oil-water contact) of an oil reservoir is well established. What is now clear, and as recently documented in a series of DOE Office of Fossil Energy reports, is that, under certain geologic and hydrodynamic conditions, an additional residual oil zone (ROZ) exists below this transition zone, and this resource could add another 100 billion barrels of oil resource in place in the United States, and an estimated 20 billion barrels could be recoverable with state-of-the-art CO2-EOR technologies. Large volumes of technically recoverable domestic oil resources remain undeveloped and are yet to be discovered in the United States, and this potential associated with CO2-EOR represents just a portion – albeit large, of this potential. Undeveloped domestic oil resources still in the ground (in-place) total 1,124 billion barrels. Of this large in-place resource, 430 billon barrels is estimated to be technically recoverable. This resource includes undiscovered oil, "stranded" light oil amenable to CO2 enhanced oil recovery (EOR) technologies, unconventional oil (deep heavy oil and tar sands) and new petroleum concepts (residual oil in reservoir transition zones).
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About Natural Gas Measurement
Natural gas measurement is needed to accurately measure
the flow of natural gas, whether from an oil and gas production well, gas
gathering system, pipeline delivery point, city gate delivery points for
local distribution companies/natural gas utility companies, as well as
sales to residential, commercial and industrial customers. Natural
gas measurement also includes the physical and chemical makeup of gas mixtures, how the mixtures are affected by temperature and pressure, and how to
best determine and select the best natural gas measurement equipment for
the specific application. Accurate natural gas measurement also includes
the requirements to properly calibrate and maintain natural gas
measurement devices, whether they may be orifices or meters.
About Heater Treaters
A heater treater is utilized in oil and gas production
facilities and gas gathering systems to make and transfer/apply heat to
the natural gas that is produced from one of more production wells. Heater
Treaters prevent the formation of water, ice and natural gas hydrates. These solids can plug the wellhead, chokes and
flowlines. As water, and salt water is a by-product of many natural gas
and oil production wells, the water may cool during the production
process, and up through the well, as it nears the surface or wellhead.
Since chokes in the wellhead restrict the flow of the oil and gas from the
well, temperatures may drop due to the pressure changes of the choke. This
may cause the water or hydrates to freeze and plug the well, thereby
slowing or stopping the oil and gas production.
Glycol dehydrators are utilized in oil and gas production facilities to dry or condition the natural gas before sales to the gathering system or pipeline.
About Gas Gathering:
The physical facilities that accumulate and transport
natural gas from a well to an acceptance point of a transportation
pipeline are called a gas gathering system.
Prior to FERC Order 636 in 1992, many interstate pipeline companies had
a completely integrated supply system that was capable of delivering
natural gas from the wellhead to the ultimate retail gas consumer. But,
following Order 636, which separated gathering, marketing, and
transmission operations, many pipeline companies reorganized and broke
up this system into discrete parts and assigned them to affiliated
companies.
The facilities, functions, and services required for gathering,
processing, and transportation were placed in affiliated companies or
were spun off or sold to other companies. Since most gas prices were no
longer regulated, gas gathering service charges became subject to market
forces and were a function of buyer/seller negotiation, isolated from
the transmission charges imposed by the pipeline transporter.
More about Gas Gathering:
The corporate reorganizations brought about under the influence of FERC
Order 636 caused a shift in the jurisdictional entities regulating the
various facilities and services. The Federal Energy Regulatory Commission
(FERC) had once regulated the entire integrated interstate pipeline
system, but after the reorganizations, FERC became the regulating entity
for only the interstate pipeline transportation and processing facilities
and services. The spun-off or affiliated gathering facilities and services
generally fell under state jurisdiction or other Federal agencies, such as
the Department of the Interior, but in some cases FERC maintained
jurisdiction. Especially unclear, and still contested in 2004, is the
jurisdictional status of some Gulf of Mexico gathering systems.
These cases involve FERC's reclassification of portions of a pipeline's
system operating on the Outer Continental Shelf (OCS) as
non-jurisdictional gathering facilities and FERC's determination that a
pipeline company can transfer those facilities to its non-jurisdictional
gathering affiliate. The key consideration in these, and similar onshore
cases, is that FERC retains rate jurisdiction over those reclassified
facilities that the pipeline retains and thus may regulate rates charged
for transportation on the pipeline's own gathering facilities performed in
connection with jurisdictional transportation. Rates on non-jurisdictional
facilities are market based and not subject to FERC oversight or review.
Consequently, some shippers have raised complaints that rates on
non-jurisdictional facilities may exceed a reasonable rate by an undue
degree.
As a result of FERC's decision in Order 636 to promote competition by
requiring interstate pipelines to "unbundle" their previously
bundled sales and transportation into separate services and to transport
natural gas for all qualified shippers, some such pipelines have sought to
shed OCS facilities that primarily perform a gathering function.
Accordingly, those pipelines have asked FERC to reclassify OCS facilities
that were previously classified as transportation, and to authorize
"spin-downs" of OCS gathering facilities to affiliates.
To differentiate jurisdictional transportation and non-jurisdictional
gathering for pipelines, FERC for many years has employed two principal
tests. Under the "behind-the-plant" test, facilities upstream of
compressors and processing plants (i.e., toward the wellhead where the gas
comes out of the ground) were presumptively gathering facilities, while
facilities downstream of the plants (i.e., toward the consumer) were
presumptively transportation facilities. For gas that requires no
processing, FERC employed a "central-point-in-the-field" test,
under which lateral lines that collect and transport gas from separate
wells that then converge into a single large line were classified as
gathering facilities, while facilities downstream of the collection point
in a field were classified as transportation. Since 1983, FERC has
subsumed those two tests into a "primary function" test that
focuses on a number of physical factors (e.g., length, diameter, and
configuration of a pipeline) and certain other criteria, to determine
whether facilities are primarily devoted to gathering or transportation.
Under the primary function measure, no one factor is determinative, nor do
all factors apply in every situation.
FERC developed its primary function test in the context of onshore
gathering patterns. For natural gas produced on the Outer Continental
Shelf (OCS), pipelines generally are configured differently and typically
do not gather gas at a local, centralized point within a field as they
would onshore to prepare it for traditional transportation. As stated in
EP Operating Co. v. FERC (5th Circuit, 1989), "Rather, on the OCS,
relatively long lines are constructed to carry the raw gas from offshore
platforms where 'only the most rudimentary separation and dehydration
operations' are conducted, to the shore or a point closer to shore, where
it can be processed into 'pipeline quality' gas." It also notes that
pipelines on the OCS must construct large pipes to carry (often over a 100
miles away) the raw gas from offshore rigs to the shore for processing. In
response to the practical and physical differences between onshore and
offshore pipeline configurations, FERC modified its primary function test
for the OCS to allow for the increasing length and diameter of OCS
gathering lines, and later announced that it would "presume
facilities located in deep water [over 200 feet] are primarily engaged in
gathering or production."
* Some of the above information from the Department of Energy website with permission.
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