North Dakota Oil Production Jumps 12.8% in 2007 Bakken Output Increases 329% Compared to 2006
North Dakota’s 2007 oil production recorded a healthy leap compared to a year earlier. For the year 2007, the state reported that total oil produced was 45,057,874 bo, up an impressive 5,114,464 bo as opposed to the 39,943,410 produced in 2006. These production totals makes 2007 the seventh largest year on record since the oil was first discovered within North Dakota in 1951.

Of course one of the major factors in this increase in production is the Bakken formation. According to state figures, in 2007, the Bakken is credited with producing 7,382,025 bo, up an incredible 329% compared to the 2,245,411 extracted from the same formation in 2006. This increase of over 5 million barrels bespeaks of the technological advances in horizontal drilling and more importantly, the record levels of the price of oil. The current hotspot for those operators that are chasing the Bakken are in Mountrail and Dunn Counties. Presently, of the 59 rigs that are making hole in the state, 36 of them are within these two counties looking for another Parshall field, the states largest Bakken oil pool. This field, which is in Mountrail County, is currently producing over 278 k bo per month from 21 wells and is currently under aggressive exploitation. It’s also noteworthy to point out that production within these two counties has greatly increased. In 2006, Mountrail and Dunn counties produced 415,434 bo and 984,863 bo respectively. A year later, Mountrail County reported production of 1,960,091 bo while Dunn County increased their output to 1,913,598 bo.

It should be pointed out that in 2006, the Bakken accounted for 5.6% of the states total oil output from 300 active wells. In 2007, the Bakken represented 16.6% of the states output from 457 wells. The only other formations that had a higher percentage of oil produced during 2007 was the Madison and Red River “B”. It’s anticipated that the results for 2008 will show even greater numbers for the Bakken.

Although a great deal has been written about the Bakken play within the state, it should be remembered that the Ordovician Red River “B” is still king. This formation produced 16,722,579 bo or 37.6% of the states production in 2007. In 2006, the Red River “B” cumulated 15,706,913 bo. The source of this production is coming from the Greater Cedar Creek Anticline, primary the Cedar Hills South Unit (CHSU) in Bowman County. In fact, for the month of December 2007, the latest production figures that are currently available, the CHSU produced 1,072,933 bo from 136 horizontal wells.

Of the 161 operators reporting production within the state for 2007, Burlington Resources (BR) was far and away industry’s leader. Retaining their #1 spot, BR reported production of 12,690,287 bo, up 425,475 bo compared to a year earlier. This production by BR is over twice that of the second largest producer in the state. The vast majority of BR’s production is due to the company’s aggressive horizontal Red River “B” drilling program occurring in Bowman County, however the company is getting increasingly active in the horizontal Bakken play, and has numerous prospects planned in Dunn County.

Another company who is major actor in the Red River “B” play is Continental Resources (CR). CR was second largest producer in the state, having extracted 5,146,714 bo for the year, up 1,237,361 bo compared to 2006. Aside from their activity in the Red River “B” play, CR is also a large player in the Bakken play with prospects planned or drilled in Divide, Billings, McKenzie, Mountrail and Williams County.

Hess Corporation (Hess) maintained it’s third place standing in 2007 with a yearly production of 4,189,870 bo. The majority of Hess’s production is coming from the Nesson Anticline in Williams and McKenzie counties. In 2006, Hess produced 3,528,876 bo. Hess is another company who is getting more aggressive chasing the Bakken and currently has five rigs working in Mountrail County evaluating their holdings.

Encore Operating, by virtue of their purchase of Kerr-McGee’s properties in the state, ranked number 4 with a yearly production total of 3,259,711 bo. A year earlier, the company reported that they had produced 529,439 bo.

The states fifth largest producer was Whiting O&G (Whiting). Whiting is credited with extracting 2,298,580 bo in 2007, up 105,112 bo compared to 2006. Look for Whiting’s production to increase in 2008 as the company continues their Bakken program in Mountrail County, primarily that area north of the Sanish Field area.

A quick look at drilling statistics for the state in 2007 show that a total of 407 wells were spud for the year with Dunn County leading with 70 spuds, followed by Williams County with 61. Mountrail County had 60 wells initiated and Bowman County had 56.
The following list ranks the top oil producers in the state of North Dakota for the year 2007. Please note that the company rankings for oil and gas do not include confidential wells, skimmed oil, drip gas or other liquids extracted during gas processing.

The Barnett Shale is a natural gas source bed rock that stretches over 16 to 21 North Texas counties and is still actively being discovered. Its 6,000 + square-mile reservoir is already the second largest producing on-shore domestic natural gas field in the United States after the San Juan Basin in New Mexico and Colorado. At three different times spread out by 100 million years, Texas was actually a shallow ocean that stretched up the central plains and even carried up into and through Canada. The first 100 feet of ocean is considered the Photo Eukaric Zone since light can penetrate the first 100 feet. With light and heat being a factor in this shallow body of water we can assume these oceans had a huge phytoplankton and zooplankton population and with that, massive coral reef beds were created by filtering the massive plankton population. This was the environment in most of Texas some 300 to 600 million years ago as the ocean came in and out at least three different times in the Fort Worth Basin. The Barnett Shale gas field was discovered by wildcatters in the early 1950’s who were pioneering the Conglomerate, Marble Falls, Pregnant Shale, and Strawn Zones.

The technology to produce from The Barnett Shale did not evolve until 1980. This is the first area in the entire world where we are pioneering the art of producing natural gas from a source bed rock and it is alive and anaerobic.

The vast majority of the industry is unconcerned with the oxygen output, CO2 reduction, or the circle of life, instead an industry wide success rate of 97% and 5% of the nations natural gas supply make this field the most active onshore drilling play in the United States.

In fact, in every other area of the world, every drop of oil and natural gas has already escaped from the source and has been actively working its way on up to the surface only to be trapped by structure and horizons of geological time zones. In these upper production zones, a degree of permeability and porosity must exist so that we can produce from the formation. The Barnett Shale has almost no porosity and no permeability which was the reason why until now source bed rocks have not been produced from. Therefore it is safe to say that these explorers will spread their knowledge of source bed rock stimulation and production throughout the world. So what is going on here in Texas is extremely different because every operator and producer here is a pioneer in the most advanced cutting edge and active play in the world.

Shale consists of very fine grained particles of quartz and clay minerals. It is consolidated mud that has been deposited in lakes, seas, inland oceans, and other similar environments. About, forty five (45%) percent of all exposed sedimentary rocks are shales.

Organic Sedimentary Rocks are formed from organic debris. It is the deposit of once-living organisms all collected and sealed into a medley of what once was. (shells, corals, calcareous algae, wood, plants, bones etc.) Although they are a form of clastic rock, organic rocks tend to contain a larger amount of immaculately preserved fossils, which laid down near the place where the animal, coral, plant, or plankton once lived.

As the rocky mountains formed, several separate ocean beds were created in the state of Texas and are identified as The Delaware Basin, The Permian Basin and The Fort Worth Basin. The Barnett Shale is in the Fort Worth Basin and because of its maturity and age we are able to fracture and produce from this blanket formation. The Permian basin sets an example from its exploration history and research being from coral reef beds itself. The word “frac” is used as a term out on the oil patch that describes our ability to fracture and stimulate zones horizontally by creating new channels and areas while increasing the porosity and permeability of an area out side of the production pipe we have just perforated. Perforating is shooting through the production casing and into our zone. In this case the “Barnett Shale Zone” is the organic settlement of life itself proving the theories of oceans, ice ages, volcanoes, and meteorite impacts. However, this field is completely different in many aspects. This ancient shallow ocean in which the Barnett Shale is believed to be divided in two zones; the upper and lower Barnett Shale. By producing and reviewing logs in the primary core of the Barnett shale I have noticed three zones; this proves three flooding events. Under the primary core and three layers you will find a thick layer of obsidian (obsidian is a blackish translucent glass). This is probably the result of a meteorite impact in conjunction with several triggered volcanic eruptions, which then caused the ice ages and eventually the oceans. The first two ocean occurrences were closer together in time and defined as the “lower zone”; the third one spanned at least 100 million years later which is now called the “upper zone”.

Time zones are geologically missing from this shale area, which perplexes others as to what happened to this time frame in the Barnett Shale. My only assumption is that the oceans continually existed in this time and either eroded or absorbed the span of these missing formations. We have three faults and three times that the ocean came in and out of the Fort Worth Basin spread out over 300-700 million years we also have three vertical faults in the shale. Unlike most formations these Barnett Shale faults are areas to avoid because they are incapable of producing any gas or form of production such as the Muenster Arch Basin fault zone. Add plate tectonic action and 200 million more years for maturity and we have our current situation today. At the core area of the Barnett Shale we find the third zone in this shale which is the existence of the first ocean sediment itself. Also in this lower level there is more maturity and higher levels of gas and condensate with a higher (BTU) British Thermal Unit rating.

Obsidian is found underneath this third layer proving some meteorite and volcanic activity before the creation of these oceans. The northern and older part of the Barnett Shale between Denton and Decatur produces a higher 1278-BTU rating as we follow the Shale south to Fort Worth the BTU drops to 966-BTU. I have noticed that some operators are only successful in certain areas and most of this has to do with their frac techniques in conjunction with either the low BTU or High BTU areas. CO2 stimulation is what I would scientifically recommend to induce breathing in an anaerobic organic environment. Major oil companies have decided to concentrate in different areas of this shale and even other new shale discoveries because of their different fracturing techniques, beliefs, discoveries, and abilities. By inducing the anaerobic environment with CO2 we stimulate oxygen and natural gas. We can then separate the natural gas into Hydrogen and CO2 we then use the Hydrogen and return the “CO2” to the “anaerobic bacteria environment” to produce more “Oxygen” and more “Natural Gas”; the result is the first major “circle of life” between our ecosystem and sustainable natural gas production in the Barnett Shale.

The reason for failure in the Barnett Shale Play is simple. Spacing and depth are the essentials in producing from this zone. A fine layer of obsidian covers the Ellenberger Zone which must be watched and avoided. 60 acre spacing seems to be a common norm for safety in vertical wells. If a well hits the Ellenberger it will produce water and we consider the well “Killed”. Horizontal wells require at least 4 times the normal spacing. Problems: If one of the fractures goes into the Ellenberger Zone which is below the Barnett Shale then all of the gas will follow the path of least resistance and flow into the Ellenberger zone which is mainly water here in this area. Certain new companies have learned how to find this gas now trapped in the Ellenberger and are working on a purification process which extracts all of the gases and precious metals from the water. Some of the water will be used to maintain the water level of Lake Bridgeport.

What is creating all of this gas and why is it considered a source bed rock? The Shale is basically compacted organic composition and living at a high temperature. Inside this compacted shale we find that it has life and that there is anaerobic bacteria feeding on a decomposed coral reef shale producing gas. The bacteria I believe lives in an anaerobic environment and can be stimulated with CO2, the bacteria in turn is stimulated and literally excretes methane. However the rock is so dense that a lot of the gas stays trapped uniformly perfect and even in the rock. What happens with this other gas that leaves through the surface of the shale? It rises and is trapped in other structures and feeds other zones such as the conglomerate. Most of these zones were discovered before we discovered the shale because we did not go deeper. The Barnet Shale is about at 8900 to 8400 feet deep along highway 380 in between Denton and Decatur Texas. We know that the ocean / Ellenberger is at around 8000′ – 10,000′ here. The inorganic theory suggests that petroleum can come from an inorganic- or nonliving source; this theory has failed to produce a single drop of oil or natural gas. The Barnett Shale is 100% percent organic and produced from an organic source ( an old dead ocean) it is like having a huge anaerobic digester trapped miles deep and if maintained correctly could last indefinitely. I use the earth itself as an anaerobic digester much like the one below – but instead of building a container at the surface – I use the shale very much in the same fashion except 7,000 – 10,0000 deep. Truthfully, many cities could take advantage of this same principle using large Carsts or Caverns in connection with the cities sewage systems – the results would immediately produce usable gas just like we are doing in the shale. Look at the anaerobic digester below using cotton hulls it can power over 300 homes in Texas -talk about a use for waste!

The United States Geological Society estimates that the entire Barnett Shale field contains 27 trillion cubic feet of gas. Estimates of the size of Barnett Shale’s reserves are rapidly increasing; the field is starting to make a big impact on the nation’s gas business at a time of declining domestic production and projections of rising demand. Gas executives predict that the current production of 1.5 billion cubic feet a day — 2.5 percent of the national output — has the potential to climb to 3 billion to 4 billion cubic feet a day in a few years. New discoveries in the “outer fringes” of the shale define as what Mr. Jim Leatherwood calls “the Paleo landscape” this term correctly defines the reason for success and failure due to the result of the ancient ocean’s floor and channel contour. The “Paleo landscape” is now the wildcatters frontier in the Barnett shale.

Questions and concerns? Extremely high gas pressures leak into shallow to deep fresh ground water fields. The problem. The annulus in between the production casing and the earth / dirt or ground itself creates a passageway for gas to escape into different horizons. Gas can work its way up a small channel that can develop in between the production casing and the dirt we call this channel the annulus this channel can grow because of extreme lower gas zone pressures and poison large shallow fresh water reserves. Is there a solution? Yes! In Artesia New Mexico they noticed a great natural resource early on with their artesian fresh water springs – they did not want to contaminate their naturally carbonated water. So, they cement around the pipe the whole way down destroying the annulus. Yes its more expensive, but water is really more of a precious resource than gas.

The Interstate I-35 E was the edge of this ocean and as a result it is the edge of the Barnett Shale Zone. A history of the drilling activity teaches us that the “primary zone” of this Barnett Shale is in between Denton and Decatur Texas stretching down to Fort Worth Texas. We know that the zone is thicker and richer in natural gas the further north in the Barnett shale and has a higher BTU rating @1200 and the further south towards Fort Worth we find a BTU rating @ 996. Unlike other source beds we have learned to avoid the fault lines that exist because they do not produce gas and are accurately mapped by geo map on active production in the area.

Frank Dux the legendary world champion martial arts Bloodsport & Kumite master is using money from the Barnett Shale to save the rainforests and children throughout the world. The three men run Dux Inc. and are Asian Ambassadors for the Clean World Wide Water Plan. The plan combines solar panels and wind generators which feed water dehumidifiers for constant clean water and constant hydrogen energy. These three men not only hold the key to world wide freedom but they educate everyone about the answer to save everyone by providing clean water to every child, animal, crop, and city throughout the world, by using the sun, the wind, and commercial dehumidifiers together as the sustainable solution. The water extracted in the atmosphere is the cleanest water ever tested according to the Environmental Protection Agency (EPA). The cost of water extraction is free because of sustainable integration (solar & wind) the results are the keys to world wide freedom and peace. The technology is the exact reverse of what is done in the Barnett shale to stimulate anaerobic life.

The most interesting thing about this Barnett Shale is how solid it is. Typically when we measure for permeability or porosity we calculate in darceys as a form of measurement. However, in the Barnett Shale we calculate our porosity and permeability in anchstroms or shall I say, atomic measure. This means that the shale is so tight that gas has a hard time escaping it. Drilling through the shale is like drilling through a Brunswick pool table or bowling ball. Yet we find several interesting factors in the shale itself such as micro fractures that travel from the north east to the southwest. We use these micro fractures when we horizontally drill to utilize the structure in combination with the multi stage frac job. Halliburton has several multi frac techniques that will literally amaze you. Using micro radio transmission devices and special fluids the company is literally able to follow each fracture in amazing detail. You get what you pay for and horizontal frac jobs can go easily between 4$ and 12$ million. Devon itself claims that the work itself is very costly and still an educational process. James Hall of Devon is leading the industry in horizontal production discoveries and results.

Many smaller operators are experiencing the same dramatic results using standard old vertical techniques and open hole completions. Open hole completions? Yes, you heard me right. The shale is so very solid that it is more stable than what we could put down there and it allows us to cover more area. The trick in developing this field is spacing. 60 acre’s seems to be a safe space for wells in the Barnett Shale. Many of the majors have killed off some of their nearby wells by drilling to close or having a huge horizontal with a bad frac job lose the area. The trick in this field is not finding the zone – its not getting greedy. If you pass the Barnett Shale you have entered the ocean you hit the ocean you ruined your project. Engineers, be ready to spot obsidian which covers the Ellenberger Zone- the zone you must avoid. If a nearby well hits the ocean and has fractured into your zone that well has just ruined your production region. That gas will shoot out into the ocean instead of up your hole.

The most successful wildcatter in Texas history is, C.W. Sanders (32°) with a wildcat success rate of 87.5% in the days before advanced 3D seismic technology. He used two very conventional methods for drilling success; one he coined “lineology”, whereas you would draw a straight line between two good wells and create a location.

The Paleo Landscape and the Birth of the Barnett Shale began with the defining of the Fort Worth Basin and also the Conglomerate Zone discovered by early Wildcatters such as Coke Gage, P. Ellenberger, T.B. Pickens, George Mitchell, Norman Stovall, C.W. Sanders, Frank Pitts, and William ZuHone. But George Mitchell discovered how to stimulate this zone and with that and the established conglomerate zone above it a blanket coverage was quickly defined to be the “Barnett Shale”. It was soon later known through science that this layer was in fact responsible for feeding the above zones with natural gas and that this was in fact the source bed rock.

Mitchell Energy / George Mitchell was acquired by Devon in January 2002, and began developing the Barnett Shale in the Fort Worth Basin in the northeast sector of central Texas in 1981. His down hole man F.M. Wigington a.k.a. “Doc” has now teamed up with the Natural Gas Group, Organic Inc., and Dedica and is expected to begin production in southern Jack County early in 2006. This team along with William Zuhone of Dedica have the most experience in the shale today. The Mississippian-age Barnett Shale is one of the most uniform stratigraphic units in the basin, outcropping along the flanks of the Llano uplift in central Texas, where it is about 30 to 50 feet thick. The Barnett Shale dips gently and thickens to the north, reaching a maximum depth of around 8,900 feet and a maximum width of almost 1,000 feet near the Texas-Oklahoma border.

Large fractures in the Barnett Shale are created by tectonic stresses created after deposition about 300 million years ago. Huge grids of small sized fractures extend northeast southwest across the area, but could not be produced until onset of newer fracturing techniques. Barnett Shale production was first established in the Newark East Field in Wise and Denton counties, where it grew from less than one billion cubic feet of gas from 25 wells in 1985 to 19.2 billion cubic feet from 306 wells in 1995. During the past five years, production has more than doubled to 40.6 billion cubic feet from over 500 wells.

The Barnett Shale is really only to the west of I-35 and leaves Dallas County pretty much out of the play. Chris Sanders has created several new entities which all demand earth friendly and sustainable projects that are combined into his Barnett Shale projects. Sanders Drilling is now negotiating a drilling program with 1.7 million acres that are both ready for natural gas and wind farms. The firm continues to expand its play area with twenty wells in Southeast Jack County. In 1998 Rich Green / Chevron / LNG and Chris Sanders experimented with a new stimulation technique that employed water as the fracturing fluid, required significantly less proppant and was about 60 percent less expensive than the conventional stimulation treatments. The technique proved successful and has since been implemented field wide. September of 2005 the team completed its 77 successful well in the Barnett Shale using this process with the injection of treated carbon dioxide in water. They also provide millions of cubic feet of oxygen to the atmosphere for our breathing environment because the substrate in the shale transforms this CO2 into both natural gas and oxygen. Since then a new frac method called the “soda pop” has been developed with 12 wells that have already pushed 22 million dollars in natural gas returns. Currently, they are concentrating on the oil returns of the shale in the North West region of the play. STRAWN SANDS Usually above 5000′ ; occurs as channel sands, extremely productive locally. CADDO LIME Occurs below the last Strawn Sand and may be thick and prolific as at Breckenridge. CADDO CONGLOMERATES A series of coarse-grained sands particularly prolific in Montague County just to the northwest. CONGLOMERATES The major pay in this area producing over 3 trillion cubic feet of gas in Wise County.

CONGLOMERATES ATOKA-BEND

The major pay in this area producing over 3 trillion cubic feet of gas in Wise County. MARBLE FALLS LIME A zone above the Barnett at about 7000′. This may produce in the Fletcher well. BARNETT SHALE “SOURCE BED ROCK” Thick hydrocarbon rich shale between 100′ -1000′ thick occurring at depths below 7000′ to as deep as 9000′. OBSIDIAN Evidence of a massive explosion or super volcano. – perhaps Yellowstone MISSISSIPPIAN REEF Thick and prolific but rare, reefs produce mostly to the west or in the Bend Arch. VIOLA LIME Locally productive on structures in the northern portion of the Fort Worth Basin needs a structural trap.> Ellenberger The deepest pay at nearly 10,000′ deep in the deeper portion of the Fort worth Basin needs a structural trap. two major epics the Devonian is missing Silurian is missing 100 of millions of years.

The three key advantages of shale gas plays are as follows: moderate development costs, high success rates, and slow production decline rates. The rapid growth in the late 1980s and early 1990s in the Barnett Shale which is being repeated today in the Antrim Shale, and San Juan basins, is driven by the powerful economic incentives of low risks and low reserve finding costs. Recent technological advances in hydraulic fracturing, coupled with the application of multiple fracture stimulations over the life of a well to recover additional reserves create an attractive opportunity to produce in the Barnett Shale.

A thick section of organic rich shales is found in the deep part of the Delaware basin of west Texas. Leasing activity targeting this potential shale gas resource has been concentrated in two counties, Reeves and Culberson, with several companies amassing leasehold positions ranging from a few tens of thousands of acres to nearly a million acres, and is rapidly spilling over into adjoining counties of both Texas and southeast New Mexico.
The combined thickness of radioactive Woodford (Devonian) and Barnett (Mississippian) Shales approaches 1000 ft. The Woodford has extremely high gamma ray intensity, exceeding 300 API units in the middle part, whereas the Barnett may have lower average TOC based upon gamma ray values of 150 to 200 API. Average bulk densities of the two units are comparable with the Woodford showing lower average densities to the south and east. The drilling depth to the base of the shales ranges from 6000 ft to over 19000 ft in extreme northern Reeves County. Published vitrinite reflectance data indicate much of the play area lies within the gas window.
What we know at this time is based on nearly 400 wells drilled through the Barnett-Woodford on the way to deeper, conventional objectives. Modern log suites are available for about 250 wells, there are numerous cuttings sets and sample descriptions, gas shows were reported in many wells, but the shales were not cored. Several tests have been drilled in the last 18 months to test the shales, some of which were cored and are being currently tested, but the data are still highly confidential. On an area and net thickness basis alone the play appears to have multi-TCF potential, but whether commercial flow rates can be established remains to be seen.

NAE is partnering with EnCana and Samson is pursuit of commercially exploiting fractured shale resources in the Cane Creek Shale in the northern Paradox basin. Delta and Fidelity are currently drilling wells in the play area, and other companies are expected to commence drilling Cane Creek wells soon. NAE controls approximately 12,000 net acres of highly prospective leases in the core of Delta’s Greentown play area and has a farmout option on an additional 8,000 net acres in the area. Delta has reported impressive flow rates from their early drilling in the play, with rates as high as 4 MMCFGD and 800 BOPD. They are currently producing associated gas from one well into their newly built 18” gas pipeline. Fidelity has indicated a very successful Cane Creek and “O” Zone oil completion in their recently drilled well adjacent to our acreage position south of Cactus Rose Unit. Unfortunately, that well experienced collapsed casing and is being re-drilled. NAE expects to find 5-10 BCFE/well reserves on 80 acre spacing in the play fairway.

The map of the Eagle Ford shale above shows where new wells have been drilled as of January 2010. There have subsequently been more drilled in other counties including Karnes county and Gonzales county.

What Is The Eagle Ford Shale?

The layer of rock that has oil and gas investors excited was named after then tiny community of Eagle Ford, where the formation outcrops, or reaches the surface, near Dallas. As the shale rops off underground it reaches a depth of over 15,000 feet in South Texas.

Shale gas and crude oil derived from shale beds using horizontal drilling represents our newest and most important energy ace in the hole. While wind and solar derived energy are the best long term goal it takes billions of BTU’s worth of fossil fuel energy to get there and to run our economy in the meantime. We now import over 65% of the oil we use. It is natural gas, of which we have over 100 years supply, that is gaining attention in the national spotlight.

How Shales Like The Eagle Ford Were Formed

Oil and gas that are trapped in shale rock were formed by trillions upon trillions of microscopic organisms that once lived in ancient seas and which died and were then deposited in layers of ocean sediment. That ocean muck, rich in organic matter, later became rock over millions of years. The Eagle Ford shale was formed in the Cretaceous period approximately 143 to 65 million years ago. During the Cretaceous the world was warmer and warm seas teeming with all sorts of life covered much of the planet including North America.

Where Is The Eagle Ford Shale?

The Eagle Ford shale play, as oil and gas investors call an area of activity, is a broad crescent shaped zone that spans from near Mexico to southeast Texas. Approximately 30 to 50 miles in width, it is proving to contain incredible amounts of oil and natural gas. Companies such as Petrohawk Energy, who first got the Eagle Ford shale ball rolling in McMullen and LaSalle counties, are regularly making wells that produce over 8 million cubic feet equivalent of natural gas per day.

Petrohawk has also discovered a very productive oil area in the Eagle Ford in Zavala county and continues to explore the Hawkville field, in McMullen and LaSalle counties with 3D seismic surveys to locate the best places to drill.. They stated the following in their latest report to shareholders: “In the Eagle Ford Shale, Petrohawk is continuing its delineation of the Hawkville Field and is transitioning into the development of the field. There are currently four rigs running in the field. In order to acquire 3D seismic data over the entire Hawkville field, the Company is currently shooting approximately 350 square miles of 3D seismic, adding to the 100 square mile data set completed in 2009.”

Petrohawk has sold most of their older properties in the Permian Basin, near Midland Texas, to concentrate on the Eagle Ford and Haynesville shale. A host of other companies are leasing up thousands of acres of South Texas, including Conoco-Phillips, EOG, Pioneer Resources, Antatres and others.

Eagle Ford Shale Lease Amounts Rising

When the Eagle Ford shale was first being explored by Petrohawk in McMullen and LaSalle counties, lease rates were as low as $250 an acre. Leasing for Eagle Ford drilling is becoming so competitive that reports of over $2000 per acre, just for the right to explore for three years, are becoming common in some areas.

As shale plays go the Eagle Ford shale is not as large as the Marcellus shale, which lies under Pennsylvania and other northern states, but is exciting to oil and gas investors because it contains oil as well as natural gas. With some wells in the “oily” section, or northern part of the shale, producing well over 300 barrels a day, the revenue prospects are very good.

Economic Impact Of The Eagle Ford Shale

South Texas is no stranger to oil and gas drilling. That industry has been an important part of the economy for decades. Oil booms and busts have come and gone, leaving some people richer and some poorer than when they began. What promises to make this boom different is the widespread nature of shale beds such as the Eagle Ford. Unlike stratigraphic and structural traps, which trap oil and gas in “pockets” of a porous material like sand or limestone, a shale bed may uniformly cover a wide area. Because of the widespread nature of shale beds, and the fact that it may take decades to “drill out” the play, the economic benefits in terms of jobs and income may be much more long lasting than other oil and gas plays such as the Austin Chalk boom was a few years ago. Fields like the Hawkville field span more than fifty miles in length and twenty five miles wide. The chance of any well in that area being productive are very high. The geology of the Eagle Ford shale changes from county to county and the full extent of productive acreage is still being determined. There is now Eagle Ford shale drilling in LaVaca, DeWitt, Karnes, McMullen, LaSalle, Live Oak, Dimmitt, Zavala, Maverick, Atascosa, Wilson and an handful of other counties of Texas.

If you are considering leasing your property for oil and gas drilling I highly recommend the book “Money In The Ground” which can be found on Amazon below. You can learn how to avoid things like the “Mother Hubbard clause” and protect your interests.

The Shiloh Project is a coal bed methane (CBM) and conventional gas project located in Allen and Neosho Counties of eastern Kansas. This is the Company’s most advanced project in the Cherokee Basin and a major focus of its 2006 Development Program. The Company holds a 100% Working Interest in the project.

wells on this 18,400+ acre project, with the first 106 Since development began at the project in 2004, Admiral Bay has drilled and/or re-activated 147 wells now connected to the pipeline and dewatering/selling gas. Work to connect the remaining wells is ongoing. The project is presently producing 2.0 to 2.3 MCFGPD. Admiral Bay has targeted the Summit, Excello (Mulky), Bevier, Mineral, Tebo B and Riverton coals and carbonaceous shales. Admiral Bay has a 100% working interest. The Company presently has 106 wells producing and 41 wells awaiting completion or connection to the gas gathering system. There is an addition 230 locations to drill based on 80 acre spacing. Quest Engineering has given the Project Proved Reserves of 13.31 BCF , and 2P and 3P reserves of 13.91 BCF (Billion cubic feet). The first ten wells were completed in multiple zones. However, since then the remaining wells are now predominantly completed in a single coal seam, generally the Riverton. The Company has found that by completing wells in only the Riverton, the wells tend to have higher production rates in a shorter period of time, with the well producing considerably less water. Wells begin producing gas anywhere from zero to 30 Mcf/day with 30 to 100 barrels of water a day. Over time, as the wells continued to be produced, gas production increases and water production continues to decrease. The Company is evaluating the Summit and Excello (Mulky) carbonaceous shales as potentila target zones of interest.

In December of 2006, the Company received an expression of interest for a competitor in the basin. Because of an uncertain future for eight months the Company’s work program was suspended, wells were not maintained and preventive maintenance was not ongoing. This caused the Company not to drill wells and subsequently fell behind in terms of adding incremental production. Since the closing of the Gas Rock financing and replacement of the Macquarie debt facility the project now has had a significant chemical program put into place that has reduced well pulls form dozens a week to about one to three a week. Admiral Bay continues actively lease in the project area. The Company is targeting to increase its land position at the project.

Drilling depths for the coals and carbonanceous shales vary from are 450 to 1,200 feet. Secondary targets are oil and gas in the Pennsylvanian Squirrel, Cattlemen and Bartlesville Sandstones. Historically, reserves from the Bartlesville or equivalent sandstones vary from 10,000 to 150,000 barrels of oil from 10 acres or less at depths of less than 1,000 feet. Coals tested in wells drilled in the project area indicate that the Riverton coal is carrying in excess of 352 SCF (standard cubic feet) per ton and have over 145 millidarcies permeability. Historically, conventional oil and gas wells in the Shiloh Project area have flowed up to 400 MCFGPD and produced up to 70 barrels of oil a day (and wells are often a combination of oil and gas).

Thousands of feet below Arkansas hay fields and cow pastures, a newly tapped reservoir of natural gas is quietly giving up its bounty. After 300 million years trapped in hard, black shale, gas now flows into pipelines headed for market to ultimately warm homes and businesses.

In the flicker of five years, the Fayetteville Shale has gone from “just sort of a geologic oddity” to a significant industrial development, Investors, so far, are satisfied with early production and a university study says the newly tapped energy source could have a $5.5 billion impact on Arkansas by the end of 2008.

Cleburne County Judge Claude Dill says business at the county courthouse, where mineral rights transactions are corded, had been so brisk that clerks had to bring in extra tables. Dill himself negotiated a five-year lease on his 60 acres. Leases cover 4,000 square miles across north-central Arkansas, an area just smaller than the 5,000-square-mile Barnett Shale field in northern Texas, which produced 1.2 billion cubic feet of gas per day last year.

A gas transmission company plans a pipeline across Arkansas that would carry 1.1 billion cubic feet daily, but developers won’t make predictions about the Fayetteville Shale. Houston-based Southwestern Energy Co. did not discover the Fayetteville Shale nor invent the technology to shatter its hold on a buried treasure, but it and its Arkansas subsidiary, SEECO Inc., discovered that it held commercial potential like the Barnett.

Also important, Southwestern Energy was willing to place a bet – up to $700 million by the end of last year and another $900 million in 2007 – that new “frac treatment” technology used in the Barnett could also be used here.

“We ‘discovered’ an idea,” says Harold M. Korell, Southwestern Energy’s chairman, president and chief executive officer. “But until we started drilling wells, we didn’t know it would produce gas. I was very excited in 2002 as the pieces were coming together.”

That year, SEECO was a relatively small company, with its principal area of operation in the Arkoma Basin of Arkansas and Oklahoma. For 60 years, the company had been exploring and producing gas from conventional sources – porous rock thousands of feet underground. Gathering gas from unconventional sources like shale was new to the industry.

For Southwestern Energy, the Arkoma Basin represented about half the company’s gas reserves – “our bread and butter,” says John D. Thaeler, a petroleum geologist and SEECO senior vice president.

As SEECO drilled in the tighter Wedington sandstones of the Arkoma Basin, the company came across some unexpected findings. After analyzing data from 21 wells, Thaeler and his team couldn’t explain the numbers.

“We estimated it should contain about 2.2 billion cubic feet (of natural gas). But when we looked at the well performance, we realized those 21 completions were going to produce upward of 17.3 billion cubic feet,” Thaeler says. “What it meant to us is that we didn’t understand as well as we thought we did where the gas was coming from.”

At a brainstorming session at SEECO’s Fayetteville offices, the lights went on. Thaeler and his team realized the gas in the 30-50 foot thick sandstone could be coming from the surrounding Fayetteville Shale and wondered if the formation could be another Barnett.

The team poured over Barnett data and studied drilling records and maps. Samples of the Fayetteville Shale were sent to the same company that had analyzed Barnett, but the team didn’t say where the rock came from. In late summer 2002, Thaeler recalls getting the test results back. “Wow! This looks an awful lot like the Barnett,” analysts told him. “Where is it?”

The response was encouraging, but the SEECO crew knew the Barnett was hundreds of feet thick while the Fayetteville Shale in the basin was not. Over the next year, the company quietly embarked on a campaign to acquire surface and mineral rights beyond the Arkoma Basin.

The company used out-of-state land brokers unknown to locals at county courthouses and abstract offices, putting them up in motels off-the-beaten path or near SEECO’s Fayetteville offices. The brokers, sworn to secrecy, negotiated the deals and bought the rights for the company while the company remained anonymous.

By the end of 2003, Southwestern Energy had spent about $11 million and acquired the rights to about 3,300 acres. With more drilling, the company learned the thicker shale outside the Arkoma Basin was the quality needed for commercial production.

“I see them (Southwestern Energy) as very smart from an entrepreneurial standpoint and to a certain extent from a scientific standpoint,” says Ratchford, the state geology commission’s fossil fuel resources expert. “The other energy companies were basically asleep at the wheel.”

In the fall of 2004, Thaeler was in the field at a well in Jerusalem, 72 miles northwest of Little Rock, when the company used the new technology to tap natural gas from shale. The rock was fractured and the gas was released. Above ground, a small pilot light flared. Thaeler couldn’t get through by cell phone to Texas headquarters so he hurried off to make the call.

“Houston, we have gas!” he announced.

“There was no Wedington sand out there so we knew the Fayetteville Shale had the potential to be productive,” Thaeler recalls. “Naturally, we started leasing like crazy.”

Southwestern’s public announcement of the well set off a frenzy. Although not as large as the Barnett, the Fayetteville Shale held great promise. Dill’s deal gives him a minimum of $100 an acre if no gas is produced, and 12.5 percent royalties if drillers hit gas.

Over 21/2 years, about 2.5 million acres were leased. Since then, some 180 wells at an average cost of $2.2 million each have been completed, and Texas Gas Transmission plans to build a 167-mile pipeline to carry 1.1 billion cubic feet of gas a day.

Southwestern plans to drill 400-450 wells in 2007 and may eventually have 8,000 operating in the Fayetteville Shale. In all, the company estimates its leases hold 11 trillion cubic feet of natural gas for production. Arkansas has not traditionally been a major gas producer.

Meanwhile, the much larger Chesapeake Energy Corp., based in Oklahoma City, plans to drill 50-75 wells in 2007 and open a field office in White County. Schlumberger, a world leader in servicing oil and gas companies, is building a 31,000-square-foot facility in Conway, where Southwestern also has opened up an office and formed DeSoto Drilling Inc.

According to the Arkansas Oil and Gas Commission, mineral rights owners could receive as much as $3,750 a month in royalties in the first year of production on 160 acres. Also, a University of Arkansas study, partially funded by Southwestern Energy, predicts the shale play from 2005-2008 will mean an additional 9,683 jobs in Arkansas and $358 million in taxes for state and local governments. The $5.5 billion impact by the end of next year, forecast by the study, includes total labor income, property income, state and local taxes, and the purchase of goods and services.

Still, for the Fayetteville Shale venture to work, gas prices and demand will have to remain high and drilling costs and skilled workers will have to be within reach. Production throughout the play will have to be good. And new costly transmission lines will have to be built in time to take advantage of all these variables.
“It’s one thing going out and punching a hole in the ground, saying ‘I’ve got gas,”‘ Ratchford says. “It’s another thing, more difficult, to get a delivery system in place to where you have a gathering system from the well head to a gas transmission line and bringing that resource all the way into a person’s home or business.”
But Thaeler says those are the risks of the oil and gas business.

Fayetteville Shale: Quick Facts

The Fayetteville Shale in Arkansas is a recently tapped unconventional source of natural gas. The tight, finely grained rock formation, 300 million years old, ranges in thickness from 50 to 550 feet and in depth from 1,500 to 6,500 feet.

The “sweet spot,” where geologists believe the rock holds the greatest reserve, is in five central Arkansas counties: Cleburne, Conway, Faulkner, Van Buren and White.

A study by the University of Arkansas at Fayetteville, funded by Southwestern Energy Co., said the economic impact from 2005-2008 on the state would be $5.5 billion, 9,683 additional jobs, and $358 million more in taxes for state and local governments.

Houston-based Southwestern Energy began exploration in 2002. The company holds mineral rights on about 887,000 acres and estimates those properties could produce 11 trillion cubic feet of natural gas. Southwestern says it may drill as many as 8,000 wells.

Other companies in the shale play and their approximate acreage include:

• Chesapeake Energy, 1 million acres.
• Hallwood Energy, 480,000 acres.
• Maverick Oil & Gas, 125,000 acres.
• Shell Exploration & Production Co., 70,000 acres.

By the end of 2006, about 180 wells were completed in the Fayetteville Shale.
Natural gas production in the United States amounts to about 18-19 trillion cubic feet a year. Arkansas production, before the tapping of the shale, amounted to about 1 percent of the total.

Shale formations in the Black Warrior Basin and Appalachian Thrust Belt of Alabama present a diversity of opportunities for the exploration and development of natural gas. Prospective formations range in age from Cambrian through Carboniferous; they include the Middle Cambrian Conasauga Formation, a variety of Devonian shale units, and the Mississippian Neal (Floyd) Shale. Each prospective shale unit poses different challenges for development. In the Appalachian Thrust Belt, structural complexity is the principal challenge that must be met.

For example, giant deformed shale masses in the Conasauga Formation contain major resources, but best practices for drilling and completion remain to be determined. A significant gas show in the Devonian section within the backlimb of a large ramp anticline are also promising, and fracturing associated with parasitic folds may enhance permeability. Organic-rich Chattanooga (Devonian) and Neal shale units in the Black Warrior Basin are enveloped by brittle carbonate formations and thus appear analogous to the prolific Barnett Shale of the Fort Worth Basin. Understanding the interplay among stratigraphic architecture, organic content, and thermal maturity are important keys to understanding the development potential of the Chattanooga Shale and the Neal shale.

The Upper Cretaceous Gammon Shale has served as both source bed and reservoir rock for Diagenesis and Methane Generation in Upper Cretaceous Gammon Shale, Northern Great Plains, United States In the northern Great Plains, isotopically light methane is entrapped at shallow depths in marine rocks of Late Cretaceous age. Products of early diagenetic decomposition of organic matter in the Gammon Shale support the view that the gas is biogenic and formed at shallow depths early in the burial history of the sediments. This interpretation implies widespread gas occurrence and is consistent with a larger gas resource figure than alternative interpretations suggest.

The Gammon Shale was deposited offshore during a major regression of the Late Cretaceous epeiric sea. The sediment-water interface was oxygenated, and soft-bodied organisms burrowed the silt-clay sediment. Organic matter was sufficiently abundant for oxygen depletion at shallow depths. Bacterial sulfate reduction occurred quickly and resulted in the formation of framboids and octahedra of pyrite. Abundant concretions and discrete crystals of siderite began forming within tens of meters of the sediment surface. Interstitial waters became saturated with methane, and a free gas phase, held in siltstone layers by capillary forces, inhibited silicate diagenesis. Methane generation probably continued to burial depths of hundreds of meters. At the maximum burial depth (1,200 to 1,500 m), int rstitial waters contained their maximum dissolved methane, and silt layers still contained free gas. Cenozoic uplift and erosion permitted gas exsolution. Exsolved gas combined with free methane already in the reservoirs to form the gas being currently explored and extracted.

While oil shale is found in many places worldwide, by far the largest deposits in the world are found in the United States in the Green River Formation, which covers portions of Colorado, Utah, and Wyoming. Estimates of the oil resource in place within the Green River Formation range from 1.2 to 1.8 trillion barrels. Not all resources in place are recoverable; however, even a moderate estimate of 800 billion barrels of recoverable oil from oil shale in the Green River Formation is three times greater than the proven oil reserves of Saudi Arabia. Present U.S. demand for petroleum products is about 20 million barrels per day. If oil shale could be used to meet a quarter of that demand, the estimated 800 billion barrels of recoverable oil from the Green River Formation would last for more than 400 years.

More than 70% of the total oil shale acreage in the Green River Formation, including the richest and thickest oil shale deposits, is under federally owned and managed lands. Thus, the federal government directly controls access to the most commercially attractive portions of the oil shale resource base.

The Haynesville Shale, is a black, organic-rich shale of Upper Jurassic age that underlies much of the Gulf Coast area of the United States. “Haynesville Shale” is a drillers term for shale rock units within the Haynesville Formation.

The Haynesville Formation is underlain by the Smackover Formation and overlain by rocks of the Cotton Valley Group. It was deposited about 150 million years ago in a shallow offshore environment.

Geologists have long known that the Haynesville Formation contained natural gas. However, because of its low permeability the Haynesville was originally considered to be a gas source rock rather than a gas reservoir.

Today, natural gas production from the Haynesville occurs from rocks about two miles beneath northwestern Louisiana, southwestern Arkansas and eastern Texas. The most productive areas have been Caddo, Bienville, Bossier, DeSoto, Red River and Webster Parishes of Louisiana plus adjacent areas in southwest Arkansas and east Texas.

In 1998, Burlington Resources (BR) initiated a study to characterize the Lewis Shale (Lewis) gas potential in the San Juan Basin (SJB) and optimize exploitation. Historically, most SJB production has been from naturally fractured, low permeability, Cretaceous sandstones (Dakota, Mesaverde, and Pictured Cliffs)or from the prolific Fruitland Coal. In the past, the Lewis, which lies between the Mesaverde and Pictured Cliffs Formations, was completed in only the few wells where large Lewis flow rates were encountered while air-drilling for deeper targets. However, the Lewis lies behind pipe in thousands of existing wells across the SJB. In a large number of these wells and in new Mesaverde/Dakota wells, the Lewis can be completed. The BR program includes performing geological, petrophysical, reservoir, stimulation, and production data analysis. From this data, reservoir characterization, completion optimization, and forecasting models were developed that indicate commercial Lewis potential through much of the SJB in both new and existing wells. Furthermore, the Lewis is more accurately characterized as a sandy siltstone, rather than a true shale such as the Devonian or Antrim Shale.

Introduction

The San Juan Basin (SJB), in northwestern New Mexico and southwestern Colorado, is the largest producer of natural gas in the Rocky Mountain province of the United States.1 As the basin matures, “unconventional”horizons, such as the Lewis Shale, have drawn more interest and such reservoirs may significantly increase ultimate recovery from the basin. Since 1998, the Lewis Shale (Lewis) has been the focus of an extensive evaluation by Burlington Resources (BR). Stratigraphically, the Lewis is composed of shale, siltstone, and a smaller percentage of sandstone. Most of the Lewis can be classified as sandy siltstone. The Lewis lies above the Mesaverde Formation and below the Pictured Cliffs Formation, both prolific gas producers. The study area and most Lewis completion activity trends along the northwest-southeast Mesaverde production fairway at an average depth of 4,500 ft.

Current Status of the San Juan Basin

Since the mid-1980’s, development of the prolific Fruitland Coal (FTC)has dominated activity within the SJB.2 Production from the FTC reached a plateau at approximately 2.8 Bscf/D (65% of the total 4.3 Bscf/D produced from the SJB) and has begun to decline.3 Conventional gas (non-coal) presently accounts for another 1.5 Bscf/D (35%) produced from the basin. The focus of SJB activity is returning to reservoirs such as Dakota (DK), Mesaverde (MV), and Pictured Cliffs (PC)sandstones, as well as to the Mancos and Lewis shale intervals which lie between these more conventional reservoirs. is a geologic cross section of the SJB and shows the stratigraphic relationships of these formations.

Overview

BR is a dominant player in the SJB, operating over 6,500 of the total 18,255 active wells. The Lewis is behind pipe in 3,500 BR operated wells. The Lewis was rarely completed in the SJB from 1950-1990, when the only documented production was from 16 wells that encountered extensive Lewis natural fracture systems while drilling for deeper MV and DK objectives.4 In 1991, BR began adding the Lewis to existing MV completions in specific areas of the basin. Through 1997, approximately 101 Lewis completions had been made in existing and new wells. However, the Lewis was always commingled with MV and/or DK. As such, it was difficult to quantify the incremental production rates, reserves, and corresponding value of the Lewis.

In an abstract presented to the Utah Geological surey recently by Michael D. Laine, Thomas C. Chidsey, Jr and Craig D. Morgan it was proposed that there is tremendous untapped potential in the shales Utah. The Mississippian, Manning Canyon shale, Pennsylvanian.

Hermosa group (Paradox formation), and Cretaceous Mancos shale, which included the Prairie Canyon, Tununk and Lower Blue Gate members. These shales which stretch from north-central to Southeastern Utah are beginning to see some drilling activity. These shale beds have all the elements needed to be highly productive. They are thick, deep enough to produce dry gas and contain high concentrations of organic matter along with high fracturing to make gas recoverable.

“The Manning Canyon Shale is mainly claystone with interbeds of limestone, sandstone, siltstone, and mudstone, and has a maximum thickness of 2000 ft. Total organic carbon (TOC) varies from 1% to greater than 8% with type III (?) kerogen. In north-central Utah, the Manning Canyon was deeply buried by sediments in the Pennsylvanian-Permian-aged Oquirrh basin and is therefore likely very thermally mature.

Cyclic shale units in the Paradox Formation consist of thinly interbedded, black, organic-rich marine shale; dolomitic siltstone; dolomite; and anhydrite. They generally range in thickness between 25 and 50 ft. These units contain TOC as high as 15% with type III and mixed type II-III kerogen, are naturally fractured (usually on the crest of anticlinal closures), and are typically often overpressured.”

In an effort to improve oil production at Elk Hills, located in Kern County, California, successful new methods for acidizing both horizontal and vertical Monterey Shale wells were developed. During 1999 and 2000, 21 horizontal Shale wells were drilled with unacceptable production results, even though the petrophysical evaluation indicated the wells should have great flow potential.

The uncemented, slotted liners prevented the use of conventional stimulation techniques. Instead, the acid blend, placement, recovery, and flowback techniques using coiled tubing evolved and improved. Workover equipment optimization and utilization increased and time to market and operating expenses decreased. The results from acidizing horizontal wells increased oil production up to nine-fold.

Due to the successful large-volume hydrofluoric (HF) acid jobs on the horizontal Shale wells, many old vertical Shale wells were acidized using the same technique, increasing average well production by 110 barrels of oil per day (BOPD) and more than 500 MSCF/D. As a result of the diligent, combined team efforts of the operations personnel and the pumping service contractor, the total acidizing costs were reduced by U.S. $2,300,000. These costs were reduced through blending acid in the field, field-testing the oil for additives, lowering spent acid disposal costs, and mixing acid on the fly.

Field History

NA Shale drilling began in the fall of 1999 with two horizontal wells placed in the N Shale and two horizontal wells placed in the A Shale. The wells were re-drills of existing vertical wells with 7-in. production casing cemented in place. The wells were kicked off above the zone of interest with build rates above 20°/100 ft using a 6 1/8-in. bit. The laterals were drilled with high-viscosity drill-in fluids (DIF), with 6% KCl water as a base fluid and a cost of approximately U.S. $60 per barrel. Calcium carbonate (CC) was used for fluid-loss additive (FLA). The expectation was that the wells would flow to the tank batteries at economical rates. Therefore, 3 1/2-in. slotted liners were run to total depth. External casing packers were used only to isolate fluid above the zone of interest.

One mud company suggested that only a few gallons per foot of HCl acid would be necessary to dissolve the CC FLA. A second mud company stated that only a 50-psi differential into the wellbore would be necessary to recover the CC FLA. The first well was initially acidized with 2.5 gal of 17% HCl per foot of net pay (gpnf) through coiled tubing (CT). Nitrogen and CT were used to recover the spent acid.

The first A Shale well would not flow. A 11/2-in. rod pump was initially installed, but was increased to a 2-in. plunger diameter after a fluid level shot indicated 4,288 ft of fluid above the pump. The relatively high build rates and small liner size prevented the rod pump from being set as deep as necessary to maximize the pressure drawdown. Production, however, increased from 9 BOPD + 69 MSCF/D (1 1/2-in. pump) to 303 BOPD + 1,650 MSCF/D (2-in. pump) in two months.

In an attempt to increase production, the acid volume was increased to 28.1 gpnf of 17% HCl through the next three wells (two N Shales and one A Shale). The last well was foamed with nitrogen for diversion. Nitrogen and CT were used on all three wells to recover the spent acid. Beam pumping units (BPU) were installed on all three wells within two months of their initial completions to reduce the producing bottomhole pressure (BHP) and increase production rates. The third well was reacidized with 11.0 gpnf of 13.5-1.5% acid (foamed), but oil production decreased from 105 BOPD + 253 MSCF/D to 26 BOPD + 382 MSCF/D after being killed with produced water. The wells initially averaged 107 BOPD + 708 MSCF/D, declining to 33 BOPD + 533 MSCF/D in two months.

Horizontal redrilling of existing vertical wells continued into 2000 with two more N Shale laterals and four more A Shale laterals using DIF for mud. With the same completion technique, the six wells initially averaged 244 BOPD + 628 MSCF/D, declining to 70 BOPD + 311 MSCF/D in two months.

The New Albany Shale is composed of brownish-black carbon-rich shale, greenish-gray shale, and minor amounts of dolomite and dolomitic quartz sandstone (Lineback, 1968, 1970). As recognized by Lineback, the formation consists of five members in southeastern Indiana. In ascending order they are: (1) the Blocher Member, brownish-black to grayish-black, slightly calcareous pyritic shale; (2) the Selmier Member, greenish-gray to olive-gray shale; (3) the Morgan Trail Member, brownish-black to olive-black fissile siliceous pyritic shale; (4) the Camp Run Member, greenish-gray to olive-gray shale interbedded with brownish-black shale and; (5) the Clegg Creek Member, brownish-black to black pyritic shale rich in organic matter. A sixth member of the New Albany Shale, the Ellsworth Member, was recognized by Lineback (1968, 1970) in the northern part of the Illinois Basin in Indiana. There the Ellsworth Member consists of two parts: a lower part of interbedded brownish-black shale and greenish-gray shale and an upper part of greenish-gray shale. In west-central and southwestern Indiana greenish-gray shale occupying the same position as the greenish-gray shale in the upper part of the Ellsworth has been included in the Ellsworth Member by later workers (Bassett and Hasenmueller, 1980; Hasenmueller and Bassett, 1981). The Blocher, Selmier, and Ellsworth Members have been recognized and mapped in the subsurface (Lineback, 1970; Hasenmueller and Bassett, 1980a, 1980b; and Bassett and Hasenmueller, 1980). The Selmier, Morgan Trail, and Camp Run Members and part of the Clegg Creek Member are equivalent to the Blackiston Formation of Campbell (1946). The Sanderson Formation (which includes the Falling Run Bed as recognized here), the Underwood and Henryville Formations, and the Jacobs Chapel Shale of Campbell (1946) are now included in the upper part of the Clegg Creek Member.

The New Albany Shale is widespread west and southwest of the Kankakee and Cincinnati Arches in Indiana and paraconformably overlies the Muscatatuck Group (Middle Devonian). The shale is overlain by the Rockford Limestone throughout much of the Illinois Basin. In areas from which the Rockford is absent the shale is overlain by the New Providence Shale of the Borden Group. The New Albany crops out in southeastern and north-central Indiana and attains a maximum thickness of 337 feet f 103 m) in Posey County and a minimum thickness of 85 feet (26 m) in Harrison County (Hasenmueller and Bassett, 1981).

The New Albany Shale is mostly Late Devonian in age and includes conodonts indicative of the doI through doVI divisions of the German Devonian standard. The upper 2 to 6 feet (0 6 to 1.8 m) of the New Albany in the southern Indiana outcrop area is Mississippian in age and includes conodonts indicative of the cuI division of the German standard and the lower part of the cuII division. A conodont fauna corresponding to that in the Siphonodella sulcata Assemblage Zone in the Hannibal Shale of the upper Mississippi Valley has been recognized in the Underwood Bed of the New Albany Shale (Lineback, 1970).

The New Albany Shale is a widely recognized unit and is in large part correlative with the Antrim Shale of northern Indiana and Michigan, the Ohio Shale of Ohio and eastern Kentucky, the New Albany Shale of Kentucky, the New Albany Group of Illinois, and the Chattanooga Shale of Tennessee and south-central Kentucky. Parts of the New Albany Shale are also equivalent to the Sunbury Shale of Michigan, Ohio, northern Indiana, and eastern Kentucky; the Olentangy Shale, the Bedford Shale, and the Berea Sandstone of Ohio and eastern Kentucky, and the Ellsworth Shale of Michigan and northern Indiana. (See Huddle, 1934; Campbell, 1946; Lineback, 1970; and Hasenmueller and Bassett, 1981.)

North American unconventional-oil plays have gained increased attention as results improve. One of the plays explorers are closely monitoring is the Cretaceous Niobrara shale in the Rocky Mountain region.

People have long known that the Niobrara is thick, rich in organics and thermally mature. Oil has flowed from the Niobrara since the dawn of the industry: Florence Field, near Canon City, Colorado, was discovered in 1876 near an oil seep. Florence produces from fractured Pierre shale, part of the Niobrara formation. Oil pioneers also found the Niobrara productive at Salt Creek, Teapot Dome, Tow Creek and Rangely fields.

Today companies are chasing the Niobrara with new fervor. Lots of buzz is surrounding EOG Resources’ Jake well, a horizontal Niobrara discovery in Colorado’s Weld County, in the northern Denver-Julesburg Basin. According to state records, the well, in Section 1-11n-63w, flowed an average 1,750 bbl. of oil and 360,000 cu. ft. of gas per day for its first eight days on production in October 2009. The next month, it made an average of 680 bbl. per day for 30 days.

In addition to the D-J Basin, active exploration is ongoing in the southern Powder River Basin in Wyoming, and in Colorado’s North Park, Sand Wash, Piceance and Raton basins.

There are plenty of places to prospect for Niobrara, as the shale occurs across a vast, tectonically active area. It can be anywhere from 150 to 1,500 feet thick, and its TOC ranges up to around 5%. It contains Type II kerogen. Additionally, the Niobrara contains a high proportion of carbonates, including brittle, calcareous chalk benches. These appear to enhance its porosity and its ability to be fractured, by both natural and mechanical processes. And the tremendous tectonic legacy of the central Rockies region means that natural fracturing can be extensive.

Finally, the thermal maturity of the Niobrara varies, so it can yield either oil or gas or both, depending on local conditions. The shallow, biogenic Niobrara gas play in the eastern Colorado and western Kansas portion of the D-J illustrates how rapidly reservoir conditions can change within this enigmatic and fascinating formation.

We’re sure to hear much more about the Niobrara in months to come, as results are posted from a number of significant tests across several play types and basins.

Oil shale exploration is heating up in Texas’ Palo-Duro while robust gas prices are benefiting producers in Midwestern legacy fields:

Palo Duro Gas Shale Project PDF

http://www.lib.utexas.edu/books/landscapes/publications/txu-oclc-7013582/txu-oclc-7013582.pdf

The Woodford Shale is located in Oklahoma. The first production of the Woodford Shale occurred in 1934 in Pottawatomie County. Currently over 130 wells have been drilled in the Woodford Shale. Like in most shale gas plays, Woodford wells were first vertically drilled, then as technology advanced, horizontal wells have become the norm.

Significant producers within the Woodford Shale are: Newfield Exploration, Devon Energy, Chesapeake Energy, Cimarex Energy, Antero Resources, St. Mary Land and Exploration, XTO Energy, Petroquest Energy, Continental Resources, and Range Resources.

The Woodford Shale is located in the following geologic basins of Oklahoma: Arkoma Basin, Ardmore Basin, Anadarko Shelf, Arbuckle Uplift, and the Ozark Uplift. The shale is found at depths from 7,500 to 8,500 feet, and is generally 50 to 300 feet thick.

The Woodford Shale is located in the following counties of Oklahoma:

• Hughes County OK
• Coal County OK
• Pittsburg County OK
• McIntosh County OK
• Carter County OK
• Johnston County OK
• Marshall County OK
• Bryan County OK
• Canadian County OK
• Garvin County OK
• Wagoner County OK
• Mayes County OK

Country Overview

The Federal Republic of Nigeria is located in West Africa. It is bordered by the Republic of Benin in the west, Chad and Cameroon in the east, and Niger in the north. Its coast lies on the Gulf of Guinea and part of the Atlantic Ocean in the south. The people of Nigeria have an extensive history, and archaeological evidence demonstrates that human habitation in the country dates back to at least 9000 BC.
Nigeria is the most densely populated country in Africa and the 9th most densely populated country in the world. It also has one of the fastest growing economies in the world.
Petroleum plays a large role in the Nigerian economy, accounting for 40% of the GDP. It is the 12th largest oil producer in the world, the 8th largest exporter and has the 10th largest proven reserves. The country is also a founding member of OPEC.

Natural resources in the country include iron ore, limestone, lead and zinc. Agricultural products include groundnuts, palm oil, cocoa, coconut, citrus fruits, maize and sugar cane. Nigeria also has a booming leather and textile industry.

Licence Areas

Cornerstone International Industries, Inc. began operations in Nigeria in 2010 by signing two Production Sharing Contracts (PSCs) with the Nigerian National Petroleum Corporation (NNPC). Our average annual production will be 8,800 barrels per day (bbl/d). Since this acquisition, Cornerstone International Industries, Inc. will increase its growth by acquiring oil properties deemed by others to have limited remaining production potential and using its strong in-house technical and operational expertise to grow reserves and production in a cost effective manner.

In Nigeria, Cornerstone International Industries, Inc.’s producing assets will include 11 field complexes with around 60 production wells in concession OML123, 2 fields with 20 producing wells in concession OML 124 and 2 fields with 14 production wells in concession OML126. On-going progress with Field Development Planning is expected to result in a significant increase in production.