THE BUSINESS PROCESS OF SUPPLY, TRANSMISSION, AND TRADING

SAP for Oil & Gas supports the management and execution of bulk supply chain activities, from initial planning to final settlement. Our solutions automate and streamline key activities, including:

• Bulk supply chain planning and optimization – SAP solutions enable you to plan and optimize key aspects of your supply chain, from long-term forecasting to operational planning, integrating them into daily operations and scheduling processes. You can also use information from execution and settlement activities to create plans, ensuring that all processes within the supply chain have a common heritage.
• Bulk supply chain operations and scheduling – With SAP solutions, you can manage immediate and short-term operations and scheduling. You can also schedule transportation and pipelines, manage inventory and contract operations, and capture custody transfer documentation.
• Bulk supply chain execution and settlement – SAP solutions streamline the deal-to-cash process loop, enabling you to update inventory, monitor product movements, and manage inbound and outbound invoicing. You can also apply execution information to planning and operations process cycles for ongoing and long-term planning.
• Bulk supply chain reporting and analytics – SAP solutions support decision-making and strategy setting, helping you gather activity and performance data from many different sources. Using flexible report structures, analysts and planners can monitor supply chain activity at every process step and provide feedback on an ongoing basis as well as at periodic review points.
• Physical oil and gas commodity trading – Working with the most heavily traded commodities in the world, you can capture deals, manage contracts, monitor positions, and integrate trading into the bulk supply chain. Because trade volumes are very large, companies can use bulk transport methods, such as marine vessels and pipelines, to achieve delivery.
• Oil and gas paper trading and risk management – With SAP solutions, you can mitigate the risks of volatile market conditions – hedging your positions in commodity markets by executing paper trades for futures, options, and swaps. You can use a trading exchange or work directly with partners in over-the-counter deals. You can also use mark-to-market and value-at-risk calculations to monitor and evaluate risk from both physical and paper trading.

Bio-Diesel run Bus in Pune by Tatas

I read an article in the other thread of this forum about the launch of a Tata bus run by Blended Bio-Diesel in Pune. quoting ref.Express.com today. Mr.Sumantran of Tata Motors is kind enough to announce the quantum of waste lands somewhere around 150 million hectares suitable for growing Oil seeds like Jatropha and he is also hopeful to see a policy on Bio-Diesel soon. We know Tatas have huge potential in Research and Development atleast in Auto sector in particular considering their unassailable share of Indian Auto Market and its continued effort in providing Indigenous Technology in making cars,Buses,LCVs,HCVs, and even big trucks recently HYWA matching VOLVOS in India itself. Tatas have good brand value in all fields except in the case of Tea plantation Tatas have totally left the oil field vaccum when we saw them developing Rice-Bran oil in 1970s and the extraction of Nimbidin from Neem in 1990s. Today, thank God Tatas have come out to support Bio-Diesel and that to minimise emissions in cities and not their trucks operated by all sort of adulterated fuels on our Indian Roads very popular in Andhra and Maharshtra and even today one can notice a Tata truck carrying over loads infact doubling the permitted weight by the RTOs. Tatas are more active in other segments like communications,IT, instead of rendering any useful work for the Rural poor atleast in S.India. We know the reason may be their worst ever problem in 80s in oil sector due to strikes in their concerns forcing them to sell their Wonderful oil and Soap division rather destroyed their century old system of oil Technology in India gifted by Danish people.

THE BUSINESS PROCESS OF UPSTREAM MANAGEMENT

SAP for Oil & Gas solutions support processes related to the exploration, development, and production of crude petroleum, enabling key activities such as: Exploration and appraisal – With SAP solutions, you can maintain your portfolio of assets by finding and developing new petroleum reserves. Integrated solutions support the full exploration cycle, enabling you to assess your current asset and production portfolio, identify exploration targets, acquire leases and licenses, manage surveys and appraisals, and model reservoirs. Exploration and production contract management – SAP solutions facilitate the acquisition of petroleum reserves through mergers, acquisitions, or joint ventures. Our solutions enable opportunity analysis, strategic planning, venture equity trading, as well as the development and management of joint operating agreements and production sharing contracts. Field development – SAP solutions helps you establish the size of the field, work out the most efficient production method, and assess whether the field will cover the costs of development and day-to-day operation and yield a profit. Liquid and gas production – With capabilities for well mapping, production planning and execution, volume and capacity management, and quality assurance, you can ensure 24/7 production cycles and maximize quantities produced. You can also comply with corporate, industry, and governmental standards for safety and environmental protection while maintaining all facilities in good working order. Allocation and settlement – SAP solutions enable you to allocate volumes and value to owners who have an equity share in a producing well or to sales contracts, indicating what you have promised to purchasers. You can also submit reports and pay royalties to governments and other public bodies. Oil field service and repair operations – With SAP solutions, you can conduct long-range planning to optimize resources. You can also deploy and schedule resources as needed, when customer service requests come in or as planned service activities occur. Plus, you can outsource services, procure and source services, and carry out billing and payment activities. Upstream management is enabled with SAP offerings such as SAP ERP. To find out how these offerings can help you improve your upstream management, please complete the "Contact SAP" form and request information about enterprise resource planning. Are You a Small or Midsize Company? If you’re looking for a more preconfigured solution to fit a less complex environment, consider our solutions designed to fit your business – and your budget. Learn more about SAP solutions for small and midsize oil and gas companies.

Want to learn more? Contact us or call the SAP sales office nearest you.

SAP FOR OIL & GAS

BUSINESS PROCESSES The SAP for Oil & Gas solution portfolio enables you to automate, streamline, and integrate complex processes, including: Upstream management – Streamline processes related to the exploration, development, and production of crude petroleum. Supply, transmission, and trading – Manage the execution of bulk supply chain activities from initial planning to final settlement. Refining and manufacturing – Control the processes involved with the transformation of crude oil into market-ready refined products. Downstream marketing and retailing – Manage the complete opportunity-to-cash process through various channels, and support service station fuel management and convenience store retailing. Asset management – Increase asset utilization, extend asset lifetime, collaborate with spare-parts suppliers, and improve utilization of service and maintenance teams. Enterprise management and support – Handle all core enterprise activities in analytics, financials, human capital management, corporate services, and operations support. Business Processes in Detail SAP solutions and applications support business processes related to the oil & gas industry. Learn more about these business processes.

Want to learn more? Contact us or call the SAP sales office nearest you.

..: THE SHOW - OIL & GAS PAKISTAN :..

Oil & Gas Pakistan is geared to be an exclusive trade exhibition, showcasing state-of-the-art equipment and machinery providing its participants with a comprehensive technical insight into the regional Oil & Gas industry.

POGEE, featuring Oil & Gas Pakistan and Power Technology Pakistan exhibitions, has established itself as the premier event catering to the Oil, Gas & Energy sectors. It serves as a convergence point for national and international companies to explore business opportunities in Pakistan . With unprecedented experience and reach, POGEE is the ideal venue to interact with key decision-makers and government officials, discuss areas of mutual cooperation, implement government plans and fulfill the future requirements of this industry in Pakistan.

OGDCL – The leading E&P Player in Pakistan

OGDCL is the national oil & gas company of Pakistan and the flagship of the country’s E&P sector. The Company is the local market leader in terms of reserves, production and acreage, and is listed on all three stock exchanges in Pakistan and also on the London Stock Exchange since December 2006. The Company is all set to ride the wave of E&P activity, equipped with its Vision & Mission, Business and Strategic Plan, a debt-free and robust balance sheet and healthy cash reserves. The Company is ready to take on the challenges of a volatile E&P industry.

..: INTRODUCTION :..

The location of Pakistan at the crossroads of Central Asia and the Arabian Sea has brought into spotlight its significance as an attractive market and a regional transit route for energy. Oil and Gas are the two major components of the energy mix which contribute 79% to the 63 million TOE of energy requirement in the country. The Government is formulating investor-friendly policies to increase the share of indigenous resources in the country. As a result of these policies, the Oil & Gas sector has attracted foreign direct investment of over US$ 700 million in 2008-09.

Pakistan is one of the largest consumers of gas in the region. It has a well developed and integrated infrastructure of transportation, distribution and utilisation of natural gas with 10,285 km of transmission and 93,961 km of distribution network. The two gas distribution companies plan to invest about US$ 400 million to increase the capacity of existing distribution network.

Up till now 725 wells have been drilled by various local and international exploration and production companies with 219 Oil & Gas discoveries, bringing the gas reserves to 30 TCF. An investment of US$ 1 billion was spent in drilling activities with 60 new wells drilled in 2008-09. At the same time, the crude oil recoverable reserves are estimated at 313 million barrels. The current production of oil is 66,532 barrels per day, whereas gas production is at 4 billion cubic feet per day.

Currently seven refineries are operating in the country with a refining capacity of 13 million tonnes per year.

Pakistan is now the largest CNG user in the world. Currently, 2700 CNG stations are operating with an investment of over US$ 1 billion, serving 2 million vehicles in the country.

LPG

LPG is environment-friendly and an economical fossil fuel available in the country. It is mainly used by the people living in remote areas, having no access to natural gas. Annual LPG consumption is 600,000 tonnes out of which 20% is met through imports. Total investment of US$ 200 million has already been made to develop the LPG supply infrastructure.

COAL

Pakistan has the 7th largest coal reserves in the world, estimated at over 185 billion tonnes of Coal. The country is producing 2.4 million tonnes of coal to meet the current coal consumption of 6.4 million tonnes while 4 million tonnes is imported to fulfill the energy requirement of the country. The Government has allocated an annual budget of US$ 25 million for the development of Thar Coal Infrastructure. Thar Coal project has the potential to cater to the increasing national energy requirement for decades with a relatively low unit cost.

"Are We 'Running Out'? I Thought There Was 40 Years of the Stuff Left"

Oil will not just "run out" because all oil production follows a bell curve. This is true whether we're talking about an individual field, a country, or on the planet as a whole.

Oil is increasingly plentiful on the upslope of the bell curve, increasingly scarce and expensive on the down slope. The peak of the curve coincides with the point at which the endowment of oil has been 50 percent depleted. Once the peak is passed, oil production begins to go down while cost begins to go up.

In practical and considerably oversimplified terms, this means that if 2005 was the year of global Peak Oil, worldwide oil production in the year 2030 will be the same as it was in 1980. However, the world’s population in 2030 will be both much larger (approximately twice) and much more industrialized (oil-dependent) than it was in 1980. Consequently, worldwide demand for oil will outpace worldwide production of oil by a significant margin. As a result, the price will skyrocket, oil dependant economies will crumble, and resource wars will explode.The issue is not one of "running out" so much as it is not having enough to keep our economy running. In this regard, the ramifications of Peak Oil for our civilization are similar to the ramifications of dehydration for the human body. The human body is 70 percent water. The body of a 200 pound man thus holds 140 pounds of water. Because water is so crucial to everything the human body does, the man doesn't need to lose all 140 pounds of water weight before collapsing due to dehydration. A loss of as little as 10-15 pounds of water may be enough to kill him.

In a similar sense, an oil based economy such as ours doesn't need to deplete its entire reserve of oil before it begins to collapse. A shortfall between demand and supply as little as 10 to 15 percent is enough to wholly shatter an oil-dependent economy and reduce its citizenry to poverty.

The effects of even a small drop in production can be devastating. Source For instance, during the 1970s oil shocks, shortfalls in production as small as 5% caused the price of oil to nearly quadruple. Source The same thing happened in California a few years ago with natural gas: a production drop of less than 5% caused prices to skyrocket by 400%.

Fortunately, those price shocks were only temporary.

The coming oil shocks won't be so short lived. They represent the onset of "a new, permanent condition". Source Once the decline gets under way, production will drop (conservatively) by 3% per year, every year. War, terrorism, extreme weather and other "above ground" geopolitical factors will likely push the effective decline rate past 10% per year, thus cutting the total supply by 50% in 7 years. Source

These estimate comes from numerous sources, not the least of which is Vice President Dick Cheney himself. In a 1999 speech he gave while still CEO of Halliburton, Cheney stated:

By some estimates, there will be an average of two-percent annual growth

in global oil demand over the years ahead, along with, conservatively, a

three-percent natural decline in production from existing reserves. That

means by 2010 we'll need an additional 50 million barrels per day. Source

Cheney's assesement is supported by the estimates of numerous non-political, retired, and now disinterested scientists, many of whom believe global oil production will peak and go into terminal decline within the next five years, if it hasn't already. Source

Many industry insiders think the decline rate will far higher than Cheney anticipated in 1999. Andrew Gould, CEO of the giant oil services firm Schlumberger, for instance, recently stated that "An accurate average decline rate of 8% is not an unreasonable assumption." Source Some industry analysts are anticipating decline rates as high as 13% per year. Source A 13% yearly decline rate would cause gobal production to drop by 75% in less than 11 years.

If a 5% drop in production caused prices to triple in the 1970s, what do you think a 50% or 75% drop is going to do?

Estimates coming out of the oil industry indicate that this drop in production has already begun. Source The consequences of this are almost unimaginable. As we slide down the downslope slope of the global oil production curve, we may find ourselves slipping into something best described as a "post industrial stone age."Source

Pakistan with an ideal geographic

Pakistan with an ideal geographic and strategic location serves as a corridor for the international supply routes of energy. Being a regional power house, the country possess opportunities of setting up the oil and gas pipelines as well as electricity grids within the region and with other neighbouring energy rich countries such as Iran, Tajikistan and Turkmenistan.

Pakistan's energy requirements are increasing every year and to meet the rising demand of energy, the government of Pakistan is currently focused on diversification of gas supplies, reconstruction of hydropower plants, construction of underground gas storage facilities, development of oil exploration & production, tapping of renewable energy resources, attracting foreign investment and privatisation of state-owned assets.

Pakistan is responding to the energy development challenge by pursuing a wide range of domestic and imported energy projects and in the year 2009 - 2010, the Oil, Gas and Energy industry has attracted Foreign Investment of about US$ 796 million.

A Simpler Route to Plastic Solar Cells

A simplified process for printing polymer solar cells could further reduce the costs of making the plastic photovoltaics. The method, which has been demonstrated on a large-area, roll-to-roll printing system, eliminates steps in the manufacturing process. If it can be applied to a wide range of polymer materials, it could lead to a fast and cheap way to make plastic solar cells for such applications as portable electronics, photovoltaics integrated into building materials, and smart fabrics.


Solar roller: This roll-to-roll printer is fabricating polymer solar cells in a lab at the University of Michigan. The clear plastic substrate is visible on the top left red-colored roller.
Credit: Jay Guo
Polymer solar cells aren't as efficient as silicon ones in converting sunlight into electricity, but they're lightweight and cheap, a trade-off that could make them practical for some applications. And they're compatible with large-area printing techniques such as roll-to-roll processing. But manufacturing the solar cells is challenging, because if the polymers aren't lined up well at the nanoscale, electrons can't get out of the cell. Researchers now use post-printing processing steps to achieve this alignment. Eliminating these extra steps will, University of Michigan researchers hope, bring down manufacturing costs and complexity.

"Our strategy solves a number of issues at the same time," says L. Jay Guo, professor of electrical engineering at the University of Michigan. Their process involves applying a small amount of force during the printing process with a permeable membrane. The process allows the printing solvents to evaporate and leads to well-ordered polymer layers--without any need for post-processing. These improvements in the structure of the cell's active layer have an additional benefit: cells made using this technique require one fewer layer of materials than polymer solar cells made using other methods. This work is described online in the journal Advanced Materials.

When light of a certain wavelength strikes the semiconducting material in a solar cell, it creates electrons and positively charged holes. To generate an external current, the cell must separate the electrons from the holes so that they can exit. This separation doesn't happen as readily in polymers as it does in inorganic materials like silicon, says Guo. The active layers in polymer solar cells combine two materials, one that conducts holes and one that conducts electrons. Ideally the electron-accepting polymer would be on top of the electron-donating polymer, so that it's near the cathode, allowing as many electrons to exit as possible.

Guo's group found that spreading the polymer mix onto a plastic substrate, then pressing it against a roller coated with silicone, facilitates the formation of this desirable structure. And the pressure from the roller encourages the polymers to crystallize in a matter of seconds, without the need for the time-consuming chemical or thermal treatments. The structure of the polymers is so good, says Guo, that the Michigan researchers could eliminate a layer from the cells without any change in power-conversion efficiency.So far, Guo has used a common but relatively low-efficiency polymers to fabricate the solar cells, but he says the method should be compatible with higher efficiency polymer materials. The Michigan cells have an efficiency of only about 3.5 percent. Researchers are working on materials sets that should bring the efficiencies of polymer solar cells up to 12 to 15 percent, a boost that's necessary if polymer solar cells are to reach a broad market and more fully compete with conventional silicon and thin-film cells.

"I think this process has very strong potential," says Yang Yang, professor of materials science and engineering at the University of California, Los Angeles. "It's uncertain whether this method also works for other polymer systems, but there is no reason why it won't." Yang is collaborating with plastic solar-cell company Solarmer of El Monte, CA, which is on track to reach 10 percent efficiency with its devices by the end of this year.

Draugen Oil Field, North Sea, Norway

The Draugen oil field is operated by Norske Shell, which also owns a 26.20% stake in the field. The remaining stake is held by Petoro (47.88%), BP Norge (18.36%) and Chevron (7.56%). The field lies in block 6407/9 in the Haltenbanken area which is situated about 140km from Kristiansund, Norway. The field lies in production licence PL093.

In a contract estimated to be worth NKr200m ($34.16m), Aker Offshore Partner (a subsidiary of Aker Solutions) will set up a water reinjection system at the Draugen field. The contract was awarded by Shell in December 2009. The contractual scope includes engineering, procurement, construction and installation of the reinjection system. Aker expects to complete the installation by January 2012.


The field was shut down in February 2010 due to cold weather and extreme winds. Shell is yet to resume operations at the facility.

Draugen field discovery and reserves

The field was discovered in 1984 by the first well drilled in the block. The discovery wellbore was a wild cat well designated 6407/9-1.

As of 31 December 2009, the recoverable oil reserves at Draugen stood at 145 million standard cubic meters. The remaining reserves stood at 19.7 million cubic metres.

Geology

The Draugen field produces oil primarily from two reservoirs. The main reservoir contains sandstone of Rogn formation, found to be of the late Jurassic age. The other deposit, located in the west, is the Garn formation of middle Jurassic age. The Rogn and Garn deposits are homogeneous and both lie at a depth of 1,650m.

Draugen field development

The Draugen field was initially developed with five subsea wells connected to a central platform. The field currently has six platform wells and eight subsea wells. Of these, 12 are production wells.

"The Draugen oil field is operated by Norske Shell, which also owns a 26.20% stake in the field."
Field development has so far included drilling of nine exploration wells and 25 development wells. The first exploration well, 6407/9-1, was a wild cat well drilled in 1984. Four more appraisal wells were drilled in the following year. The sixth appraisal well was drilled in 1986. It was suspended initially, but re-entered later. The last three appraisal wells were drilled in 1993, 1999 and 2003 respectively. Altris supplied document viewing and management software to Shell during the field development.

The Garn reservoir in the west of Draugen was developed with two subsea wells. It began production in late 2001. The Rogn reservoir was developed with two subsea wells in 2002 and production from the reservoir began in November the same year. One further subsea well was drilled in each of these reservoirs in 2007. The new wells at the Garn and Rogn were named D3 and E3 respectively. Production from the two subsea wells commenced in 2008.

Subsea system

The subsea system at Draugen, installed by FMC Technologies, includes two water injection wells, two oil production satellite wells and a gas injection satellite well. The system required nine vertical subsea trees of 5,000psi. The subsea wells were tied to the common Draugen platform.

Acergy installed the flexible pipe and umbilical system at Draugen in 2008. Normand Mermaid and Acergy Eagle ships were used for the marine installations. Acergy installed a 2.3km gas lift and 2.4km production flowlines as part of the contract.

NKT Flexibles will supply two water injection flowlines for subsea installations at the field. Two flexible lines will be supplied, one for reinjection of produced water and another for that of sea water. The installation will be undertaken in mid 2011.

Draugen platform

The Draugen platform was installed in 1993. Resting on a single column, the platform consists of a concrete shaft with integrated topside decks. The production capacity of the platform is about 140,000bpd.

Aker Kvaerner is maintaining the platform under a five-year contract signed with Shell in 2005. The contractual agreement has an option to renew the contract every two years after the end of the initial contract period.

Contracts

The EPC contract for subsea well facilities at the Draugen field was awarded to FMC Technologies in 1990. FMC designed the subsea installations for diverless installation, operation and maintenance.

The marine installation contract for Draugen D3 and E3 development, which included flexible pipe and umbilical system, was given to Acergy in March 2007. Acergy awarded the water injection flowlines supply contract NKT Flexibles in May 2010.

Bjørge Eureka, the Norwegian subsidiary of Bjørge, was awarded a contract in July 2009 to upgrade the generator system at the Draugen platform and supply centrifugal pumps to the platforms.

Production

"The Draugen field was initially developed with five subsea wells connected to a central platform."
Shell began producing oil at the Draugen field in October 1993. Use of 4D seismic technology has helped Shell to increase the production life of the Draugen field. The company expects to continue production at the field at least until 2024.

The average crude oil production at the field in 2009 stood at 63,000bpd, a decrease of 14.8% over 2008. Production has been falling continuously since 2004 when the average production stood at 144,000bpd. Various production optimisation initiatives have been undertaken by the company over the years. In order to increase oil recovery and production, the company is planning to add some more wells to the field.

Pipeline

The Garn West reservoir is connected to the Draugen platform by a 3.3km-long pipeline. The pipeline laid via the Garn West reservoir connects the Rogn deposit to the project platform.

While the oil extracted from the field is transferred to a floating loading buoy, the associated gas is transported to processing plant at Karsto by means of the Asgard Transport pipeline.

Increasing Oil Supply

The amount of accessible oil worldwide could eventually be increased by roughly 30 percent with the help of new drilling, imaging, and oil extraction technologies, including the use of microbes, say MIT researchers. Theoretically, this number could be even higher; in a best-case scenario, the amount of oil that could be produced would double.


Rapidly heating many rock types causes them to break apart. This process could be the basis for a new, less expensive method of drilling for oil. (Photo courtesy of Jefferson Tester, MIT.)
On average, using current techniques, about two-thirds of the oil in an oil field gets left behind, says Richard Sears, a vice president at Shell International Exploration and Production, Houston, TX. "The fundamental problem is basic physics. It's not like the oil is in big tanks. We produce oil from rock -- sandstone. The oil is actually held in the very small spaces between the grains of sand. The problem is, when you try to move that oil out of the rocks, because of the size of the spaces, you end up with a layer of oil coating the insides of the rocks." About one-third of the oil in fields will always be inaccessible. That leaves one-third that could be recovered with new technologies -- which is equal to the amount that would have already been extracted.

Getting all of this oil out would be extremely ambitious, but Robert van der Hilst, earth, atmospheric, and planetary sciences (EAPS) professor at MIT, says much smaller gains would still be marked improvements. Increasing the percent of oil harvested from worldwide oil fields by even one percentage point would be the equivalent of adding a new oil-producing region as productive as the fields in the entire North Sea, he says.

To a certain extent, getting more oil out of existing fields is a question of economics. Oil, which resides underground in porous rock, can be forced out by injecting water, steam, or carbon dioxide, but these methods bring added costs that limit their use. If oil prices stay consistently high, these methods will be employed more than they are now, Sears says.But significantly increasing oil recovery will require new technologies. At the top of the list are better oil field imaging techniques, says Nafi Toksöz, an EAPS professor at MIT. Improved imaging can help oil companies find and tap areas in an oil field that have become surrounded by water, and so cut off from oil wells, he says. It can also improve the effectiveness of existing methods such as using water or steam to extract oil.

As it is now, water pumped into a field, for example, might start to cut a channel through the oil, and so, rather than pushing oil out, would simply enter through an injection well and flow out through an extraction well in the place of oil. Better understanding of the dynamics of an oil field through imaging at regular intervals can help engineers know where best to inject water and steam, and how to control the pressure to prevent channels from forming.

Oil and Gas Technology Feasibility Studies

The optimal recovery and use of U.S. oil and gas resources requires energy policies and environmental regulations based on credible scientific data, assumptions, and analyses. Before new technologies can be moved into commerce, their capabilities, cost, risk, and legality need to be determined. Argonne's Environmental Science Division (EVS) conducts independent feasibility studies of the technical, regulatory, economic, and risk aspects of promising oil field technologies to foster technology evaluation and implementation. Examples of technologies that EVS has recently evaluated include:

Synthetic-based drilling fluids that offer both good drilling performance and low environmental impacts;
The use of underground salt caverns for disposing of oil field waste well below drinking water supplies;
Downhole oil/water separators that offer cost savings through lower produced water management costs and fewer environmental impacts;
The use of treated drill cuttings to restore coastal wetlands; and
Slurry injection for disposal of drilling wastes.

In addition to preparing feasibility studies on these topics, EVS has conducted extensive outreach to regulatory agencies and the oil and gas industry in the United States and abroad, through conference presentations and publications.

Related EVS Developed/Hosted Web Sites

Drilling Waste Management Information System (DWMIS)
Salt Cavern Information Web Site
Related Web Sites

Ohio Oil and Gas Well Emergency Response System
Related Publications

Produced Water Volumes and Management Practices in the United States
Thermal Distillation Technology for Management of Produced Water and Frac Flowback Water
Water Issues Associated with Heavy Oil Production
Testimony of John A. Veil, Argonne National Laboratory, Before the House Committee on Science and Technology Subcommittee on Energy and Environment Concerning: "Research to Improve Water-Use Efficiency and Conservation: Technologies and Practice"
Life-Cycle Thinking for the Oil and Gas Exploration and Production Industry
Trip Report for Field Visit to Fayetteville Gas Wells
Potential Ground Water and Surface Water Impacts from Oil Shale and Tar Sands Energy-Production Operations
Exploration and Production Waste Disposal Database
Offsite Commercial Disposal of Oil and Gas Exploration and Production Waste: Availability, Options, and Costs
Summary of DOE/PERF Water Program Review, November 1-4, 2005, Annapolis, Maryland
Characteristics of Produced Water Discharged to the Gulf of Mexico Hypoxic Zone
Downhole Separation Technology Performance: Relationship to Geologic Conditions
A White Paper Describing Produced Water from Production of Crude Oil, Natural Gas, and Coal Bed Methane
An Introduction to Salt Caverns and Their Use for Disposal of Oil Field Wastes
An Introduction to Slurry Injection Technology for Disposal of Drilling Wastes
Evaluation of Slurry Injection Technology for Management of Drilling Wastes
Compendium of Regulatory Requirements Governing Underground Injection of Drilling Wastes
Analysis of Data from a Downhole Oil/Water Separator Field Trial in East Texas
Regulatory Issues Affecting Management of Produced Water from Coal Bed Methane Wells
Information on Commercial Disposal Facilities That May Have Received Offshore Drilling Wastes
Summary of Data from DOE-Subsidized Field Trial #1 of Downhole Oil/Water Separator Technology, Texaco Well Bilbrey 30-Federal No. 5 Lea County, New Mexico
Update on Onshore Disposal of Offshore Drilling Wastes
Data Summary of Offshore Drilling Waste Disposal Practices
Disposal of NORM-Contaminated Oil Field Wastes in Salt Caverns
Risk Analyses for Disposing of Nonhazardous Oil Field Wastes in Salt Caverns
Preliminary Technical and Legal Evaluation of Disposing of Nonhazardous Oil Field Waste into Salt Caverns
Potential environmental benefits from regulatory consideration of synthetic drilling muds.
Feasibility Evaluation of Downhole Oil/Water Separator (DOWS) Technology
Costs for Off-Site Disposal of Nonhazardous Oil Field Wastes: Salt Caverns versus Other Disposal Methods
Surface Water Discharges from Onshore Stripper Wells
Contact

John Veil
(202)488-2450
jveil@anl.gov

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SALE OF OIL

Once the oil is out of the ground and into the holding tanks, it must be sold. In most cases each holder of a working interest has the right to take his portion of production in kind, therefore, make his own arrangements for its sale. It is not uncommon, however, for all the holders of a working interest of a well to enter into the same arrangement with the same buyer of the oil production. These sale contracts are normally entered into for periods of not longer than a few months but in no case longer than one year.

The buyer of the oil will generally be advised by the operator of the working interest as to the identity and extent of ownership of each of the holders of the working interest, as well as the identity of the royalty holders and the amount of their interests. The information will be compiled on division orders which are the basis upon which the buyer of the oil can divide the proceeds of sale among the various holders.

The buyer of the oil will pick up the oil from the holding tanks at periodic intervals, gauge it and remit the remaining proceeds in the proper amounts to the holders of the working interest and the royalties.

OPERATION

When all equipment is in place, the oil may begin to flow into the holding tanks to await pick up. It can be expected that a well will not be in production for certain times due to adverse weather conditions, mechanical malfunctions and other unforeseen circumstances. After the production period commences, it is necessary to incur certain costs in order to bring the oil to the surface. These costs include normal maintenance on the pump and other equipment, replacement of any pipe or tanks as needed, compensation to the operator of the pump, and payment of any incidental damages to the owner of the surface rights of the leased property. In some cases, the oil in a pay zone will be mixed with salt water. In such cases, the oil must be separated from the salt water and the salt water disposed of in a manner which is not harmful to the environment. The water may be hauled away by tank truck but often this phenomenon requires the drilling, nearby the oil producing well, of another well into which the salt water will be pumped.

The cost of this water disposal well is normally considered to be a cost of operation. Finally, there may be additional costs incurred in opening up a new pay zone when any presently producing pay zone becomes economically unfeasible. Because opening a new pay zone involves the installation of very little, if any, new equipment, the costs involved therein usually are not very substantial.

SECONDARY RECOVERY

Water flooding is one of the most common and efficient secondary recovery processes. Water is injected into the oil reservoir in certain wells in order to renew a part of the original reservoir energy. As this water is forced into the oil reservoir, it spreads out from the injection wells and pushes some of the remaining oil toward the producing wells. Eventually the water front will reach these producers and increasingly larger quantities of water will be produced with a corresponding decrease in the amount of oil. When it is no longer economical to produce these high water-ratio wells, the flood may be discontinued. As mentioned previously, average primary recoveries may be only 15% of the oil in the reservoir. Properly operated waterfloods should recover an additional 15% to 20% of the original oil in place. This leaves a substantial amount of oil in the reservoir, but there are no other engineering techniques in use now that can recover it economically. In most cases, oil reservoirs suitable for secondary recovery projects have been produced for several years. It takes time to inject sufficient water to fill enough of the void spaces to begin to move very much oil. It takes several months from the start of a waterflood before significant production increases take place and the flood will probably have maximum recoveries during the second, third, fourth, and fifth years after injection of water has commenced. The average flood usually lasts 6 to 10 years.

Water floods have been highly successful in the Wyoming Basin and probably account for 75% of the total production from the area. Flood recoveries will generally be an additional 80% to 100% of the primary production. There are no special problems with floods in the Wyoming Basin. Ample supplies of salt water are generally available and injection pressures are not too high - 1500 PSI or less. Corrosion is minimal and no expensive, high-pressure equipment is involved. Sufficient potential flood properties are available on reasonable terms - especially smaller areas owned by independent operators who do not have the finances to support the installation of properly engineered secondary recovery operations. Water floods in the Wyoming Basin should return 2 to 3 times their cost and are considered to be low-risk prospects.

OIL PRODUCTION

Once an accumulation of oil has been found in a porous and permeable reservoir, a series of wells are drilled in a predetermined pattern to effectively drain this "oil pool". Wells may be drilled as close as one to each 10 aces (660 ft. between wells) or as far apart as one to each 640 acres (1 mile between wells) depending on the type of reservoir and the depth to the "pay" horizon. For economic reasons, spacing is usually determined by the distance the reservoir energy will move commercial quantities of oil to individual wells. The rate of production is highest at the start when all of the energy from the dissolved gas or water drive is still available. As this energy is used up, production rates drop until it becomes uneconomical to operate although significant amounts of oil still remain in the reservoir. Experience has shown that only about 12 to 15 percent of the oil in a reservoir can be produced by the expansion of the dissolved gas or existing water.

INJECTION WELLS

In the ordinary producing operation only a portion of the oil in place is recoverable by primary production methods. Such methods include free-flowing wells and production maintained by pumps. As oil is extracted from a reservoir or sands the pressure which brings the oil to the well is reduced. Secondary recovery methods are intended to increase the recoverable percentage of the oil in place by injecting a substance such as gas or water into the producing formation. The injected substance is intended to increase the pressure on the oil in the formation and drive it toward the well-bore. A well, called an injection well or water injection well, is usually drilled in order to inject the substance. Sometimes a previously drilled, abandoned well can be reworked as an injection well. When water is used as the injectant it is often produced on the property itself. Excess water produced by operating wells may be diverted to the injection well and used as the injectant.

This method of water disposal usually alleviates the need for a separate water disposal well. If the water from the producing wells does not provide enough injectant to provide proper pressure for secondary recovery, a water supply well may be required to provide an adequate supply of water.

Sucker-Rod Pumps

The artificial-lift method that involves surface pumps is known as rod pumping or beam pumping. Surface equipment used in this method imparts an up-and-down motion to a sucker-rod string that is attached to a piston or plunger pump submerged in the fluid of a well. Most rod-pumping units have the same general operating principles.

Sucker-Rod Pumps

The artificial-lift method that involves surface pumps is known as rod pumping or beam pumping. Surface equipment used in this method imparts an up-and-down motion to a sucker-rod string that is attached to a piston or plunger pump submerged in the fluid of a well. Most rod-pumping units have the same general operating principles.

Sucker-Rod Pumps

The artificial-lift method that involves surface pumps is known as rod pumping or beam pumping. Surface equipment used in this method imparts an up-and-down motion to a sucker-rod string that is attached to a piston or plunger pump submerged in the fluid of a well. Most rod-pumping units have the same general operating principles.

Fracturing

When sandstone rocks contain oil or gas in commercial quantities but the permeability is too low to permit good recovery, a process called fracturing may be used to increase permeability to a practical level. Basically, to fracture a formation, a fracturing service company pumps a specially blended fluid down the well and into the formation under great pressure. Pumping continues until the formation literally cracks open. Meanwhile, sand, walnut hulls, or aluminum pellets are mixed into the fracturing fluid. These materials are called proppant. The proppant enters the fractures in the formation, and, when pumping is stopped and the pressure allowed to dissipate, the proppant remains in the fractures. Since the fractures try to close back together after the pressure on the well is released, the proppant is needed to hold or prop the fractures open. These propped-open fractures provide passages for oil or gas to flow into the well. See figure to the right.

ARTIFICIAL LIFT

After the well has been perforated, acidized or fractured, the well may not produce by natural flow. In such cases, artificial-lift equipment is usually installed to supplement the formation pressure

Acidizing

Sometimes, however, petroleum exists in a formation but is unable to flow readily into the well because the formation has very low permeability. If the formation is composed of rocks that dissolve upon being contacted by acid, such as limestone or dolomite, then a technique known as acidizing may be required. Acidizing is usually performed by an acidizing service company and may be done before the rig is moved off the well; or it can also be done after the rig is moved away. In any case, the acidizing operation basically consists of pumping anywhere from fifty to thousands of gallons of acid down the well. The acid travels down the tubing, enters the perforations, and contacts the formation. Continued pumping forces the acid into the formation where it etches channels - channels that provide a way for the formation's oil or gas to enter the well through the perforations.

Perforating

Since the pay zone is sealed off by the production string and cement, perforations must be made in order for the oil or gas to flow into the wellbore. Perforations are simply holes that are made through the casing and cement and extend some distance into the formation. The most common method of perforating incorporates shaped-charge explosives (similar to those used in armor-piercing shells). Shaped charges accomplish penetration by creating a jet of high-pressure, high-velocity gas. The charges are arranged in a tool called a gun that is lowered into the well opposite the producing zone. Usually the gun is lowered in on wireline (1). When the gun is in position, the charges are fired by electronic means from the surface (2). After the perforations are made, the tool is retrieved (3). Perforating is usually performed by a service company that specializes in this technique.

CEMENTING

After the casing string is run, the next task is cementing the casing in place. An oil-well cementing service company is usually called in for this job although, as when casing is run, the rig crew is available to lend assistance. Cementing service companies stock various types of cement and have special transport equipment to handle this material in bulk. Bulk-cement storage and handling equipment is moved out to the rig, making it possible to mix large quantities of cement at the site. The cementing crew mixes the dry cement with water, using a device called a jet-mixing hopper. The dry cement is gradually added to the hopper, and a jet of water thoroughly mixes with the cement to make a slurry (very thin water cement).
Special pumps pick up the cement slurry and send it up to a valve called a cementing head (also called a plug container) mounted on the topmost joint of casing that is hanging in the mast or derrick a little above the rig floor. Just before the cement slurry arrives, a rubber plug (called the bottom plug) is released from the cementing head and precedes the slurry down the inside of the casing. The bottom plug stops or "seats" in the float collar, but continued pressure from the cement pumps open a passageway through the bottom plug. Thus, the cement slurry passes through the bottom plug and continues on down the casing. The slurry then flows out through the opening in the guide shoe and starts up the annular space between the outside of the casing and wall of the hole. Pumping continues and the cement slurry fills the annular space.

A top plug, which is similar to the bottom plug except that it is solid, is released as the last of the cement slurry enters the casing. The top plug follows the remaining slurry down the casing as a displacement fluid (usually salt water or drilling mud) is pumped in behind the top plug. Meanwhile, most of the cement slurry flows out of the casing and into the annular space. By the time the top plug seats on or "bumps" the bottom plug in the float collar, which signals the cementing pump operator to shut down the pumps, the cement is only in the casing below the float collar and in the annular space. Most of the casing is full of displacement fluid.

After the cement is run, a waiting time is allotted to allow the slurry to harden. This period of time is referred to as waiting on cement or simply WOC.

After the cement hardens, tests may be run to ensure a good cement job, for cement is very important. Cement supports the casing, so the cement should completely surround the casing; this is where centralizers on the casing help. If the casing is centered in the hole, a cement sheath should completely envelop the casing. Also, cement seals off formations to prevent fluids from one formation migrating up or down the hole and polluting the fluids in another formation. For example, cement can protect a freshwater formation (that perhaps a nearby town is using as its drinking water supply) from saltwater contamination. Further, cement protects the casing from the corrosive effects that formation fluids (as salt water) may have on it.

DRILLING TO TOTAL DEPTH

The final part of the hole is what the operating company hopes will be the production hole. But before long, the formation of interest (the pay zone, the oil sand, or the formation that is supposed to contain hydrocarbons) is penetrated by the hole. It is now time for a big decision. The question is, "Does this well contain enough oil or gas to make it worthwhile to run the final production string of casing and complete the well?"

DRILLING

Once an area has been selected and the right to drill thereon has been obtained, actual drilling may begin. The most common method of drilling in use today is rotary drilling. Rotary drilling operates on the principle of boring a hole by continuous turning of a bit. The bit is the most important tool. The rest of the rig (a derrick and attendant machinery) is designed to make it effective. While bits vary in design and purpose, one common type consists of a housing and three interlocking movable wheels with sharp teeth, looking something like a cluster of gears. The bit, which is hollow and very heavy, is attached to the drill stem, composed of hollow lengths of pipe leading to the surface. As the hole gets deeper, more lengths of pipe can be added at the top. Almost as important as the bit is the drilling fluid.

Although known in the industry as mud, it is actually a repaired chemical compound. The drilling mud is circulated continuously down the drill pipe, through the bit, into the hole and upwards between the hole and the pipe to a surface pit, where it is purified and recycled. The flow of mud removes the cuttings from the hole without removal of the bit, lubricates and cools the bit in the hole, and prevents a blow out which could result if the bit punctured a high pressure formation.

The cuttings, which are carried up by the drilling mud, are usually continuously tested by the petroleum geologist in order to determine the presence of oil.

SECURING LEASES

Once a likely area has been selected, the right to drill must be secured before drilling can begin. Securing the right to drill usually involves leasing the mineral rights of the desired property from the owner. The owner may be the owner of all interest in the land, or just the mineral rights. As payment for the right to drill for and extract the oil and gas, the owner will usually be paid a sum call a "lease bonus" or a "hole bonus" for every well drilled on the leased land. He will also retain a royalty on the production, if any, of the leased property. The royalty is the right to receive a certain portion of the production of property, without sharing in the costs incurred in producing the oil, such as drilling, completion, equipping and operating or production costs. The costs are borne by the holder of the right to drill and extract the mineral, which right is usually referred to as the working interest.

In many cases the procurement of the lease from the land owner is accomplished by a lease broker who will, in turn, offer and then assign the lease to an operator such as CORPO-PETROL. CORPO-PETROL is very selective in choosing leases for drilling. The lease broker usually retains an overriding royalty on the working interest as compensation for his services. In the case of CORPO-PETROL's leases, there generally is a retained land owner's royalty of 1/8 of all production and a 1/16 overriding royalty on the working interest, retained or granted to one or more persons who may have acted as lease brokers.

Types of Petroleum Traps

Geologists have classified petroleum traps into two basic types: structural traps and Stratigraphic traps. Structural traps are traps that are formed because of a deformation in the rock layer that contains the hydrocarbons. Two common examples of structural traps are fault traps and anticlines.

An anticline is an upward fold in the layers of rock, much like an arch in a building. Petroleum migrates into the highest part of the fold, and its escape is prevented by an overlying bed of impermeable rock (A).

A fault trap occurs when the formations on either side of the fault have been moved into a position that prevents further migration of petroleum. For example, an impermeable formation on one side of the fault may have moved opposite the petroleum-bearing formation on the other side of the fault. Further migration of petroleum is prevented by the impermeable layer (B).

Stratigraphic traps are traps that result when the reservoir bed is sealed by other beds or by a change in porosity or permeability within the reservoir bed itself. There are many different kinds of Stratigraphic traps. In one type, a tilted or inclined layer of petroleum-bearing rock is cutoff or truncated by an essentially horizontal, impermeable rock layer (C).

Or sometimes a petroleum-bearing formation pinches out; that is, the formation is gradually cut off by an overlying layer. Another Stratigraphic trap occurs when a porous and permeable reservoir bed is surrounded by impermeable rock. Still another type occurs when there is a change in porosity and permeability in the reservoir itself. The upper reaches of the reservoir may be impermeable and nonporous, while the lower part is permeable and porous and contains hydrocarbons.

FINDING OIL & GAS

Hydrocarbons - crude oil and natural gas - are found in certain layers of rock that are usually buried deep beneath the surface of the earth. In order for a rock layer to qualify as a good source of hydrocarbons, it must meet several criteria.

Characteristics of Reservoir Rock
For one thing, good reservoir rocks (a reservoir is a formation that contains hydrocarbons) have porosity. Porosity is a measure of the openings in a rock, openings in which petroleum can exist. Even though a reservoir rock looks solid to the naked eye, a microscopic examination reveals the existence of tiny openings in the rock. These openings are called pores. Thus a rock with pores is said to be porous and is said to have porosity (Figure 1).


AFigure 1: Porositynother characteristic of reservoir rock is that it must be permeable. That is, the pores of the rock must be connected together so that hydrocarbons can move from one pore to another (Figure 2). Unless hydrocarbons can move and flow from pore to pore, the hydrocarbons remain locked in place and cannot flow into a well. In addition to porosity and permeability reservoir rocks must also exist in a very special way. To understand how, it is necessary to cross the time barrier and take an imaginary trip back into the very ancient past.

Figure 2: Permeability Imagine standing on the shore of an ancient sea, millions of years ago. A small distance from the shore, perhaps a dinosaur crashes through a jungle of leafy tree ferns, while in the air, flying reptiles dive and soar after giant dragonflies. In contrast to the hustle and bustle on land and in the air, the surface of the sea appears very quiet. Yet, the quiet surface condition is deceptive. A look below the surface reveals that life and death occur constantly in the blue depths of the sea. Countless millions of tiny microscopic organisms eat, are eaten and die. As they die, their small remains fall as a constant rain of organic matter that accumulates in enormous quantities on the sea floor. There, the remains are mixed in with the ooze and sand that form the ocean bottom.

As the countless millennia march inexorably by, layer upon layer of sediments build up. Those buried the deepest undergo a transition; they are transformed into rock. Also, another transition occurs: changed by heat, by the tremendous weight and pressure of the overlying sediments, and by forces that even today are not fully understood, the organic material in the rock becomes petroleum. But the story is not over.

For, while petroleum was being formed, cataclysmic events were occurring elsewhere. Great earthquakes opened huge cracks, or faults, in the earth's crust. Layers of rock were folded upward and downward. Molten rock thrust its way upward, displacing surrounding solid beds into a variety of shapes. Vast blocks of earth were shoved upward, dropped downward or moved laterally. Some formations were exposed to wind and water erosion and then once again buried. Gulfs and inlets were surrounded by land, and the resulting inland seas were left to evaporate in the relentless sun. Earth's very shape had been changed.

Meanwhile, the newly born hydrocarbons lay cradled in their source rocks. But as the great weight of the overlying rocks and sediments pushed downward, the petroleum was forced out of its birthplace. It began to migrate. Seeping through cracks and fissures, oozing through minute connections between the rock grains, petroleum began a journey upward. Indeed, some of it eventually reached the surface where it collected in large pools of tar, there to lie in wait for unsuspecting beasts to stumble into its sticky trap. However, some petroleum did not reach the surface. Instead, its upward migration was stopped by an impervious or impermeable layer of rock. It lay trapped far beneath the surface. It is this petroleum that today's oilmen seek.

Large Potential Financial Reward

By concentrating its efforts in proven natural gas provinces, CORPO-PETROL can utilize existing infrastructure to quickly develop and market its natural gas and oil production. The company pays close attention to the details of its operations, and controls the costs and expenses of its operations, which ultimately improves the economics of its projects for itself and its investing partners.

Although not a guarantee of future performance, investing in an array of oil and gas prospects is an excellent way to diversify any portfolio. Returns on successful oil and gas investments can be expected to significantly outperform high-yield corporate bonds and mutual funds.

Tax Benefits

With a proper election, and when monies are considered at risk and not passive for IRS purposes, intangible drilling and development costs may be deducted as an expense for federal income tax purposes. Generally, intangible costs constitute anywhere from 75% to 95% of the total cost to drill, complete, and equip the well. All of these "non-salvageable" costs are deductible in the year expensed.

To be certain, this deduction can be quite significant, and the large write-off potential signifies the government's desire to increase domestic drilling discoveries.

In addition, the owner of an oil and gas interest is generally entitled to a deduction for depletion with respect to the income received from the productions of oil and gas. This allowance has changed several times through the years, but currently allows for 15% of the revenue to be tax-free.

The following is a generalized summary of certain items in the U.S. Internal Revenue Code relating to oil and gas exploration. It is neither exhaustive nor detailed. Each individual should understand how these items will impact him or her personally. In addition, other items unique to the individual may also be relevant. Investors should contact their tax consultants for a complete explanation of the benefits of investing in oil and gas

Energy Markets

Through the 1990's up to the present, natural gas has become the preferable fuel, and demand for natural gas has been increasing yearly, while domestic supply has decreased because of depleting fields and a lack of domestic drilling. These fundamentals have caused a sustained rise in natural gas prices, and these indicators suggest that high prices will continue for the near future.

Oil and Gas Investor

Consider making an investment in the oil & gas industry... it is just too good to pass-up right now...as usual, as almost everyone knows...this is particularly so, when you are investing with the right people, and at the right time, and place...

I believe the oil & gas business just got a lot more interesting for you active investors...we now have much better...and more accurate methods of finding large commercial reserves of oil & gas than ever before...and this is making our business even more exciting, and profitable... than in the recent past...especially because of the new technology, and again...much more accurate process of verifying targets where the biggest, and most likely recoverable reserves of natural gas, and oil are and will be found...

Our computer power, and speed available now, plus having access to a huge historical data base of oil & gas data...is making the identification process much more of a 'check-list technique' of finding the best reservoirs of both oil & gas, than ever before... and as a result this is where production revenue is being established in the big numbers...

How big? How about establishing on line production of eight million cubic feet of natural gas per day, and 860 barrels of oil per day, while on a 4/64ths choke...from a single well...for those of you with some technical expertise...

To make a long story short...this rather expensive and deep well in the Gulf States area will pay-out in less than six months at current pricing in the marketplace. I see quite a few of these new wells being brought on line these days...

You can diversify in a production package, or participate in a number of single wells to spread-out your risk...and take the excellent tax write-offs as well...this is a perfect time of the year to invest because you will have all year long to generate cash flow, and take the big first year Intangible Drilling Cost (IDC), write-offs...these IDC'S can be 80% or more of your original investment in the first year of your investment...You also take depreciation and get a 15% or more depletion allowance on the revenue side each year...

Oil and Gas Investor

Consider making an investment in the oil & gas industry... it is just too good to pass-up right now...as usual, as almost everyone knows...this is particularly so, when you are investing with the right people, and at the right time, and place...

I believe the oil & gas business just got a lot more interesting for you active investors...we now have much better...and more accurate methods of finding large commercial reserves of oil & gas than ever before...and this is making our business even more exciting, and profitable... than in the recent past...especially because of the new technology, and again...much more accurate process of verifying targets where the biggest, and most likely recoverable reserves of natural gas, and oil are and will be found...

Our computer power, and speed available now, plus having access to a huge historical data base of oil & gas data...is making the identification process much more of a 'check-list technique' of finding the best reservoirs of both oil & gas, than ever before... and as a result this is where production revenue is being established in the big numbers...

How big? How about establishing on line production of eight million cubic feet of natural gas per day, and 860 barrels of oil per day, while on a 4/64ths choke...from a single well...for those of you with some technical expertise...

To make a long story short...this rather expensive and deep well in the Gulf States area will pay-out in less than six months at current pricing in the marketplace. I see quite a few of these new wells being brought on line these days...

You can diversify in a production package, or participate in a number of single wells to spread-out your risk...and take the excellent tax write-offs as well...this is a perfect time of the year to invest because you will have all year long to generate cash flow, and take the big first year Intangible Drilling Cost (IDC), write-offs...these IDC'S can be 80% or more of your original investment in the first year of your investment...You also take depreciation and get a 15% or more depletion allowance on the revenue side each year...