Haynesville Shale Gas Play, North Louisiana and East Texas

Here is some information on a newly economic shale gas play. It warrants watching closely.
Peter
source

Haynesville Shale: News, Map, Videos, Lease and Royalty Information
Haynesville Shale
Haynesville Shale Orientation:

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.

Quote: Louisiana DOE

“This is an extraordinary time for Louisiana, particularly in north Louisiana, where we are experiencing something akin to a modern day gold rush due to excitement about the Haynesville Shale discovery. To put the magnitude of this sale into perspective: This month’s lease sale surpassed by more than double the bonus collections for the previous 11 months of FY 2007-08 combined, almost entirely because of activity in north Louisiana... 25 of the 38 leases awarded were from Caddo, Red River and Bienville parishes, totaling approximately $34 million in cash payments, and the average bonus per acre for these leases was over $13,400 per acre, while more typical prices in the past for north Louisiana have been around $400 per acre." (source)

Quote: Chesapeake Energy

“Based on its geoscientific, petrophysical and engineering research during the past two years and the results of three horizontal and four vertical wells it has drilled, Chesapeake believes the Haynesville Shale play could potentially have a larger impact on the company than any other play in which it has participated to date." (source)

News Reports
Haynesville Shale News: ShaleBlog.com, a blog tracking news about the Haynesville Shale.

Other Shale Resources
Marcellus Shale: Very similar to the Haynesville. The Marcellus Shale is a new gas resource of the Appalachian Basin.

Barnett Shale: Here's where it all started. The Barnett Shale of Texas was where the hydrofrac and horizontal drilling techniques were first mastered for tight shale reservoirs.

Fayetteville Shale: Another gas shale formation producing in northern Arkansas..

Oil and Gas Jobs

Oil and Gas Job Opportunties: Multiple shale plays happening across the United States have triggered an enormous demand for skilled workers and trainees.

Haynesville Stratigraphy

Gas production is mainly in the Haynesville Formation. However, some gas is also produced from the Cotton Valley Group and Smackover Formation.

Government & Regulatory
Questions and Answers About the Haynesville Shale: Answers from the Shreveport Mayor's Office about leases, landmen, signing bonus, royalties and drilling activities.

Louisiana Office of Mineral Resources: Monthly lease information and access to mineral resource records. Historical oil and gas production data. Historical lease and royalty data.

Louisiana Department of Natural Resources: Department "news" page.

Haynesville Economics
Economic Impact: Local officials of Shreveport get in touch with counterparts in Fort Worth to find out what they learned from their Barnett Shale experience.

Chesapeake Rig Tour: KSLA video showing a drill rig with details on the horizontal well technique.

Waiting to Sign: Property owners are uniting and holding out for the best deal possible. Their supergroup represents 6000 owners. They have an offer of $27,200 per acre signing bonus plus 26% royalty.

Advice for Property Owners: There are many sources of advice on leasing a natural gas property. This video explores the options that landowners have for advice.

Gas Lease and Royalty
Gas Lease Forum: Knowledge is power when you receive an offer to lease your land. Find out what others are being offered and share advice at this forum.

Natural Gas Lease Database: See how much was paid as a signing bonus to numerous landowners in most counties. Includes transaction date, signing bonus per acre, term of lease, royalty rate and number of acres. Share your information anonymously to help others.

National Association of Royalty Owners: The only national organization representing, solely and without compromise, oil and gas royalty owners interests.

Wellhead Price of Natural Gas: Current and historical price data from the US Energy Information Administration.

Gas Lease Blog: Information on natural gas development and leases.

Glossary of Natural Gas Leasing Terms: Look up definitions to understand your lease or whatever you are reading.

Gas Leasing FAQ's: Some of the best questions answered right here.

Geology News
Daily news for geology and earth science. Delivered to you free by RSS or email.

Haynesville Shale Map
Drilling activity in the Haynesville Shale has been most active in Caddo, Bossier, DeSoto and Webster Parishes, Louisiana plus adjacent areas in southwest Arkansas and east Texas. The Shreveport Times has a well location map for Louisiana.

Estimate Your Royalty
Natural Gas Royalty Estimator: Enter data from your lease agreement and make a few assumptions. Unoffical estimates of your annual royalty payments.

Wellhead Price History
The wellhead price of natural gas changes in response to market and political forces.

Haynesville Drilling
The productive potential of the Haynesville Shale was not fully realized until horizontal drilling and hydrofracing technologies were demonstrated in other unconventional shale reservoirs. The hydrofracing process helps liberate gas from the shale and horizontal drilling allows a single well to drain a much larger volume of rock than a traditional vertical well.

Unconventional Gas Technology:A "white paper" by Schlumberger, the well service company. Explains how hydraulic fracturing is used to stimulate production in tight gas shale reservoirs. (large .pdf file)

How Much Water is Needed? Frac jobs require a lot of water. Here's some experience on water needs from the Barnett Shale of Texas..

Interactive Drill Rig: Learn about drill rigs and drilling with this interactive presentation by Dale Energy.

Night-Time Satellite Photos Of Earth

Night-time energy usage around the world. Who and where are the people burning the "midnight oil"? What does this say about geography, industry, population, and civilization?
Fascinating. It is a big world.
Peter
(source)

"Satellite Photo of Earth at Night"Shown below is a famous NASA image that is often called a "satellite photo of earth at night". It isn't really a "photo". Instead it is an image that was compiled using data from the Defense Meteorological Satellite Program. It is a map of the location of permanent lights on Earth's surface. Each white dot on the map represents the light of a city. The entire image is show below and we follow it with enlarged continents and commentary.
This map shows the geographic distribution of cities. It clearly shows that cities are concentrated in Europe, the eastern United States, Japan, China and India. It is a better map for showing the geography of night time electricity consumption for outdoor lighting than it is for showing the geography of population. For example: the eastern United States is very bright but the more densely populated areas of China and India are not nearly as bright in this image. NASA Image.

This map shows the geographic distribution of night time lights in the United States, Canada, Mexico and the Caribbean. Strong lights occur in a strand that includes Washington, DC, Philadelphia, New Jersey, New York City and Boston. Most of the large cities of Canada are located within a couple hundred miles of the United States border. Chicago stands out on the shoreline of Lake Michigan and other major cities in the central states are collected by a network of highways. On the west coast, Seattle, San Francisco, Los Angeles and San Diego stand out. The coastlines of Florida and Puerto Rico are lined with bright cities. Finally, the cities of Hawaii and oil facilities of the north Alaska coast are also "visible from space". NASA Image.

Western Europe is aglow with night lights. This image clearly shows that the cities of Europe are along the coasts. The Mediterranean coasts of Italy, France and Spain are a solid line of light as is the southern shorelines of the Black and Caspian Seas. The Sahara of northern Africa and the jungles of south-central Africa are largely void of illuminated cities. One of the most striking features on this image is the high concentration of cities on the Nile River, downstream from the Aswan Dam. NASA Image.

The cities of South America are mainly concentrated on the southwestward-facing Atlantic coast, along the Pacific coast and northern Colombia and Venezuela. Large areas of the Amazon Basin are without bright cities and some of the night lights there might actually be the fires if deforestation and agricultural burning. NASA Image.

Japan stands out on this satellite view of Asia at night, along with the west coast of Taiwan, South Korea, Hong Kong and Bangkok. The route of the Trans-Siberian Railroad can be seen as a light line across the otherwise dark area of northern Russia. High city densities in eastern China, Indonesia, India and the eastern coast of Australia can clearly be seen. NASA Image

Marcellus Shale And Natural Gas Production In The NE United States

The successful production of large volumes of natural gas from shale rocks has enormously positive economic consequences for America, and indeed, the world. This is a relatively recent development of extreme importance. For an idea of how important natural gas is, consider exactly what it is and its many uses:

Natural gas is a gaseous fossil fuel consisting primarily of methane but including significant quantities of ethane, propane, butane, and pentane—heavier hydrocarbons removed prior to use as a consumer fuel —as well as carbon dioxide, nitrogen, helium and hydrogen sulfide.[1] It is found in oil fields (associated) either dissolved or isolated in natural gas fields (non-associated), and in coal beds (as coalbed methane).

This so-called "Shale Gas" and the Marcellus Shale development warrants close attention.
Peter
(source)

Marcellus Shale - Appalachian Basin Natural Gas Play
New research results surprise everyone on the potential of this well-known Devonian black shale.
Super Giant Field in the Appalachians?A few years ago every geologist involved in Appalachian Basin oil and gas knew about the Devonian black shale called the Marcellus. Its black color made it easy to spot in the field and its slightly radioactive signature made it a very easy pick on a geophysical well log. However, very few of these geologists were excited about the Marcellus Shale as a major source of natural gas. Wells drilled through it produced some gas but rarely in enormous quantity. Few if any in the natural gas industry suspected that the Marcellus might soon be a major contributor to the natural gas supply of the United States - large enough to be spoken of as a "super giant" gas field.

Early Marcellus Estimates by USGSAs recently as 2002 the United States Geological Survey in its Assessment of Undiscovered Oil and Gas Resources of the Appalachian Basin Province, calculated that the Marcellus Shale contained an estimated undiscovered resource of about 1.9 trillion cubic feet of gas. [1] That's a lot of gas but spread over the enormous geographic extent of the Marcellus it was not that much per acre.

The First Hints of Big Production

Range Resources - Appalachia, LLC may have started the Marcellus Shale gas play. In 2003 they drilled a Marcellus well in Washington County, Pennsylvania and found a promising flow of natural gas [2]. They experimented with drilling and hydraulic fracturing methods that worked in the Barnett Shale of Texas. Their first Marcellus gas production from the well began in 2005. Between then and the end of 2007 more than 375 gas wells with suspected Marcellus intent had been permitted in Pennsylvania [2].

Recent Surprise EstimatesIn early 2008, Terry Englander, a geoscience professor at Pennsylvania State University, and Gary Lash, a geology professor at the State University of New York at Fredonia, surprised everyone with estimates that the Marcellus might contain more than 500 trillion cubic feet of natural gas. Using some of the same horizontal drilling and hydraulic fracturing methods that had previously been applied in the Barnett Shale of Texas, perhaps 10% of that gas (50 trillion cubic feet) might be recoverable. That volume of natural gas would be enough to supply the entire United States for about two years and have a wellhead value of about one trillion dollars! [5]

What is the Marcellus Shale?
Marcellus Shale: Videos, News, Maps, Lease & Royalty Information

The Marcellus Shale, also referred to as the Marcellus Formation, is a Middle Devonian-age black, low density, carbonaceous (organic rich) shale that occurs in the subsurface beneath much of Ohio, West Virginia, Pennsylvania and New York. Small areas of Maryland, Kentucky, Tennessee, and Virginia are also underlain by the Marcellus Shale. See the map of the Marcellus Shale above.

How Deep is the Marcellus Shale?

Throughout most of its extent, the Marcellus is nearly a mile or more below the surface. The map at right shows the depth of the Marcellus Shale. These great depths make the Marcellus Formation a very expensive target. Successful wells must yield large volumes of gas to pay for the drilling costs that can easily exceed a million dollars for a traditional vertical well and much more for a horizontal well with hydraulic fracturing. Using the two maps together, some especially interesting areas can be seen. These are where thick Marcellus Shale can be drilled at minimum depths. Although this is a great oversimplification, it correlates with the heavy leasing activity that has occurred in parts of northern Pennsylvania and western New York.

Where is the Highest Production Potential?

Rock units are not homogeneous. The gas in the Marcellus Shale is a result of its contained organic content. Logic therefore suggests that the more organic material there is contained in the rock the greater its ability to yield gas. John Harper of the Pennsylvania Geological Survey suggests that the areas with the greatest production potential are those areas where the net thickness of organic-rich shale within the Marcellus Formation is the greatest. A map showing this distribution for the state of Pennsylvania is shown at right. Northeastern Pennsylvania is where the thick organic-rich shale intervals are located.

Low Yield, Long-Lasting Production

Before 2000, many successful natural gas wells had been completed in the Marcellus. The yields of these wells were often unimpressive upon completion. However, many of these older wells in the Marcellus have a sustained production that decreases slowly over time. Many of them continued to produce gas for several decades. A patient investor might make a profit from these low yield wells with slowly declining production rates. For new wells drilled with the new horizontal drilling and hydraulic fracturing technologies the inital production can be much higher than what was seen in the old wells. Then as production rates decline a well might receive new hydraulic fracturing treatments to boost production. The wells will eventually deplete but the fracturing treatments help to produce a more complete recovery of the natural gas. Because this method has not been applied long-term to wells in the Marcellus there is little production history data.

How Does the Gas Occur in the Rock?

Natural gas occurs within the Marcellus Shale in three ways: 1) within the pore spaces of the shale; 2) within vertical fractures (joints) that break through the shale; and, 3) adsorbed on mineral grains. Most of the recoverable gas is contained in the pore spaces. However, the gas has difficulty escaping through the pore spaces because they are very tiny and poorly connected. Most historic wells in the Marcellus produced gas at a very slow rate because of the low permeability mentioned above. This is typical for a shale. However, the most successful historic wells in the Marcellus share a common characteristic: they intersect numerous fractures. These fractures allow the gas to flow through the rock unit and into the well bore. The fractures intersecting the well also intersect other fractures and those fractures intersect still more fractures. Thus, an extensive fracture network allows one well to drain gas from a very large volume of shale. A single well can recover gas from many acres of surrounding land.

Horizontal Drilling to Penetrate More Fractures

The fractures (also known as "joints") in the Marcellus Shale are vertical. So, a vertical borehole would be expected to intersect very few of them. However, a horizontal well, drilled perpendicular to the most common fracture orientation should intersect a maximum number of fractures. The diagram to the right illustrates the concept of a horizontal well. High yield wells in the Marcellus Shale have been built using the horizontal drilling technique. Some horizontal wells in the Marcellus Shale have initial flows that suggest that they are capable of yielding millions of cubic feet of gas per day, making them some of the most productive gas wells in the eastern United States. Although some experts are very optimistic on the long-term production rates of these wells, it is too early to determine their productive life or long-term yield.

Increase the Number of Fractures

A second method is used to increase the productivity of a well. That is to increase the number of fractures in a well using a technique known as "hydraulic fracturing" or "hydrofracing". This method uses high-pressure water or a gel to induce fractures in the rock surrounding the well bore. Hydrofracing is done by sealing off a portion of the well and injecting water or gel under very high pressure into the isolated portion of the hole. The high pressure fractures the rock and pushes the fractures open. To prevent the fractures from closing when the pressure is reduced several tons of sand or other "propant" is pumped down the well and into the pressurized portion of the hole. When the fracturing occurs millions of sand grains are forced into the fractures. If enough sand grains are trapped in the fracture it will be propped partially open when the pressure is reduced. This provides an improved permeability for the flow of gas to the well.

Economic Significance of the Marcellus Shale Gas Field

The presence of an enormous volume of potentially recoverable gas in the eastern United States has a great economic significance. This will be some of the closest natural gas to the high population areas of New Jersey, New York and New England. This transportation advantage will give Marcellus gas a distinct advantage in the marketplace. Gas produced from the shallower, western portion of the Marcellus extent (see map above) might be transported to cities in the central part of the United States. It should have a positive impact on the stability of natural gas supply of the surrounding region for at least several years if the resource estimate quoted above proves accurate.

Gas Leases & Signing Bonuses

Many landowners are being approached with offers to lease their land. The size of the signing bonuses that have been paid in transactions between informed buyers and informed sellers is directly related to two factors: 1) the level of uncertainty in the mind of the buyer, and 2) the number of other buyers competing to make the purchase. These factors have changed significantly in a very short time. As recently as 2005 there was very little interest in leasing properties for Marcellus Shale gas production. The Marcellus was not considered to be an important gas resource and a technology for tapping it had not been demonstrated. At that time the level of uncertainty in the minds of the buyers was very high and the signing bonuses were a few dollars per acre. When the potential of the Marcellus was first suspected in 2006 a small number of speculators began leasing land - paying risky signing bonuses that were sometimes as high as $100 per acre.

In late 2007 signing bonuses of a few hundred dollars per acre were common. Then, as the technology was demonstrated and publicized signing bonuses began to rise rapidly. By early 2008 several wells with strong production rates were drilled, numerous investors began leasing and the signing bonuses rose from a few hundred dollars per acre up to over $2000 per acre for the most desirable properties. If the results of current and future drilling activity do not match the expectations of companies paying for leases the amounts that they are willing to pay could drop rapidly.

Gas Royalties

Although signing bonuses generate an enormous amount of interest because they are guaranteed income, royalties can be significantly higher. A royalty is a share of a well's income. The customary royalty rate is 12.5 percent of the value of gas produced by a well. Higher royalty rates are sometimes paid by aggressive buyers for highly desirable properties. The royalties paid to eligible property owners from a well yielding over one million cubic feet of natural gas per day can be hundreds of thousands of dollars per year. These royalties are divided by all eligible property owners within a production unit (an area of land that is thought to contribute gas to a producing well - typically 640 acres). The amount paid to each eligible property owner is based upon their ownership share. (Get a gas royalty estimate.) If the Marcellus Shale holds up to the optimistic expectations of some natural gas experts, Pennsylvania, Ohio, New York and West Virginia could temporarily have an enormous boost in income that might be sustained for a few decades.

Natural Gas Drilling Activity

Several companies are actively drilling, leasing or planning activity on Marcellus Shale properties. Range Resources, North Coast Energy Inc., Chesapeake Energy, Chief Oil & Gas LLC, East Resources Inc., Fortuna Energy Inc., Equitable Production Company, Cabot Oil & Gas Corporation, Southwestern Energy Production Company, and Atlas Energy Resources are all involved. Shares of most of these companies are up strongly over the past two years. The Pennsylvania Department of Environmental Protection says that drilling permits are up strongly since 2005 and much of the activity increase can be attributed to wells targeting the Marcellus shale. Some of the new wells appear capable of yielding millions of cubic feet per day and that has companies working hard to acquire leases on desirable properties and complete new wells.

Other Gas Shales in the United States

The events described above are not unique to the northeastern United States or the Marcellus Shale. The horizontal drilling and hydrofracing technologies were perfected for shale reservoirs about four years ago in the Barnett Shale of Texas. The technology was then applied to the nearby Fayetteville Shale of northcentral Arkansas. Then, shortly after the Marcellus activity began, drilling and leasing in the Haynesville Shale of northwestern Louisiana started. These are just two of several unconventional gas plays now happening in the United States.

Shale Gas: A Brief History

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By KATHY SHIRLEY
EXPLORER Correspondent
Tax Break Rekindled Interest
Shale Gas Exciting Again
An Atrium Shale outcrop at the Paxton Quarry in northern Michigan.
Photo courtesy of Gas Research Institute
See related story: Lewis Not Overlooked Anymore
Shale gas production is certainly nothing new in the United States. In fact, the first commercial gas shale well was drilled in New York in the late 1820s – nearly 40 years before Colonel Drake drilled his famous oil well in Pennsylvania.
Still, there’s a new - some might say urgent - sense of excitement when it comes to the role of shale gas production in today’s energy mix, as well as its potential for the coming years.
“Over the next decade we expect the gas industry will continue to expand the shale gas play frontiers as new areas are evaluated and we learn more about the geology of shale gas resources,” said David G. Hill, manager, emerging resources, with the Gas Technology Institute.
Gas shales, he said, are classified as continuous type natural gas plays - accumulations that are pervasive throughout large geographic areas and offer long-lived reservoirs with attractive finding costs.

“The major exploration risk in most shale gas plays is generally not the drilling of a truly dry hole, but rather in not obtaining economically viable gas production rates,” Hill said. “Most shales have very low matrix permeabilities and require the presence of extensive natural fracture systems to sustain commercial gas production rates.”

In shale reservoirs, natural gas is stored three ways:
As free gas within the rock pores.
As adsorbed gas on organic material.
As free gas within the system of natural fractures.
These different storage mechanisms, Hill said, affect the speed and efficiency of gas production.
Modern gas shale production was initially spurred by the Section 29 non-conventional fuels production tax credit, but that tax credit expired in 1992, and operators have continued to expand gas shale programs. Today over 28,000 gas shale wells produce nearly 380 billion cubic feet of gas yearly from five U.S. basins:

Appalachian.
Michigan.
Illinois.
Fort Worth.
San Juan.
In 1998 fractured shale gas reservoirs supplied 1.6 percent, or .3 trillion cubic feet of total U.S. dry natural gas production and contained 2.3 percent or 3.9 trillion cubic feet of total U.S. proved natural gas reserves. Over the past decade shale gas production has increased by a factor of 2.5, growing from 148.6 billion cubic feet of gas in 1989 to 380 billion cubic feet in 1999.
The shale gas resource base in the lower 48 states is significant. According to GTI, gas-in-place resource estimates for the five main gas shale plays total 581 trillion cubic feet of gas, and recoverable resource estimates range from 31 to 76 trillion cubic feet.

These figures are considered conservative since estimates for the Barnett Shale in the Fort Worth Basin and the Lewis Shale (see related story, page 26) are not available.
Hill commented that “each new shale gas play has presented technical challenges that operators have to overcome by identifying and solving shale-specific problems.
“But,” he added, “success in these relatively low-cost plays has sparked a resurgence of industry interest in evaluating the production potential of the shale gas resources present in basins throughout the United States.”

A Stimulating Story
The first shale gas production in the United States came from the Appalachian Basin, where by 1926 the Devonian shale gas fields were the world’s largest known occurrence of natural gas. At year-end 1999 the basin contained over 21,000 gas shale wells, producing approximately 120 billion cubic feet of gas a year.
Technically recoverable resource estimates for the Appalachian Basin range from 14.5 to 27.5 trillion cubic feet of gas.
The basin’s Devonian-age shales extend from southwestern New York to eastern Kentucky and central Tennessee. The majority of its shale gas production has been from the Big Sandy and associated fields in Kentucky and southwestern West Virginia, where the primary target is the Huron member of the Upper Devonian Ohio Shale.
Well recoveries vary considerably, ranging from less than 100 million cubic feet of gas to more than one billion cubic feet. The average well produces 250 to 350 million cubic feet over a productive life of 30 years.
“One of the biggest technical challenges in the Ohio Shale has been in the area of stimulation,” Hill said. “While some wells flow gas naturally, over 90 percent require some form of stimulation to achieve commercial production rates.”

Over the years the Appalachian Devonian shales have been a test bed for a variety of stimulation technologies that include:
“Shooting” a well with gelatinated nitroglycerine.
High energy gas fracturing.
Nitrogen- and carbon dioxide-based foam fracturing.
Straight gas fracturing without proppant.
High angle and horizontal completions.
A number of variations on basic fracturing fluids and chemicals.
Two more recent innovations are the use of liquid carbon dioxide and sand, and cryogenic nitrogen.
As with most stimulation applications, Hill said, no single technique or fluid system has worked universally.
“The proximity to large East Coast markets, low transportation costs, long lived reserves and high success rates will continue to make the Ohio Shale an attractive target in the Appalachian Basin,” he said.
“However, considering the maturity of the play, the greatest challenge to continued success will be expanding the productive limits of historic play areas with new stimulation technologies.”

A Tale of Two Basins
The Antrim Shale in the Michigan Basin spurred the current gas shale interest in the United States.
Initially the Section 29 tax credit spurred activity in the Antrim Shale, but new technology, an understanding of the mechanisms controlling production and operational efficiency gains by operators have sustained activity in the play.
The Devonian-age Antrim Shale reaches a depth of about 3,000 feet in the center of the basin. Operators, however, are developing the shale along the shallow northern and western rim of the basin, where well depths range from 400 to 2,500 feet and wells cost about $240,000 to $280,000 to drill and complete.
The primary targets are the Lachine and Paxton members of the Lower Antrim.
Resources estimates range from 35 trillion to 76 trillion cubic feet of gas, with technically recoverable gas reserves estimated at 11 to 18.9 trillion cubic feet. The average well in the Antrim Shale produces around 116 thousand cubic feet of gas a day, and production has grown from 12 billion cubic feet from 154 wells in 1988 to over 190 billion cubic feet of gas from 6,500 wells in 1999.
In fact, the 221 Antrim Shale wells drilled in 1999 accounted for three-quarters of the drilling activity in the Michigan Basin.
“The Antrim play will continue to develop,” Hill said, “as operators evaluate new completion technologies, recomplete wells in the upper Antrim Shale, conduct restimulation programs and test new areas for production potential.”

The New Albany Shale in the Illinois Basin has a long producing history, too, but activity in this region has not progressed at the same rate as the Ohio Shale or the Antrim Shale.
In the 1990s activity in this play was driven by success in the Antrim. Many of the players in Michigan considered the New Albany a viable target and approached it using the Antrim model for development.
Activity in the New Albany Shale peaked in 1996 with 90 wells, but has since declined to just 16 wells in 1999.
Operators are currently experimenting with various drilling and completion techniques in an attempt to improve well performance and reduce costs. Well costs have ranged from $100,000 to $150,000, depending on water lifting requirements and the type, number and size of stimulation treatments needed.

Efforts also are under way to better identify the mechanisms controlling gas occurrence and productivity.
Gas resource estimates for the New Albany Shale range from 86 to 160 trillion cubic feet of gas with estimates of technically recoverable reserves ranging from 1.9 to 19.2 trillion cubic feet.

The Barnett - and Beyond
Mitchell Energy & Development Co. has been developing the Barnett Shale in the Fort Worth Basin in the northeast sector of central Texas since 1981.
The Mississippian-age Barnett Shale is one of the most uniform statigraphic 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 shale dips gently and thickens to the north, reaching a maximum depth of around 8,500 feet and a maximum thickness of almost 1,000 feet near the Texas-Oklahoma border.
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 is found at 6,500 to 8,000 feet in the Wise and Denton counties area and is about 500 feet thick. It is divided into lower and upper intervals by the Forestburg Limestone.

AFE Oil and Gas Consultants expanded the Barnett Shale play area in 1997 with a discovery in Dallas County, approximately 12 miles southeast of the Newark East Field. The firm continued to expand its play area with three wells in northeastern Tarrent County.
“Initially, Mitchell Energy completed only the lower Barnett interval, using massive hydraulic fracturing treatments,” Hill said. “Well costs typically ranged from $600,000 to $800,000, including $200,000 to $300,000 in stimulation costs.”
In 1998 the firm 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,” Hill said, “and has since been implemented field wide.”
Last September Mitchell Energy demonstrated a technique for economically completing the upper Barnett Shale interval, increasing reserves in their core area by 25 percent, or 250 million cubic feet per well, and expanding the play to previously marginal areas.
This new completion technique in combination with a 50-acre spacing infill well drilling program is expected to allow Mitchell Energy to increase its Barnett Shale gas production and open up new areas for exploitation.

Hill said while the bulk of gas shale production has come from these reservoirs in the San Juan, Appalachian, Michigan, Illinois and Fort Worth basins, there are a multitude of opportunities to expand shale gas activity in other regions of the country.

“Three key advantages of shale gas plays are moderate exploration costs, high success rates and slow production decline rates,” he said. “The rapid growth in the late 1980s and early 1990s in the Antrim Shale, which is being repeated today in the Fort Worth and San Juan basins, is driven by the powerful economic incentives of low risks and low reserve finding costs.
“Each of these plays has presented new technical challenges for operators to overcome,” he added, but “their success has sparked a resurgence of industry interest in evaluating the production potential of shale gas resources in basins throughout the United States.”

The Father Of The Barnett Shale Gas Play

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The Father of the Barnett
A unique set of factors converged to kick off the Barnett boom. New technologies such as artificial fracturing and horizontal drilling made it possible to extract large amounts of gas from shales. The relatively high price of gas in recent years made it economically viable.
Yet according to Eric Potter, neither of these would have mattered without one critical element:
“It wasn’t high tech. It was persistence and experimentation on the part of one company that got this boom going.”

Mitchell Energy had produced gas from a shallower formation, the same formation that John Jackson had discovered in the 1950s. That production was waning.
“They began looking around for what could be done in the same area,” says Potter. “They had always noticed that when you drilled through the Barnett, you would get a gas show. But everyone thought you wouldn’t get much gas.”
Even though shale may have a lot of pores with the ability to store gas, it is not very permeable. In other words, it does not have many connections between the pores and so trapped oil and gas can not flow easily.

“Mitchell Energy sunk a lot of money over a long period into learning how to stimulate the rock so it would flow,” says Potter. Their first attempts were expensive “massive hydraulic frac jobs.” They would pump a very large volume of fluid and sand down a well bore to crack the rock and give it more permeability. At first, they got the gas flowing, but the methods and materials were expensive. So they wondered if they could pump less fluid and get the same effect.
“They arrived at something called a light sand frac,” says Potter. “Suddenly it was economical and at the same time—in the mid-1990s—the price of gas was rising. By the late 1990s, they had perfected the technique in vertical wells and started applying it to several hundred wells. That’s when it came to the attention of industry.”

Potter first heard about these early successes from a Mitchell employee in 1996.
“I didn’t think it would have the kind of impact it did,” he says. “I wasn’t the only one. Most people in industry were surprised and had difficulty adjusting to the notion that shale could produce in commercial amounts over such a wide area. There were only a few companies that appreciated the value of hydraulic fracture technology applied on such a large scale.”
When thermally-mature organic-rich mudstone is drilled into, the pressure drops and gas is released by a process called desorption. Early estimates of how much gas would be given up by the Barnett Shale turned out to be far too low. The experiments were run again and it was realized that this shale would give up much more gas than was previously thought.
“Then it was realized, oh, if you scale that up to the whole area and then to the whole county and up to the whole Basin, the amounts of gas are really quite prodigious,” says Potter. “People became aware of that in 2002 and 2003 and that really got the ball rolling.”

Mitchell Energy already had critical infrastructure in place to process and transport gas. So they could quickly and economically take advantage of the discovery.
“It took George Mitchell 18 years to make it work,” notes Larry Brogdon, partner and chief geologist for Four Sevens Oil Company. “He is the father of the Barnett Shale. He was tenacious. He started in 1981 and it really didn’t take off until 1999. And even then, it took a long time to develop it.”
by Marc Airhart

Barnett Shale Gas

The gas being produced from the Barnett Shale represents one of the most exciting developments in the oil and gas industry in decades.
Peter

source





Barnett Boom Ignites Hunt for Unconventional Gas Resources
January 2007
The global hunt for unconventional gas reserves recently turned to an unlikely spot—a patch of north central Texas that already seemed tapped out after 50 years of intense oil and gas drilling.
Technology, economics and one man’s persistence transformed the Barnett Shale formation of the Fort Worth Basin into a booming new frontier.
As conventional petroleum reserves dwindle in the U.S., public pressure mounts to reduce the country’s dependence on foreign energy, and the price of oil and gas rises, energy companies are setting their sights on “unconventional” domestic sources. These include oil sands, coal beds and shales.

In less than a decade, the Barnett Shale play has become the largest natural gas play in the state of Texas and, as new wells sprout like bluebonnets across the Fort Worth region, it might soon become the largest in the nation.
“This play already covers parts of 15 or more counties,” says Eric Potter, associate director of the Bureau of Economic Geology at the University of Texas at Austin. “It compares favorably with the biggest of the old oil booms of the early 20th century.”
Of course this boom is different. The concrete-like shale gives up its gas grudgingly. So individual wells tend to be smaller and more expensive to operate.

In less than a decade, the Barnett Shale play has become the largest natural gas play in the state of Texas and, as new wells sprout like bluebonnets across the Fort Worth region, it might soon become the largest in the nation.
“The East Texas gushers would win out hands down,” says Potter. “But there are so many [Barnett] wells that even though they are modest, the total output is going to be huge.“
This play is also different because much of the untapped gas lies under the highly populated Fort Worth metropolitan area. Oil and gas companies are finding new challenges drilling in an urban setting.
Now, some experts are wondering if the boom can go global. The search is on for similar shale formations around the world, including the Fayetteville Shale in Arkansas.

Going to the Source
The fact that there is a Barnett boom at all reflects a tectonic shift in thinking. In the past, drillers bypassed the source rock that generated the oil and gas and focused on the reservoir rock, where the resources were easier to extract. Typically, oil or gas exits from the source rock and migrates to places where it is trapped. And those traps—conventional fields—typically do not cover a large area.
“There would be a field here and then a lot of blank space and then a few miles over there would be another field,” says Potter. “But this kind of play, it just covers county after county. You’re looking at thousands and thousands of wells covering the land.”
According to Eric Potter, the 5,500 wells currently pumping gas in the Barnett Shale play will ultimately generate on the order of $35 billion for their owners and through an economic ripple effect, $100 billion for the Texas economy.

With new technologies for coaxing gas out of shales, drillers see the Barnett as both source and reservoir. One such technology is artificial fracturing—in which operators pump water and sand down a well to create fractures that liberate more gas from the rock.
Potter and his colleagues at the Bureau are analyzing the properties of shales across the state. Ultimately, they hope to apply their work to similar rock formations anywhere in the world.
“Now any kind of mudrock or shale that’s black, organic rich, reasonably thick, and reasonably deep we’re interested in,” says Potter. “The question is, all shales are not alike, so what makes a shale prospective as opposed to one that is not prospective? We don’t really know that yet.”

Wise Investment
Before he died in 2003, oilman and philanthropist John Jackson donated to The University of Texas at Austin royalty interests in roughly a thousand wells in the Fort Worth Basin, part of the bequest that led to the formation of the Jackson School of Geosciences. These wells were producing oil and gas from the younger Bend Conglomerate formation just above the Barnett.
The Bend Conglomerate was formed during the Pennsylvanian age, meaning it was laid down about 290 to 320 million years ago. The Barnett Shale, a marine basinal deposit of middle to late Mississippian age, was laid down about 320 to 360 million years ago.
Could the same wells produce significant amounts of gas from the older, deeper Barnett shale? Potter and his colleagues at the Bureau helped the University assess the long-term potential of the University’s royalty interests.

Royalty interests on about a thousand wells donated by John Jackson, mostly in Wise County, Texas help build one of the world’s premier geoscience programs at the Jackson School.
“The short answer is that we think that most of that acreage has quite good potential in the Barnett,” says Potter. “Eight of the top ten Jackson School royalty wells are producing from the Barnett Shale. We are forecasting that most of these holdings will produce from the Barnett.”
The University receives on average about two percent of the gross revenue from wells it holds royalty interests on. That money is being used to build one of the world’s premier geosciences programs at the new Jackson School. Because the money goes into general funds, it supports all of the activities of the school, including dean Eric Barron’s priorities: to create the world’s most student-centered earth science program, to attract and retain the best research talent, to increase the breadth and depth of the faculty and research community and to establish the “fabric of a great school.”

Researchers at the Bureau are providing technical analysis to help stimulate additional drilling and production in Wise County, where most of the University’s royalty interests are located. Emphasis so far has been on mapping the basic stratigraphic and structural framework, tracking successful drilling in the less developed southern part of the play, mapping similar conditions in Wise County, and remapping the thermal maturity of the formation. The maturity seems to relate directly to the gas to oil ratio, one of the key factors controlling gas flow rates.
According to Potter, the 5,500 wells currently pumping gas in the Barnett Shale play will ultimately generate on the order of $35 billion for their owners. As those companies pay taxes and wages, and as their employees and contractors in turn spend their money, there is an economic ripple effect, creating an overall value of about $100 billion to the Texas economy.
Of course, that is only counting current wells. Potter predicts that if gas prices stay relatively high, tens of thousands of new wells will be drilled in the coming decades.

“It’s a ubiquitous reservoir,” says Larry Brogdon, partner and chief geologist for Ft. Worth based Four Sevens Oil Company. “It’s everywhere. You can not drill a well without hitting the Barnett, and the gas is always there. The question is can you get it out or not.“
So far, operators have extracted 2 trillion cubic feet of gas from the Barnett Shale play. At about 1.5 billion cubic feet a day, that’s about 2 percent of the daily natural gas consumption of the U.S.
“When you can go from nothing to the second largest producing gas field in the country in a matter of just a few years, that makes a statement,” says Rich Pollastro, a geologist with the U.S. Geological Survey in Lakewood, Colorado. “That’s huge. And it could potentially become the largest producing field in the country. That was a real awakening for the country and now because of its success, industry and nations are looking at it worldwide.”

The Next Barnett?
In the summer of 2004, Southwestern Energy announced that the Fayetteville Shale formation in the Arkoma Basin had many of the same characteristics that made the Barnett Shale formation so desirable for gas production. Before the announcement, the company had quietly acquired mineral leases on nearly a half million acres of land.
The announcement set off another gas boom. Oil and gas operators familiar with the Barnett Shale rushed to Arkansas to get in on the action.
“The analog would be like a 19th century gold rush,” says Ed Ratchford, geology supervisor for the Arkansas Geological Commission in Little Rock. “Everyone stakes a claim. You don’t say this place is going to be better than this place. You don’t have time. People were leasing thousands of acres a day.”

Ratchford and his team maintain a well log library, a collection of well cuttings and cores from oil and gas wells across Arkansas. They used these to conduct geochemical tests on samples from the Fayetteville Shale and produce a regional picture of where good gas prospects were likely to be.
“We had companies all over us waiting for us to get this stuff done,” says Ratchford. “They were sitting out in the parking lot before we opened up. We were the only ones that had this information. It was critical for helping the operators know where to lease.”
In the excitement, many companies took a gamble on mineral leases.

Locations of the Barnett Formation. Source: USGS.
“We had a lot of companies that had leased before the report came out,” says Ratchford. “Then they had a big golf ball in their throats saying, ‘I wish I hadn’t leased here.’ That’s the risk you run when you lease big tracts of land in a boom without having the luxury of doing the science first.”
“Some of those companies are going to make a lot of money,” notes Ratchford, “some are going to be doing tax write offs. That’s the nature of exploration. In a situation like this, where there’s a frenzy, there are going to be winners and losers.“
It’s too early to tell how much gas will ultimately be recoverable from the Fayetteville Shale. Southwestern Energy, still the largest lease holder in the play, estimates that they will recover 17 trillion cubic feet of gas.

The future looks good for the Fayetteville play. Ratchford expects the number of wells producing in the area to rise from the current 80 to a couple hundred and that gas will be extracted for at least 15 or 20 years.
He also notes that oilfield services provider Schlumberger has recently built a 30,000 square foot facility in Conway, Arkansas and will employ approximately 100 employees at that facility. “They would not do this if they didn’t believe this would be a long term venture,” says Ratchford.
Other areas that have generated interest for possible large shale gas plays are the Caney and Woodford formations in Oklahoma, the Floyd formation in the Black Warrior Basin of northwest Alabama, and the Barnett and Woodford formations in the Permian Basin of Texas.
It remains to be seen if the rising star of the Barnett Shale play will be eclipsed by other gas plays.
“The Barnett might be as good as it gets,” says Pollastro. “No one knows for sure.”
He produced the U.S. Geological Survey’s assessment of the Fort Worth Barnett shale play in 2003. At the time, he estimated that it held a remaining volume of 26 trillion cubic feet of recoverable unconventional gas. Now he’s evaluating the Barnett and Woodford formations in the Permian Basin, where drillers have experienced mixed results.
“It’s a different animal,” he says. “The Barnett in the Delaware Basin part of the Permian Basin is deeper and is more clay rich, so at present it’s not working like everybody thought it would. It’s not as rich in organic material as the Fort Worth Basin. I think there’s good potential, but I think there will be a steep learning curve.”
by Marc Airhart

Doomsday Is Approaching For Climate Change Alarmists

Professor Will Alexander of The University of Pretoria, South Africa is quite outspoken and to the point in his dismissal of the myth of man-caused global warming. It looks like his article is not "peer-reviewed", which probably makes it all the more valuable. Global warming alarmists are going to be have an increasingly difficult time silencing their growing number of critics.
Peter

Fraudulent Science
Will Alexander
My advice to climate alarmists is that now is an appropriate time to start planning your exit strategy. The whole IPCC/UNFCCC edifice is about to disintegrate. I described these events in my recent memos. My position during all these years has been very simple. I could find no evidence of unnatural changes in the officially published hydrometeorological records. In the attached memo, for the first time I go on the attack. Not only is there no believable evidence in the data to support climate alarmism, but the evidence refutes the IPCC’s claims and completely undermines its position.

I have attached two files, my memo and the evaporation histograms in file Evaporation.pdf. What is the future of climate alarmism and its associated research? There is none. The globe is cooling, the glaciers are advancing and Bangladesh is not being inundated by rising sea levels. Public interest is falling and the media are becoming more critical. The possibility of nations reaching agreement on meaningful actions to control, let alone reduce, their undesirable emissions is receding by the day. The basic science underlying the IPCC’s position is being eroded away, stone by stone.

There is a growing and very perceptible groundswell of public and scientific opinion that is questioning the very basis of climate alarmism. The alarmists are no longer dealing with a gullible public and ambitious poticians. Here in South Africa, we are going through turbulent times. Honest, conscientious and knowledgeable scientists have a professional and moral duty to examine the scientific basis for the alarmist claims and report their findings. The most efficient method to publicise their results is the Internet. Others can use the information to complement their own studies. The rising tide of knowledge will become unchallengeable. This is the route that I have followed. Ever since I became involved in this climate change issue, way back in 1993, I reported that there is no evidence in the data to support the alarmist claims. The other side insisted that their computer models were infallible and that I was wrong. I did not try to prove that they were wrong. I just kept reiterating that there was no evidence in the data to support their theories.

This was also my 93-page message to the Stern Review. You will recall their basic argument. Increasing undesirable greenhouse gas emissions result in rising global temperatures. These increase evaporation from the oceans. Energy is thereby transferred to the atmosphere. This in turn amplifies the greenhouse effect. All of this results in an intensification of the hydrological cycle: more extreme floods and droughts, etc etc. All of this results in threats to our precious plant and animal species and human life on this planet. (But as the analysis shows,) there is no evidence of changes in open water surface evaporation that are synchronous with global temperature changes during the period of record. This is a body blow for the climate alarmists. There is absolutely no evidence that global warming increases evaporation from open water surfaces, including the oceans.

If the alarmists try to follow the adaptation route, they will be squashed underfoot by civil engineers and applied hydrologists. There is only one remaining option. Abandon ship. In the meantime, you may find this item on the web interesting.
See Will’s latest memo here.

Will Alexander is a Professor at the University of Pretoria, South Africa

University of Pretoria professor: MAN-MADE global warming is not real
allAfrica.com: Namibia: Climate Change a Fallacy - South African Professor (Page 1 of 1)
MAN-MADE global warming is not real, a Professor from the University of Pretoria charged in Windhoek last week.

Professor Will Alexander claimed that claims by environmentalists that climate change was real were not true and if the world was warmer now, it was simply caused by natural climatic variability....He said while environmentalists claim that rainfall will decrease because of climate change, rainfall has in fact increased during the last century.According to him, it was also not true that the frequency of tropical cyclones, droughts and floods will increase."There is no evidence on that," said Alexander.He claimed that disasters such as this year's floods in the North were caused by natural climatic variability and people were affected because they were now living in areas prone to natural disasters, whereas before they lived in higher-lying areas.But Dr Omu Kakujaha from the University of Namibia said whether climate change or climate variability was real or not, it has a negative impact on Namibia's economy.
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