Peter
Showing posts with label Fayeteville Shale. Show all posts
Showing posts with label Fayeteville Shale. Show all posts
Tuesday, February 28, 2012
Do We Have Much Oil And Gas Left In The United States?
Just look at this map. And this is just the lower 48 for Obama's sake! Someone tell him or his advisors (handlers). Didn't he say something like "we can't drill our way" out of this energy crisis? Sometimes I wonder what he is really smoking. Look at this map closely. There is oil and gs all over the place, not all of it easy to recover, but give us a chance Mr. Obama, please? I? know it's there, I didn't create this map , but I know it's there, I've studied all these places. Please, let us help you pay your bills and get out of debt. Please Mr. President, before it is too late.
Peter
Peter
Wednesday, July 8, 2009
US and Canadian Shale Gas Plays Examined
Study analyzes nine US, Canada shale gas plays
A recent study has estimated that nine US and Canada shale-gas plays may produce as much as 24 bcfd by 2018. (source)
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The Oct. 6, 2008, Tristone Capital Inc. study evaluated the gas resources in the Bamett (Fort Worth basin), Deep Bossier, Haynesville, Fayetteville, Woodford, and Marcellus shales in the US and the Montney, Hom River (Muskwa), and Utica shales in Canada (Fig. 1).
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The study expects companies ultimately to recover from these resources 261 tcf of gas, based on various risk factors applied and a long-term average gas price of $8.50/MMbtu. Without the risk factors, Tristone Capital says these shales have a 743-tcf recovery potential (Fig. 2).
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Fig. 3 shows the study’s estimated production from these plays, and Fig. 4 shows its US well completion forecast.
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Several emerging shale plays with limited well control also may contribute additional gas to future production, according to the study. These include the Pearsall shales in the Maverick basin of South Texas, the Niobrara shales of Western Colorado, and the Barnett shale in the Delaware basin of West Texas.
Shale play comparison
The study says that shale-gas plays owe their success to a balance of various parameters along with constantly evolving drilling and completion techniques and infrastructure. “It is commonly said that no two shale gas plays are exactly alike,” the study says.
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Table 1 summarizes shale-gas play attributes, and Fig. 5 compares the arithmetic average of the attributes. The study notes that the most productive core portions of plays may deviate from the averages.
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Multistage hydraulic fracturing along a horizontal lateral and improvements in stimulation are main factors influencing shale-gas development economics. The study says these factors have improved economics by more than three times from that of vertical well developments by improving both ultimate recovery and initial production rates.
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Table 2 compares typical lateral lengths and frac treatments for the nine plays.
The three types of frac fluid noted are slick water, CO2-polymer, and gelled cross-linked oil-based fluid.
Slick-water fracs use a nongelled fracturing fluid with low proppant concentrations and a friction-reducing chemical additive that allows pumping the water into the reservoir faster. The fluid often is a brine or potassium chloride (KCl) water to inhibit swelling of clays. The study notes that this fluid is less expensive than hydrocarbon-based fluid and works best in low-permeability reservoirs
Companies pioneered slick-water fracs first in the Fort Worth basin’s Barnett shale.
The CO2-polymer frac fluid contains emulsified CO2 in a methanol-water mixture of 5% water and 20% methanol. The study says the mixture appears to minimize reservoir damage and maximize fluid recovery from multiple diversions in the well. Including CO2 also reduces by 25% the fluid required and provides extra energy, as the gas expands, during frac fluid flow-back greatly to shorten cleanup time, the study says.
The Montney formation in British Columbia is where companies use this fluid. The study notes that stimulating a horizontal well in the Montney typically involves perforating, isolating, and fracturing 6-11 zones at a cost of about $100,000- 120,000/frac interval. It is common to spend more than $1 million for fracturing these wells, the study says. The study describes these jobs as needing 8-10 pump trucks or about 18,000-22,500 hp and taking more than 1 week to complete.
The study notes that companies initially used gelled cross-linked oil-based fluids as the “fluid of choice” for hydraulic fracturing because of its compatibility with most formations and its cold weather attributes. In several basins, slickwater fracs have replaced oil-based fracs because the slick water uses less water and costs less, the study says.
To prevent swelling and permeability loss in the shales, companies typically continue to use oil-based frac fluids in formations that contain extensive water-sensitive clays. The study notes that these fluids are used in the Fayetteville, Haynesville, and Woodford shales.
Fort Worth basin Barnett
Development activity continues to evolve with part of the current activity in urban sites such as Fort Worth and the Dallas-Fort Worth airports.
The study notes that as of Aug. 18, 2008, the Barnett had 8,416 gas wells drilled in 19 counties. Production had increased to 3.8 bcfd in first-quarter 2008 from 219 MMcfd in 2000. The study expects the shale to produce 6-7 bcfd in the next 5 years.
Some of the newer techniques in the play noted in the study are:
- Longer horizontal laterals, up to 3,500 ft, often drilled from pads with multiple wells, especially in the urban areas.
- Testing of tighter well density with laterals, spaced 250-ft apart (25-30) compared with 500 ft between laterals (50-acre spacing).
- Simultaneous fracing of wells to increase recovery.
Deep Bossier
Wells in Deep Bossier of East Texas reach a 15,000-20,000 ft depth, have pressures of about 15,000 psi, and have tested at 65 MMcfd. The study notes that these wells are expensive, costing $10-20/million for a vertical well.
Currently the play has six main fields in four counties: Robertson, Leon, Freestone, and Limestone.
Fayetteville
The Fayetteville shale in Arkansas is the shallower and thinner equivalent of the Barnett shale. The core of the play is in five counties in central Arkansas: Cleburne, Van Buren, Conway, Faulkner, and White.
The study says as of May 31, 2008, the play had 877 producing wells, with production in July of 740 MMcfd compared to only 90 MMcfd in December 2006. The study expects the play to produce 3.15 bcfd by 2018.
Haynesville
The Haynesville shale is in northwestern Louisiana and East Texas. Wells in the play initially have produced 5-20 MMcfd, the study said. The study expects wells to have ultimate gas recovers of 4-8 bcf.
Currently, companies have drilled about 20-25 horizontal wells in the play, and the study expects about 60-80 rigs could be active in the play by yearend 2008, with most of the drilling in Caddo and DeSoto Parishes in Louisiana.
Woodford
The Devonian-aged Woodford shale lies at 6,000-14,000 ft depths in the Arkoma basin of southeast Oklahoma. The study notes that the $6 million well cost in the Woodford is more than the $2-3/million/well cost in the Fayetteville and Barnett shales.
The study estimates that an 80-acre well in the Woodford will recover about 4 bcf of gas.
Marcellus
The Marcellus shale in the Appalachia basin extends over several states, although most wells drilled to date have been in Pennsylvania, the study notes.
It says Marcellus production has been minimal to date because of the need to expand the existing infrastructure to accommodate the high-pressure gas that the gas transportation system in Appalachia cannot at this time handle.
Most companies have so far drilled mostly vertical wells to delineate the play, but the study expects horizontal wells to be the primary means for developing the formation.
Montney
The Montney shale lies in the east-central part of British Columbia. The study notes that continued drilling should increase production to 1 bcfd by yearend 2009 from the current 600 MMscfd in early 2008.
Operators typical include five to eight fracs/well, and the study expects estimated ultimate gas recovery to increase to 7 bcf/well from the current 5 bcf/well as technology innovation continues.
Horn River basin
The Horn River basin in Northeastern British Columbia extends into the Northwest Territories. The Devonian Muskwa shale is the main play although the basin also has other shales with large original gas in place such as the Fort Simpson, the study says.
Initial well production rates have ranged from 2 to 8.8 MMcfd with wells with more fracs stages producing better, the study notes. The study says estimated ultimate gas recovery ranges from 4 to 6 bcf/section.
Utica
The Utica and the overlying Lorraine shales are relatively new plays in Quebec with only a few wells testing the formations to date. The study estimates that recoverable gas could be as much as 40 tcf (150 bcf/section).
An initial vertical well tested at 1 MMcfd; rates should be higher for horizontal wells with multiple fracs, according to the study.
Emerging plays
Three emerging shale plays listed by the study are Pearsall shales in the Maverick basin of South Texas, the Niobrara shales of Western Colorado, and the Barnett shale in the Delaware basin of West Texas.
The study says the Pearsall is as deep as 3,500 m in places, has a 200-300 m thickness, and contains about 30-175 bcf/section of original gas in place. It notes reports that say initial horizontal wells flowed at 0.8-3.8 MMcfd.
The Niobrara shales outcrop in Kansas and Nebraska, but are at more than 2,500 m depths in western Colorado. The study notes that in the eastern shallower portion of the play, the shales are underpressured and wells have low initial rates, while in the deeper overpressure portion, wells may produced at 1 MMcfd and recover 100-150 bcf of gas/section.
The Barnett in the Delaware basin is twice a deep as the Barnett in the Fort Worth basin and therefore holds much more gas per section. One estimate is that the Delaware Barnett has 500 bcf/section compared with 150 bcf/section in the Fort Worth basin. The study notes that developing Delaware Barnett gas will be more complicated and costly.
Saturday, April 18, 2009
Shale Gas Development In The United States: A Summary By The DOE
The United States Department of Energy (DOE) just released (April 14, 2009) a thorough "primer" on the current status of shale gas development in the onshore portion of the lower 48 United States. Reproduced below is the executive summary. The complete document is available in .pdf format here: http://www.fossil.energy.gov/programs/oilgas/publications/naturalgas_general/Shale_Gas_Primer_2009.pdf
The document is 116 pages long and is thus far too much to post here. However, I will be posting sections of it I find relevant to geologists, geophysicists, and engineers most directly involved with the exploration, development, and production of this significant new energy resource. There will be abundant opportunity for further discussion and elaboration on these subjects.
Peter
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER
EXECUTIVE SUMMARY (source)
Natural gas production from hydrocarbon rich shale formations, known as “shale gas,” is one of the most rapidly expanding trends in onshore domestic oil and gas exploration and production today. In some areas, this has included bringing drilling and production to regions of the country that have seen little or no activity in the past. New oil and gas developments bring change to the
environmental and socio-economic landscape, particularly in those areas where gas development is a new activity. With these changes have come questions about the nature of shale gas development, the potential environmental impacts, and the ability of the current regulatory structure to deal with this development. Regulators, policy makers, and the public need an objective source of information on which to base answers to these questions and decisions about how to manage the challenges that may accompany shale gas development.
Natural gas plays a key role in meeting U.S. energy demands. Natural gas, coal and oil supply about 85% of the nation’s energy, with natural gas supplying about 22% of the total. The percent contribution of natural gas to the U.S. energy supply is expected to remain fairly constant for the next 20 years.
The United States has abundant natural gas resources. The Energy Information Administration estimates that the U.S. has more than 1,744 trillion cubic feet (tcf) of technically recoverable natural gas, including 211 tcf of proved reserves (the discovered, economically recoverable fraction of the original gas-in-place). Technically recoverable unconventional gas (shale gas, tight sands, and coalbed methane) accounts for 60% of the onshore recoverable resource. At the U.S. production rates for 2007, about 19.3 tcf, the current recoverable resource estimate provides enough natural gas to supply the U.S. for the next 90 years. Separate estimates of the shale gas resource extend this supply to 116 years.
Natural gas use is distributed across several sectors of the economy. It is an important energy
source for the industrial, commercial and electrical generation sectors, and also serves a vital role in residential heating. Although forecasts vary in their outlook for future demand for natural gas, they all have one thing in common: natural gas will continue to play a significant role in the U.S. energy picture for some time to come.
The lower 48 states have a wide distribution of highly organic shales containing vast resources of natural gas. Already, the fledgling Barnett Shale play in Texas produces 6% of all natural gas produced in the lower 48 States.
Three factors have come together in recent years to make shale gas production economically viable: 1) advances in horizontal drilling, 2) advances in hydraulic fracturing, and, perhaps most importantly, 3) rapid increases in natural gas prices in the last several years as a result of significant supply and demand pressures.
Analysts have estimated that by 2011 most new reserves growth (50% to 60%, or approximately 3 bcf/day) will come from unconventional shale gas reservoirs. The total recoverable gas resources in four new shale gas plays (the Haynesville, Fayetteville, Marcellus, and Woodford) may be over 550 tcf. Total annual production volumes of 3 to 4 tcf may be sustainable for decades. This potential for production in the known onshore shale basins, coupled with other unconventional gas plays, is predicted to contribute significantly to the U.S.’s domestic energy outlook.
Shale gas is present across much of the lower 48 States. Exhibit ES-1 shows the approximate
locations of current producing gas shales and prospective shales. The most active shales to date are the Barnett Shale, the Haynesville/Bossier Shale, the Antrim Shale, the Fayetteville Shale, the Marcellus Shale, and the New Albany Shale.
Each of these gas shale basins is different and each has a unique set of exploration criteria and operational challenges. Because of these differences, the development of shale gas resources in each of these areas faces potentially unique opportunities and challenges.
EXHIBIT ES-1: UNITED STATES SHALE BASINS
The development and production of oil and gas in the U.S., including shale gas, are regulated under a complex set of federal, state, and local laws that address every aspect of exploration and operation. All of the laws, regulations, and permits that apply to conventional oil and gas
exploration and production activities also apply to shale gas development.
The U.S. Environmental Protection Agency administers most of the federal laws, although development on federally-owned land is managed primarily by the Bureau of Land Management (part of the Department of the Interior) and the U.S. Forest Service (part of the Department of Agriculture). In addition, each state in which oil and gas is produced has one or more regulatory agencies that permit wells, including their design, location, spacing, operation, and abandonment, as well as environmental activities and discharges, including water management and disposal, waste management and disposal, air emissions, underground injection, wildlife impacts, surface disturbance, and worker health and safety.
Many of the federal laws are implemented by the states under agreements and plans
approved by the appropriate federal agencies. A series of federal laws governs most environmental aspects of shale gas development. For example, the Clean Water Act regulates surface discharges of water associated with shale gas drilling and production, as well as storm water runoff from production sites. The Safe Drinking Water Act regulates the underground injection of fluids from shale gas activities. The Clean Air Act limits air emissions from engines, gas processing equipment, and other sources associated with drilling and production. The National Environmental Policy Act (NEPA) requires that exploration and production on federal lands be thoroughly analyzed for environmental impacts.
Most of these federal laws have provisions for granting “primacy” to the states (i.e., state agencies implement the programs with federal oversight). State agencies not only implement and enforce federal laws; they also have their own sets of state laws to administer. The states have broad powers to regulate, permit, and enforce all shale gas development activities—the drilling and fracture of the well, production operations, management and disposal of wastes, and abandonment and plugging of the well.
State regulation of the environmental practices related to shale gas development, usually with federal oversight, can more effectively address the regional and state-specific character of the activities, compared to one-sizefits-all regulation at the federal level. Some of these specific factors include: geology, hydrology, climate, topography, industry characteristics, development history, state legal structures, population density, and local economics. State laws often add additional levels of environmental protection and requirements. Also, several states have their own versions of the federal NEPA law, requiring environmental assessments and reviews at the state level and extending those reviews beyond federal lands to state and private lands.
A key element in the emergence of shale gas production has been the refinement of cost-effective horizontal drilling and hydraulic fracturing technologies. These two processes, along with the implementation of protective environmental management practices, have allowed shale gas development to move into areas that previously would have been inaccessible. Accordingly, it is important to understand the technologies and practices employed by the industry and their ability to prevent or minimize the potential effects of shale gas development on human health and the environment and on the quality of life in the communities in which shale gas production is located.
Modern shale gas development is a technologically driven process for the production of natural gas resources. Currently, the drilling and completion of shale gas wells includes both vertical and
horizontal wells. In both kinds of wells, casing and cement are installed to protect fresh and
treatable water aquifers. The emerging shale gas basins are expected to follow a trend similar to
the Barnett Shale play with increasing numbers of horizontal wells as the plays mature.
Shale gas operators are increasingly relying on horizontal well completions to optimize recovery and well economics. Horizontal drilling provides more exposure to a formation than does a vertical well. This increase in reservoir exposure creates a number of advantages over vertical wells drilling. Six to eight horizontal wells drilled from only one well pad can access the same reservoir volume as sixteen vertical wells. Using multi-well pads can also significantly reduce the overall number of well pads, access roads, pipeline routes, and production facilities required, thus minimizing habitat disturbance, impacts to the public, and the overall environmental footprint.
The other technological key to the economic recovery of shale gas is hydraulic fracturing, which
involves the pumping of a fracturing fluid under high pressure into a shale formation to generate
fractures or cracks in the target rock formation. This allows the natural gas to flow out of the shale to the well in economic quantities. Ground water is protected during the shale gas fracturing process by a combination of the casing and cement that is installed when the well is drilled and the thousands of feet of rock between the fracture zone and any fresh or treatable aquifers.
For shale gas development, fracture fluids are primarily water based fluids mixed with additives that help the water to carry sand proppant into the fractures. Water and sand make up over 98% of the fracture fluid, with the rest consisting of various chemical additives that improve the effectiveness of the fracture job. Each hydraulic fracture treatment is a highly controlled process designed to the specific conditions of the target formation.
The amount of water needed to drill and fracture a horizontal shale gas well generally ranges from about 2 million to 4 million gallons, depending on the basin and formation characteristics. While these volumes may seem very large, they are small by comparison to some other uses of water, such as agriculture, electric power generation, and municipalities, and generally represent a small percentage of the total water resource use in each shale gas area. Calculations indicate that water use for shale gas development will range from less than 0.1% to 0.8% of total water use by basin.
Because the development of shale gas is new in some areas, these water needs may still challenge supplies and infrastructure. As operators look to develop new shale gas plays, communication with local water planning agencies, state agencies, and regional water basin commissions can help operators and communities to coexist and effectively manage local water resources. One key to the successful development of shale gas is the identification of water supplies capable of meeting the needs of a development company for drilling and fracturing water without interfering with community needs. While a variety of options exist, the conditions of obtaining water are complex and vary by region.
After the drilling and fracturing of the well are completed, water is produced along with the natural gas. Some of this water is returned fracture fluid and some is natural formation water. Regardless of the source, these produced waters that move back through the wellhead with the gas represent a stream that must be managed. States, local governments, and shale gas operators seek to manage produced water in a way that protects surface and ground water resources and, if possible, reduces future demands for fresh water.
By pursuing the pollution prevention hierarchy of “Reduce, Re-use, and Recycle” these groups are examining both traditional and innovative approaches to managing shale gas produced water. This water is currently managed through a variety of mechanisms, including underground injection, treatment and discharge, and recycling. New water treatment
technologies and new applications of existing technologies are being developed and used to treat
shale gas produced water for reuse in a variety of applications. This allows shale gas-associated
produced water to be viewed as a potential resource in its own right.
Some soils and geologic formations contain low levels of naturally occurring radioactive material
(NORM). When NORM is brought to the surface during shale gas drilling and production
operations, it remains in the rock pieces of the drill cuttings, remains in solution with produced
water, or, under certain conditions, precipitates out in scales or sludges. The radiation from this
NORM is weak and cannot penetrate dense materials such as the steel used in pipes and tanks.
Because the general public does not come into contact with gas field equipment for extended
periods, there is very little exposure risk from gas field NORM.
To protect gas field workers, OSHA requires employers to evaluate radiation hazards, post caution signs and provide personal protection equipment when radiation doses could exceed regulatory standards. Although regulations vary by state, in general, if NORM concentrations are less than regulatory standards, operators are allowed to dispose of the material by methods approved for standard gas field waste.
Conversely, if NORM concentrations are above regulatory limits, the material must be disposed of at a licensed facility. These regulations, standards, and practices ensure that shale gas operations present negligible risk to the general public and to workers with respect to potential NORM exposure.
Although natural gas offers a number of environmental benefits over other sources of energy,
particularly other fossil fuels, some air emissions commonly occur during exploration and
production activities. Emissions may include NOx, volatile organic compounds, particulate matter, SO2, and methane. EPA sets standards, monitors the ambient air across the U.S., and has an active enforcement program to control air emissions from all sources, including the shale gas industry. Gas field emissions are controlled and minimized through a combination of government regulation and voluntary avoidance, minimization, and mitigation strategies.
The primary differences between modern shale gas development and conventional natural gas
development are the extensive uses of horizontal drilling and high-volume hydraulic fracturing.
The use of horizontal drilling has not introduced any new environmental concerns. In fact, the
reduced number of horizontal wells needed coupled with the ability to drill multiple wells from a
single pad has significantly reduced surface disturbances and associated impacts to wildlife, dust , noise, and traffic. Where shale gas development has intersected with urban and industrial settings, regulators and industry have developed special practices to alleviate nuisance impacts, impacts to sensitive environmental resources, and interference with existing businesses.
Hydraulic fracturing has been a key technology in making shale gas an affordable addition to the Nation’s energy supply, and the technology has proved to be an effective stimulation technique. While some challenges exist with water availability and water management, innovative regional solutions are emerging that allow shale gas development to continue while ensuring that the water needs of other users are not affected and that surface and ground water quality is protected. Taken together, state and federal requirements along with the technologies and practices developed by industry serve to reduce environmental impacts from shale gas operations.
The document is 116 pages long and is thus far too much to post here. However, I will be posting sections of it I find relevant to geologists, geophysicists, and engineers most directly involved with the exploration, development, and production of this significant new energy resource. There will be abundant opportunity for further discussion and elaboration on these subjects.
Peter
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER
EXECUTIVE SUMMARY (source)
Natural gas production from hydrocarbon rich shale formations, known as “shale gas,” is one of the most rapidly expanding trends in onshore domestic oil and gas exploration and production today. In some areas, this has included bringing drilling and production to regions of the country that have seen little or no activity in the past. New oil and gas developments bring change to the
environmental and socio-economic landscape, particularly in those areas where gas development is a new activity. With these changes have come questions about the nature of shale gas development, the potential environmental impacts, and the ability of the current regulatory structure to deal with this development. Regulators, policy makers, and the public need an objective source of information on which to base answers to these questions and decisions about how to manage the challenges that may accompany shale gas development.
Natural gas plays a key role in meeting U.S. energy demands. Natural gas, coal and oil supply about 85% of the nation’s energy, with natural gas supplying about 22% of the total. The percent contribution of natural gas to the U.S. energy supply is expected to remain fairly constant for the next 20 years.
The United States has abundant natural gas resources. The Energy Information Administration estimates that the U.S. has more than 1,744 trillion cubic feet (tcf) of technically recoverable natural gas, including 211 tcf of proved reserves (the discovered, economically recoverable fraction of the original gas-in-place). Technically recoverable unconventional gas (shale gas, tight sands, and coalbed methane) accounts for 60% of the onshore recoverable resource. At the U.S. production rates for 2007, about 19.3 tcf, the current recoverable resource estimate provides enough natural gas to supply the U.S. for the next 90 years. Separate estimates of the shale gas resource extend this supply to 116 years.
Natural gas use is distributed across several sectors of the economy. It is an important energy
source for the industrial, commercial and electrical generation sectors, and also serves a vital role in residential heating. Although forecasts vary in their outlook for future demand for natural gas, they all have one thing in common: natural gas will continue to play a significant role in the U.S. energy picture for some time to come.
The lower 48 states have a wide distribution of highly organic shales containing vast resources of natural gas. Already, the fledgling Barnett Shale play in Texas produces 6% of all natural gas produced in the lower 48 States.
Three factors have come together in recent years to make shale gas production economically viable: 1) advances in horizontal drilling, 2) advances in hydraulic fracturing, and, perhaps most importantly, 3) rapid increases in natural gas prices in the last several years as a result of significant supply and demand pressures.
Analysts have estimated that by 2011 most new reserves growth (50% to 60%, or approximately 3 bcf/day) will come from unconventional shale gas reservoirs. The total recoverable gas resources in four new shale gas plays (the Haynesville, Fayetteville, Marcellus, and Woodford) may be over 550 tcf. Total annual production volumes of 3 to 4 tcf may be sustainable for decades. This potential for production in the known onshore shale basins, coupled with other unconventional gas plays, is predicted to contribute significantly to the U.S.’s domestic energy outlook.
Shale gas is present across much of the lower 48 States. Exhibit ES-1 shows the approximate
locations of current producing gas shales and prospective shales. The most active shales to date are the Barnett Shale, the Haynesville/Bossier Shale, the Antrim Shale, the Fayetteville Shale, the Marcellus Shale, and the New Albany Shale.
Each of these gas shale basins is different and each has a unique set of exploration criteria and operational challenges. Because of these differences, the development of shale gas resources in each of these areas faces potentially unique opportunities and challenges.
EXHIBIT ES-1: UNITED STATES SHALE BASINS
The development and production of oil and gas in the U.S., including shale gas, are regulated under a complex set of federal, state, and local laws that address every aspect of exploration and operation. All of the laws, regulations, and permits that apply to conventional oil and gas
exploration and production activities also apply to shale gas development.
The U.S. Environmental Protection Agency administers most of the federal laws, although development on federally-owned land is managed primarily by the Bureau of Land Management (part of the Department of the Interior) and the U.S. Forest Service (part of the Department of Agriculture). In addition, each state in which oil and gas is produced has one or more regulatory agencies that permit wells, including their design, location, spacing, operation, and abandonment, as well as environmental activities and discharges, including water management and disposal, waste management and disposal, air emissions, underground injection, wildlife impacts, surface disturbance, and worker health and safety.
Many of the federal laws are implemented by the states under agreements and plans
approved by the appropriate federal agencies. A series of federal laws governs most environmental aspects of shale gas development. For example, the Clean Water Act regulates surface discharges of water associated with shale gas drilling and production, as well as storm water runoff from production sites. The Safe Drinking Water Act regulates the underground injection of fluids from shale gas activities. The Clean Air Act limits air emissions from engines, gas processing equipment, and other sources associated with drilling and production. The National Environmental Policy Act (NEPA) requires that exploration and production on federal lands be thoroughly analyzed for environmental impacts.
Most of these federal laws have provisions for granting “primacy” to the states (i.e., state agencies implement the programs with federal oversight). State agencies not only implement and enforce federal laws; they also have their own sets of state laws to administer. The states have broad powers to regulate, permit, and enforce all shale gas development activities—the drilling and fracture of the well, production operations, management and disposal of wastes, and abandonment and plugging of the well.
State regulation of the environmental practices related to shale gas development, usually with federal oversight, can more effectively address the regional and state-specific character of the activities, compared to one-sizefits-all regulation at the federal level. Some of these specific factors include: geology, hydrology, climate, topography, industry characteristics, development history, state legal structures, population density, and local economics. State laws often add additional levels of environmental protection and requirements. Also, several states have their own versions of the federal NEPA law, requiring environmental assessments and reviews at the state level and extending those reviews beyond federal lands to state and private lands.
A key element in the emergence of shale gas production has been the refinement of cost-effective horizontal drilling and hydraulic fracturing technologies. These two processes, along with the implementation of protective environmental management practices, have allowed shale gas development to move into areas that previously would have been inaccessible. Accordingly, it is important to understand the technologies and practices employed by the industry and their ability to prevent or minimize the potential effects of shale gas development on human health and the environment and on the quality of life in the communities in which shale gas production is located.
Modern shale gas development is a technologically driven process for the production of natural gas resources. Currently, the drilling and completion of shale gas wells includes both vertical and
horizontal wells. In both kinds of wells, casing and cement are installed to protect fresh and
treatable water aquifers. The emerging shale gas basins are expected to follow a trend similar to
the Barnett Shale play with increasing numbers of horizontal wells as the plays mature.
Shale gas operators are increasingly relying on horizontal well completions to optimize recovery and well economics. Horizontal drilling provides more exposure to a formation than does a vertical well. This increase in reservoir exposure creates a number of advantages over vertical wells drilling. Six to eight horizontal wells drilled from only one well pad can access the same reservoir volume as sixteen vertical wells. Using multi-well pads can also significantly reduce the overall number of well pads, access roads, pipeline routes, and production facilities required, thus minimizing habitat disturbance, impacts to the public, and the overall environmental footprint.
The other technological key to the economic recovery of shale gas is hydraulic fracturing, which
involves the pumping of a fracturing fluid under high pressure into a shale formation to generate
fractures or cracks in the target rock formation. This allows the natural gas to flow out of the shale to the well in economic quantities. Ground water is protected during the shale gas fracturing process by a combination of the casing and cement that is installed when the well is drilled and the thousands of feet of rock between the fracture zone and any fresh or treatable aquifers.
For shale gas development, fracture fluids are primarily water based fluids mixed with additives that help the water to carry sand proppant into the fractures. Water and sand make up over 98% of the fracture fluid, with the rest consisting of various chemical additives that improve the effectiveness of the fracture job. Each hydraulic fracture treatment is a highly controlled process designed to the specific conditions of the target formation.
The amount of water needed to drill and fracture a horizontal shale gas well generally ranges from about 2 million to 4 million gallons, depending on the basin and formation characteristics. While these volumes may seem very large, they are small by comparison to some other uses of water, such as agriculture, electric power generation, and municipalities, and generally represent a small percentage of the total water resource use in each shale gas area. Calculations indicate that water use for shale gas development will range from less than 0.1% to 0.8% of total water use by basin.
Because the development of shale gas is new in some areas, these water needs may still challenge supplies and infrastructure. As operators look to develop new shale gas plays, communication with local water planning agencies, state agencies, and regional water basin commissions can help operators and communities to coexist and effectively manage local water resources. One key to the successful development of shale gas is the identification of water supplies capable of meeting the needs of a development company for drilling and fracturing water without interfering with community needs. While a variety of options exist, the conditions of obtaining water are complex and vary by region.
After the drilling and fracturing of the well are completed, water is produced along with the natural gas. Some of this water is returned fracture fluid and some is natural formation water. Regardless of the source, these produced waters that move back through the wellhead with the gas represent a stream that must be managed. States, local governments, and shale gas operators seek to manage produced water in a way that protects surface and ground water resources and, if possible, reduces future demands for fresh water.
By pursuing the pollution prevention hierarchy of “Reduce, Re-use, and Recycle” these groups are examining both traditional and innovative approaches to managing shale gas produced water. This water is currently managed through a variety of mechanisms, including underground injection, treatment and discharge, and recycling. New water treatment
technologies and new applications of existing technologies are being developed and used to treat
shale gas produced water for reuse in a variety of applications. This allows shale gas-associated
produced water to be viewed as a potential resource in its own right.
Some soils and geologic formations contain low levels of naturally occurring radioactive material
(NORM). When NORM is brought to the surface during shale gas drilling and production
operations, it remains in the rock pieces of the drill cuttings, remains in solution with produced
water, or, under certain conditions, precipitates out in scales or sludges. The radiation from this
NORM is weak and cannot penetrate dense materials such as the steel used in pipes and tanks.
Because the general public does not come into contact with gas field equipment for extended
periods, there is very little exposure risk from gas field NORM.
To protect gas field workers, OSHA requires employers to evaluate radiation hazards, post caution signs and provide personal protection equipment when radiation doses could exceed regulatory standards. Although regulations vary by state, in general, if NORM concentrations are less than regulatory standards, operators are allowed to dispose of the material by methods approved for standard gas field waste.
Conversely, if NORM concentrations are above regulatory limits, the material must be disposed of at a licensed facility. These regulations, standards, and practices ensure that shale gas operations present negligible risk to the general public and to workers with respect to potential NORM exposure.
Although natural gas offers a number of environmental benefits over other sources of energy,
particularly other fossil fuels, some air emissions commonly occur during exploration and
production activities. Emissions may include NOx, volatile organic compounds, particulate matter, SO2, and methane. EPA sets standards, monitors the ambient air across the U.S., and has an active enforcement program to control air emissions from all sources, including the shale gas industry. Gas field emissions are controlled and minimized through a combination of government regulation and voluntary avoidance, minimization, and mitigation strategies.
The primary differences between modern shale gas development and conventional natural gas
development are the extensive uses of horizontal drilling and high-volume hydraulic fracturing.
The use of horizontal drilling has not introduced any new environmental concerns. In fact, the
reduced number of horizontal wells needed coupled with the ability to drill multiple wells from a
single pad has significantly reduced surface disturbances and associated impacts to wildlife, dust , noise, and traffic. Where shale gas development has intersected with urban and industrial settings, regulators and industry have developed special practices to alleviate nuisance impacts, impacts to sensitive environmental resources, and interference with existing businesses.
Hydraulic fracturing has been a key technology in making shale gas an affordable addition to the Nation’s energy supply, and the technology has proved to be an effective stimulation technique. While some challenges exist with water availability and water management, innovative regional solutions are emerging that allow shale gas development to continue while ensuring that the water needs of other users are not affected and that surface and ground water quality is protected. Taken together, state and federal requirements along with the technologies and practices developed by industry serve to reduce environmental impacts from shale gas operations.
Saturday, February 21, 2009
An Excellent Summary Of Unconventional Gas (and oil) Plays In The US
The following is a well-written and fairly detailed summary of the status of so-called unconventional shale gas, (and some oil) plays taking place in the United States as of August, 2008. It seems the economic benefits of this activity is going relatively unnoticed, compared to all the emphasis on "green" energy. Green meaning solar, wind and geothermal energy. It does make one wonder who is controlling or influencing what the mainstream media reports.
Note, one of the keys to the success of these new plays is horizontal drilling, and of course, the interpretation of these horizontal wells. This kind of interpretation presents a totally new challenge to geologists and engineers, something that can not be taken lightly.
Peter
ARCHIVE August 2008
Vol. 229 No. 8
SPECIAL FOCUS: NORTH AMERICAN OUTLOOK- UNCONVENTIONAL RESOURCES
Unconventional plays grow in number after Barnett Shale blazed the way
The Haynesville and Marcellus are becoming exciting new gas plays, while activity in the Woodford and Fayetteville continues.
Katrina Boughal , Technical Editor (source)
Unconventional gas plays in the US have been booming since technological advances increased production in the now-famous Barnett Shale. Horizontal drilling and fracture stimulation in the shale source rock, as opposed to the sandstone/limestone/dolomite reservoir rock, have proved to be successful not only in gas plays like the Barnett, Fayetteville and Woodford, but also in the Bakken-a primarily oil-rich formation.
Resources that were previously thought to be unrecoverable are now being reassessed and, in some cases, rediscovered. Many shale plays have been producing a small amount of gas for years (the Indiana and Kentucky New Albany Shale since the late 1880s), but with the Barnett example, they are becoming more successful. Hot plays in the industry include the Louisiana/Texas Haynesville and Bossier Shales, and the Marcellus of Pennsylvania/Appalachia. The Williston Basin Bakken Formation has also gained popularity after a recent reassessment by the USGS.
HAYNESVILLE
The fairly recent Haynesville gas play, having garnered attention over the past few months, is an Upper Jurassic formation overlain by the Cotton Valley Group, and lies over the Smackover Formation. The Haynesville is an ultra-low permeability shale, and is focused in northwest Louisiana and East Texas, particularly in Caddo, Bossier and DeSoto Parishes, but also to a lesser extent in Red River and Sabine Parishes, and Harrison and Panola Counties, Fig. 1. The Haynesville Shale underlies the Bossier Shale (part of the Cotton Valley Group), and they are sometimes referred to as the same unit or related units. 2 Deeper than most shale gas plays, the Haynesville is located at depths ranging between 11,000 and 13,000 ft. 3
Fig. 1 . Map of the Haynesville Shale play (shaded). 1
Chesapeake is a large participant in the Haynesville play, holding about 550,000 acres as of late June 2008, with plans to acquire more acreage. Chesapeake entered a joint venture with Plains Exploration and Production, and the companies plan to drill about 600 wells in the Haynesville in the next three years. Chesapeake is estimating a mid-point estimated ultimate reserve of 6.5 Bcf, and their initial horizontal production rates are encouraging for the play.
“The initial production rates on the eight horizontal wells we have completed have ranged from 5 to 15 MMcfd on restricted chokes at flowing casing pressures of up to 6,500 psi,” said Chesapeake CEO Aubrey K. McClendon. 4
Petrohawk is also an active participant with about 275,000 acres, and completed their first horizontal well in the Haynesville in late June 2008. The Elm Grove Plantation #63, drilled in Bossier Parish, encountered about 212 ft of Haynesville Shale, and produced at a rate of 16.8 MMcfd. Completion of Elm Grove Plantation #63 included 11 stages of fracture stimulation. Petrohawk is drilling three horizontal wells, and expects to be operating six rigs in the Haynesville by mid-September 2008. 5
Companies are scrambling to lease plots in the Haynesville, with Forest Oil announcing in late June 2008 a net holding of 90,000 acres in the area. 6 GMX Resources added 7,300 net acres in early July, bringing its total acreage to 27,500. 7 EnCana has about 325,000 acres in the Haynesville, and completed a horizontal well in February with an initial production rate of 8 MMcfd. 8
FAYETTEVILLE
A few years ago the Fayetteville Shale experienced an upswing in interest somewhat akin to what the Haynesville is experiencing now. The Fayetteville of Arkansas is a Mississippian formation on the eastern end of the Arkoma Basin, with thicknesses varying between 50 and 300 ft and drilled at depths ranging from 2,000 to 6,000 ft. Thickness in the Fayetteville differs from east to west, at about 50 to 75 ft thick in western Arkansas to about 300 ft at the eastern edge of the Arkoma Basin. The formation is productive from its middle to base because the lower section is rich in organic material, with chert and siliceous interbedding. 9 The unit is thermally mature, and is differentiated from surrounding units by high radioactivity and resistivity signatures. 10
The Fayetteville is found in multiple eastern and central Arkansas counties, including Cleburne, Conway, Faulkner, Franklin, Jackson, St. Francis, Pope, Prairie, Van Buren, White and Woodruff Counties. The Fayetteville is about the same age and is seen as a geologic equivalent to the Barnett Shale near Fort Worth.
The Fayetteville followed the Barnett in production technology. As with other shale gas plays, the Fayetteville was previously known to be a gas-bearing formation, but only produced when horizontal drilling and fracture stimulation were introduced. 8 Some 460 of the over 500 producing wells in the Fayetteville are horizontal, and total production from the shale has reached, and likely exceeded, 52 Bcf. 11
Rig counts in the Arkansas Arkoma Basin have increased dramatically in the past two years. In August 2006, the rig count hovered at slightly over 20. In early July 2008, the count was at 59 operating rigs, with most located in Van Buren, White and Conway Counties. Southwestern Energy was operating 18 of the 59 rigs (about 31%) in the Arkansas Arkoma Basin during the first week of July 2008. 12 Southwestern, one of the most dominant players in the region, owns about 851,100 acres in the Fayetteville area, and has completed 557 wells in the play as of March 2008, of which about 88% were horizontal. During the company’s first quarter 2008, estimated 2007 production from the Fayetteville was 53.5 Bcf. 13
Chesapeake holds the largest land area in the play with 1.1 million acres, and in March 2008, had a net production of 130 MMcfd from the Fayetteville. Chesapeake had 12 rigs operating in March 2008, and plans to escalate drilling activity to 25 rigs in the play by early 2009. 14
MARCELLUS
In 2002, the USGS released an assessment of the undiscovered oil and gas in the Appalachian Basin Province. The Marcellus Shale was characterized as an individual assessment unit in the Appalachian Basin region that contained gas resources of about 1.9 Tcf. 15
The Marcellus had been fairly quiet until recently, when in late 2007 Range Resources announced horizontal well test rates from 1.4 MMcfd to 4.7 MMcfd. Shortly after, in January 2008, Pennsylvania State University and the University of New York at Fredonia released a report estimating recoverable reserves at 50 Tcf. Since then, The New York Times and USA Today have run stories on the Marcellus and the formation’s producing potential.
The Marcellus Shale is part of a large suite of rocks known as the Devonian shales, and stretches NE-SW about 600 mi across several Appalachian states, including New York, Pennsylvania and West Virginia, Fig. 2. 16 The naturally fractured, dry gas-producing Marcellus covers an area of about 54,000 square mi, 17 and ranges in thickness from 50 to 200 ft. Like the Fayetteville, the Marcellus thins from east to west, with 200-ft sections in northeastern Pennsylvania and 50-ft sections in northern West Virginia, Ohio, Pennsylvania and western New York. The formation depth ranges from 5,000 to 8,000 ft below sea level. 18
Fig. 2 . Map of the Marcellus and Devonian Shales. 16
The organic richness of the Marcellus, however, decreases generally from north in New York to south in West Virginia. The thermal maturity of the shale is an estimated 1.5 to 3% vitrinite reflectance (Ro). 18
As of April 2008, Range Resources held about 1.15 million acres of the Marcellus play, and had drilled 10 successful horizontal wells with initial production rates ranging from 2.6 to 5.8 MMcfd. 19 Other players in the Marcellus include Atlas Energy Resources and Chesapeake (largest lease holder with 1.2 million acres). Atlas, whose drilling plan is focused primarily in southwestern Pennsylvania, announced in February that it had 21 producing vertical wells, with 6 more due to be completed and producing shortly. 20
Marcellus players face the problem of minimal public information on the area, and have to resort to academic papers and regional geologic information due to the lack of log data. Oilfield services and equipment in the area are also somewhat scarce, with only four or six Appalachian rigs capable of drilling horizontal wells. 16
WOODFORD
Activity in the Woodford Shale began in 2003-2004 as a vertical play, but quickly transitioned to horizontal wells after the Barnett became horizontally driven. 21
The Woodford Shale is located in Oklahoma on the western end of the Arkoma Basin, and ranges in age from Middle Devonian to Early Mississippian. The stratigraphic equivalent to the Bakken and Antrim Shales, the Woodford shows a wide range of thermal maturities from 0.7 to 4.89% Ro?. Although known to be a gas-producing formation, the Woodford may have the potential to produce oil as well, 22 and the silica-rich shale has provided a good environment for fracturing due to its brittle nature. 21
The Woodford has seen many players in the area including Newfield Exploration, Devon, Chesapeake and XTO Energy. Newfield has about 165,000 net acres in the Woodford, is looking to drill about 100 horizontal wells this year and had a gross production of 165 MMcfd as of February 2008.23 Drilling depths for Newfield have ranged from 6,000 to 13,000 ft, with lateral lengths to about 5,000 ft. 21
For a more in-depth discussion on the characteristics and production potential of the Woodford Shale, please see page 83.
BARNETT
No unconventional play article would be complete without a mention of the Barnett. The very well-known Barnett Shale is the gas play that introduced horizontal drilling and fracture stimulation techniques to the unconventional shale gas field, allowing other plays’ production potential to be realized. Indeed, every time a new shale gas play is discovered, it is compared to the Barnett, or is called the “next Barnett” or a “baby Barnett.”
The Mississippian Barnett in the Fort Worth Basin of Texas is about 6,500 to 8,000 ft deep, and thickens toward the northeast-from about 30 to 50 ft thick in the south to about 1,000 ft thick in the northeast. 24
At the end of 2007, the total number of Barnett producing wells over time was at about 8,960, with cumulative production of 3.69 Tcf and 11.6 million bbl of oil. The rate of production from 8,435 active Barnett wells in December 2007 was 3.524 Bcfd plus 7,477 bpd. From 2003 to 2007, horizontal wells have become the dominant well orientation. In 2003, about 21% of wells completed in the Barnett were horizontal; in 2007, about 94% were horizontal. 25
The Barnett continues as the giant that it has become in the past five years. The players list in the Barnett is exhaustive, with Devon, Chesapeake, XTO, Encana, EOG and others. Devon has drilled more than 1,300 wells in the Barnett since 2002, and produces nearly 600 MMcfd. 26
BAKKEN
The April 2008 USGS assessment of the Bakken Formation in the Williston Basin has caused a flurry of activity in the area, particularly because of the undiscovered, technically recoverable oil resource estimation-between 3.0 and 4.3 billion bbl. The large increase in the Bakken’s recoverable resources (formerly estimated by the USGS at 151 million bbl in 1995) is due to the same factor that has lead to expanding shale gas plays: advances in horizontal drilling and hydraulic fracturing.
The Upper Devonian-Early Mississippian Bakken is a continuous, 200,000-sq mi formation composed of sandstone, siltstone and dolomite bounded by two shale layers. Average porosity in the Bakken is between 8% and 12%, and permeability ranges from 0.05 mD to 0.5 mD. The Bakken is about 2-mi deep, and has a net thickness of about 6 ft to 15 ft. Key players in the region include EOG Resources, Whiting Petroleum, Brigham Exploration, Hess, Newfield Exploration, XTO and Marathon. 27 For a more comprehensive view on the Bakken assessment, please see World Oil June 2008, page 83.
OTHER PLAYS
There are a multitude of unconventional shale plays being assessed, and the following are a few from various parts of the US.
Utica. Located in New York, northern Pennsylvania, Quebec and Ontario, the Utica Shale is an Upper Ordovician reservoir with typical low permeability, high organic content and varying thickness-the formation ranges from 150 to 1,000 ft across New York. The Utica’s close proximity to the Marcellus makes it interesting, but recently drilled Utica wells have “not responded well to the normal shale fracturing practices.” 28 Forest Oil has acquired 269,000 net acres of the Quebec Utica, and in April 2008, reported 1 MMcfd production rates from two 4,800-ft vertical wells. 29
Chattanooga.
This Devonian shale formation extends across a large part of the US, although the gas play is centered in southern Kentucky, eastern Tennessee and northern Alabama, Fig. 3. Sources cite the Chattanooga as being an equivalent to both the Marcellus and the Woodford Shales, all of which are Devonian formations. 30,31
Fig. 3 . Map of the Chattanooga Shale play (shaded). 30
The USGS reported in 2007 on the petroleum system of the Black Warrior Basin in Alabama and Mississippi that encompasses part of the Chattanooga Shale. The USGS report focused on the carbonates and sandstones, and discussed the Floyd and Chattanooga Shales as source rocks alone-no unconventional shale gas assessment was released. The Chattanooga is a Devonian-age shale that is separated from the Mississippian-age Floyd Shale by a thin layer of chert and limestone, and they are often referred in relation to each other. The Alabama Chattanooga play lies in the eastern Black Warrior Basin, and is a thin unit with a Total Organic Carbon (TOC) weight percent range of 2.4-12.7. 32 The Tennessee Chattanooga play is relatively shallow compared to other gas plays with depths ranging from 1,500 to 2,000 ft. 33
In 2007, CNX Gas Corp. drilled a horizontal well in Tennessee with an initial production rate of 3.9 MMcfd. 34 Atlas Energy Resources announced in June 2008 the successful drilling of four horizontal wells in the formation. 35
Floyd. In close contact with the Chattanooga Shale, the Floyd play is situated in the Black Warrior Basin of Mississippi and Alabama. The formation is primarily shale, but also contains clay, sandstone and limestone beds, with chert and large siderite modules. 32 Found at depths from about 4,000 ft to 9,000 ft below surface level, 36 the Floyd thickens toward the northeast, with a maximum thickness of about 600 ft, and has a TOC percent weight of about 1.8. The Floyd is believed to be the source rock for the conventional reservoirs in the area. 32 Carrizo Oil and Gas drilled a horizontal well in the Floyd in July 2007,37 and Murphy Oil drilled several wells in 2006. 38 With minimal news concerning the Floyd in 2008, play activity seems to have slowed down.
New Albany.
Found in the Illinois Basin, the New Albany Shale is a mostly Devonian-aged formation (the top few feet of the unit are Mississippian) that spans Kentucky, Indiana and, to a smaller extent, Illinois. The New Albany can be correlated with the Antrim Shale of Michigan and Indiana, and the Chattanooga Shale of Tennessee. 39 The New Albany gas play has been focused in Kentucky and southeastern Indiana. Formation thickness varies-the shale is about 100 to 140 ft thick in southeastern Indiana and almost 340 ft thick farther southwest in the Illinois Basin. 40 The USGS released a report in 2007 on the Illinois Basin that assessed the undiscovered, technically recoverable gas resources of the New Albany Shale at 3.79 Tcf. 41 Aurora Oil and Gas reported an average production of 424 Mcfd from their New Albany holdings in the first quarter 2008. 42 CNX Gas drilled six wells in the New Albany in 2007 to determine reservoir information and future drilling locations. 34
As the Barnett proves to be continually successful, shale plays, oil and gas, are looking to be important in the future.
There are already whispers of the Haynesville being the next Barnett, and although those rumors have been heard before about other plays, expect to hear about the Haynesville, and the Bakken and Marcellus, in the months to come.
LITERATURE CITED
1 “Core leasing area: Haynesville Shale map,” Haynesville Shale Map, http://haynesvilleshalemap.com/, accessed July 7, 2008.
2 Welborn, V., “What is the Haynesville Shale?” Shreveport Times , July 7, 2008.
3 “Shale gas fever drives land drilling in US,” Platts Oilgram News , July 4, 2008, pg. 6.
4 “Chesapeake and PXP announce Haynesville Shale joint venture,” Yahoo Financial News, July 1, 2008, http://bix.yahoo.com/bw/080701/20080701006524.html, accessed July 8, 2007.
5 “Petrohawk Energy Corporation reports Haynesville Shale result and leasehold update,” Fox Business, June 30, 2008, http://www.foxbusiness.com/story/markets/industries/energy/petrohawk-energy-corporation-reports-haynesville-shale-result-leasehold-update/, accessed July 8, 2008.
6 “Forest Oil increases holdings in E. Texas, N. La,” Forbes.com, June 30, 2008, http://www.forbes.com/feeds/ap/2008/06/30/ap5169765.html, accessed July 10, 2008.
7 “GMX Resources Inc. announces Haynesville/Bossier Shale drilling to begin 3Q08,” Prime Newswire, July 7, 2008, http://www.primenewswire.com/newsroom/news.html?d=145868, accessed July 10, 2008.
8 Fuquay, J., “Chesapeake, EnCana, boost activity in Louisiana gas shale,” Star-Telegram , June 16, 2008.
9 Brown, D., “Barnett may have Arkansas cousin,” AAPG Explorer , Feb. 2006.
10 “The Fayetteville Shale play: A geologic overview,” Arkansas Business.com, Aug. 27, 2007, http://www.arkansasbusiness.com/article.aspx?aID=99154, accessed July 8, 2008.
11 Shelby, P., “Fayetteville Shale play of North-Central Arkansas: A project update,” presented at the AAPG Annual Convention, San Antonio, Texas, April 20-23, 2008.
12 “Baker Hughes US rig count- Summary report,” Baker Hughes- Investor relations- Rig counts, http://164.109.37.157/Reports/StandardReport.aspx, accessed July 11, 2008.
13 “Fayetteville Shale play,” Southwestern Energy Company, http://www.swn.com/operations/fayetteville.shale.asp, accessed July 8, 2008.
14 “Chesapeake reports Haynesville Shale discovery in Louisiana and announces CapEx increase,” OilVoice, March 24, 2008, http://www.oilvoice.com/n/Chesapeake_Reports_Haynesville_Shale_Discovery_in_Louisiana_and_Announces_CapEx_Increase/92f01da5.aspx, accessed July 11, 2008.
15 US Department of the Interior, US Geological Society, “Assessment of undiscovered oil and gas resources of the Appalachian Basin Province, 2002,” USGS Fact Sheet FS-009-03, February 2003.
16 Durham, L. S., “Another shale making seismic waves,” AAPG Explorer, March 2008.
17 Mayhood, K., “Low down, rich and stingy,” The Columbus Dispatch , March 11, 2008.
18 Milici, R. C. and C. S. Swezey, “Assessment of Appalachian Basin oil and gas resources: Devonian Shale- Middle and Upper Paleozoic total petroleum system,” Open file report series 2006-1237, USGS Reston, Virginia, 2006, pp.38-39.
19 “Range announces record first quarter results,” OilVoice, April 24, 2008, http://www.oilvoice.com/n/Range_Announces_Record_First_Quarter_Results/4c59a7ac.aspx, accessed July 11, 2008.
20 “Atlas Energy Resources, LLC increases estimated reserve potential from Marcellus Shale to between 4 and 6 Tcf,” Reuters, Feb. 21, 2008, http://www.reuters.com/article/pressRelease/idUS127932+21-Feb-2008+MW20080221, accessed July 14, 2008.
21 Brown, D., “Big potential boost the Woodford,” AAPG Explorer , July 2008.
22 Comer, J. B., “Reservoir characteristics and production potential of the Woodford Shale,” World Oil , August 2008, pp. 83.
23 “Newfield Exploration announces 2008 capital program,” Reuters, Feb. 4, 2008, http://www.reuters.com/article/pressRelease/idUS139442+04-Feb-2008+PRN20080204, accessed July 11, 2008.
24 Hayden, J. and D. Pursell, “The Barnett Shale: Visitors guide to the hottest gas play in the US,” Tudor Pickering, Oct. 2005, http://www.tudorpickering.com/pdfs/TheBarnettShaleReport.pdf, accessed July 10, 2008.
25 “Number of vertical and horizontal producer wells in the Barnett Shale as of Jan. 1, 2008,” Powell Barnett Shale Newsletter , March 27, 2008, http://www.barnetshalenews.com/documents/VHchart%201-1-08.pdf, accessed July 10, 2008. 26 “Operations- Barnett Shale,” Devon Energy, http://www.devonenergy.com/Operation/FeatuerStories/Pages/barnett_shale.aspx, accessed July 10, 2008.
27 Cohen, D. M., “USGS names Bakken play the largest oil accumulation in the Lower 48,” World Oil , June 2008, pp. 83-84.
28 Paktinat, J., Pinkhouse, J., Fontaine, J., Lash, G. and G. Penny, “Investigation of methods to improve Utica Shale hydraulic fracturing in the Appalachian Basin,” presented at the AAPG Annual Convention, San Antonio, Texas, April 20-23, 2008.
29 “Forest Oil announces significant gas discovery in Utica Shale…” Reuters, April 1, 2008, http://www.reuters.com/article/pressRelease/idUS134787+01-Apr-2008+BW20080401, accessed July 11, 2008.
30 “Chattanooga Shale natural gas field,” Oil Shale Gas, http://www.oilshalegas.com/chattanoogashale.com, accessed July 9, 2008.
31 “AMI Project,” Irvine Energy PLC, http://www.irvineenergy.com/projects/index.htm, accessed July 9, 2008.
32 USGS Black Warrior Basin Province assessment team, “Geologic assessment of undiscovered oil and gas resources of the Black Warrior Basin Province, Alabama and Mississippi,” Hatch, J. R. and M. J. Pawlewicz, compilers, USGS Digital Data Series DDS-69-I, 2007, 76 p.
33 “Domestic Energy announces Appalachian Shale plan,” Reuters, April 28, 2008, http://www.reuters.com/article/preeRelease/idUS139048+28-Apr-2008+MW20080428, accessed July 9, 2008.
34 “CNX Gas reports fourth quarter and full year 2007 results,” Reuters, Jan. 29, 2008, http://www.reuters.com/article/pressRelease/idUS140410+29-Jan-2008+PRN20080129, accessed July 11, 2008.
35 “Atlas Energy announces four successful horizontal wells in Tennessee’s Chattanooga Shale, and a net acreage position of 105,000 acres in the play,” OilVoice, June 21, 2008, http://www.oilvoice.com/n/Atlas_Energy_Announces_Four_Successful_Horizontal_Wells_in_Tennessees_Chattanooga_Shale/9fc6bbe0.aspx, accessed July 9, 2008.
36 “Floyd Shale potential of the Black Warrior Basin: Executive summary,” Mississippi Geological Society eBulletin , Vol. 55, No. 7, March 2007.
37 “Carrizo Oil & Gas, Inc. announces record production and third quarter 2007 financial results,” Carrizo Oil & Gas, Nov. 8, 2007, http://carrizo.mediaroom.com/index.php?s=43&iten=154, accessed July 10, 2008.
38 Edmonds, C., “New shales may be ready to deliver,” The Street, Feb. 22, 2007, http://www.thestreet.com/story/10340267/1/new-shales-may-be-ready-to-deliver.html, accessed July 10, 2008.
39 “New Albany Shale,” Indiana Geological Survey, http://igs.indiana.edu/Geology/structure/compendium/html/comp82hw.cfm, accessed July 9, 2008.
40 Comer, J. B., Hasenmueller, N. R., Mastalerz, M. D., Rupp, J. A., Shaffer, N. R. and C. W. Zuppann, “The New Albany Shale gas play in southern Indiana,” presented at AAPG Eastern Section Meeting, Buffalo, N.Y., Oct. 8-11, 2006.
41 US Department of the Interior, US Geological Survey, “Assessment of undiscovered oil and gas resources of the Illinois Basin, 2007,” USGS Fact Sheet 2007-3058, August 2007.
42 “Aurora Oil & Gas Corp. announces first quarter 2008 results,” Reuters, May 9, 2008, http://www.reuters.com/article/pressRelease/idUS248894+09-May-2008+PRN20080509, accessed July 11, 2008.
Note, one of the keys to the success of these new plays is horizontal drilling, and of course, the interpretation of these horizontal wells. This kind of interpretation presents a totally new challenge to geologists and engineers, something that can not be taken lightly.
Peter
ARCHIVE August 2008
Vol. 229 No. 8
SPECIAL FOCUS: NORTH AMERICAN OUTLOOK- UNCONVENTIONAL RESOURCES
Unconventional plays grow in number after Barnett Shale blazed the way
The Haynesville and Marcellus are becoming exciting new gas plays, while activity in the Woodford and Fayetteville continues.
Katrina Boughal , Technical Editor (source)
Unconventional gas plays in the US have been booming since technological advances increased production in the now-famous Barnett Shale. Horizontal drilling and fracture stimulation in the shale source rock, as opposed to the sandstone/limestone/dolomite reservoir rock, have proved to be successful not only in gas plays like the Barnett, Fayetteville and Woodford, but also in the Bakken-a primarily oil-rich formation.
Resources that were previously thought to be unrecoverable are now being reassessed and, in some cases, rediscovered. Many shale plays have been producing a small amount of gas for years (the Indiana and Kentucky New Albany Shale since the late 1880s), but with the Barnett example, they are becoming more successful. Hot plays in the industry include the Louisiana/Texas Haynesville and Bossier Shales, and the Marcellus of Pennsylvania/Appalachia. The Williston Basin Bakken Formation has also gained popularity after a recent reassessment by the USGS.
HAYNESVILLE
The fairly recent Haynesville gas play, having garnered attention over the past few months, is an Upper Jurassic formation overlain by the Cotton Valley Group, and lies over the Smackover Formation. The Haynesville is an ultra-low permeability shale, and is focused in northwest Louisiana and East Texas, particularly in Caddo, Bossier and DeSoto Parishes, but also to a lesser extent in Red River and Sabine Parishes, and Harrison and Panola Counties, Fig. 1. The Haynesville Shale underlies the Bossier Shale (part of the Cotton Valley Group), and they are sometimes referred to as the same unit or related units. 2 Deeper than most shale gas plays, the Haynesville is located at depths ranging between 11,000 and 13,000 ft. 3
Fig. 1 . Map of the Haynesville Shale play (shaded). 1Chesapeake is a large participant in the Haynesville play, holding about 550,000 acres as of late June 2008, with plans to acquire more acreage. Chesapeake entered a joint venture with Plains Exploration and Production, and the companies plan to drill about 600 wells in the Haynesville in the next three years. Chesapeake is estimating a mid-point estimated ultimate reserve of 6.5 Bcf, and their initial horizontal production rates are encouraging for the play.
“The initial production rates on the eight horizontal wells we have completed have ranged from 5 to 15 MMcfd on restricted chokes at flowing casing pressures of up to 6,500 psi,” said Chesapeake CEO Aubrey K. McClendon. 4
Petrohawk is also an active participant with about 275,000 acres, and completed their first horizontal well in the Haynesville in late June 2008. The Elm Grove Plantation #63, drilled in Bossier Parish, encountered about 212 ft of Haynesville Shale, and produced at a rate of 16.8 MMcfd. Completion of Elm Grove Plantation #63 included 11 stages of fracture stimulation. Petrohawk is drilling three horizontal wells, and expects to be operating six rigs in the Haynesville by mid-September 2008. 5
Companies are scrambling to lease plots in the Haynesville, with Forest Oil announcing in late June 2008 a net holding of 90,000 acres in the area. 6 GMX Resources added 7,300 net acres in early July, bringing its total acreage to 27,500. 7 EnCana has about 325,000 acres in the Haynesville, and completed a horizontal well in February with an initial production rate of 8 MMcfd. 8
FAYETTEVILLE
A few years ago the Fayetteville Shale experienced an upswing in interest somewhat akin to what the Haynesville is experiencing now. The Fayetteville of Arkansas is a Mississippian formation on the eastern end of the Arkoma Basin, with thicknesses varying between 50 and 300 ft and drilled at depths ranging from 2,000 to 6,000 ft. Thickness in the Fayetteville differs from east to west, at about 50 to 75 ft thick in western Arkansas to about 300 ft at the eastern edge of the Arkoma Basin. The formation is productive from its middle to base because the lower section is rich in organic material, with chert and siliceous interbedding. 9 The unit is thermally mature, and is differentiated from surrounding units by high radioactivity and resistivity signatures. 10
The Fayetteville is found in multiple eastern and central Arkansas counties, including Cleburne, Conway, Faulkner, Franklin, Jackson, St. Francis, Pope, Prairie, Van Buren, White and Woodruff Counties. The Fayetteville is about the same age and is seen as a geologic equivalent to the Barnett Shale near Fort Worth.
The Fayetteville followed the Barnett in production technology. As with other shale gas plays, the Fayetteville was previously known to be a gas-bearing formation, but only produced when horizontal drilling and fracture stimulation were introduced. 8 Some 460 of the over 500 producing wells in the Fayetteville are horizontal, and total production from the shale has reached, and likely exceeded, 52 Bcf. 11
Rig counts in the Arkansas Arkoma Basin have increased dramatically in the past two years. In August 2006, the rig count hovered at slightly over 20. In early July 2008, the count was at 59 operating rigs, with most located in Van Buren, White and Conway Counties. Southwestern Energy was operating 18 of the 59 rigs (about 31%) in the Arkansas Arkoma Basin during the first week of July 2008. 12 Southwestern, one of the most dominant players in the region, owns about 851,100 acres in the Fayetteville area, and has completed 557 wells in the play as of March 2008, of which about 88% were horizontal. During the company’s first quarter 2008, estimated 2007 production from the Fayetteville was 53.5 Bcf. 13
Chesapeake holds the largest land area in the play with 1.1 million acres, and in March 2008, had a net production of 130 MMcfd from the Fayetteville. Chesapeake had 12 rigs operating in March 2008, and plans to escalate drilling activity to 25 rigs in the play by early 2009. 14
MARCELLUS
In 2002, the USGS released an assessment of the undiscovered oil and gas in the Appalachian Basin Province. The Marcellus Shale was characterized as an individual assessment unit in the Appalachian Basin region that contained gas resources of about 1.9 Tcf. 15
The Marcellus had been fairly quiet until recently, when in late 2007 Range Resources announced horizontal well test rates from 1.4 MMcfd to 4.7 MMcfd. Shortly after, in January 2008, Pennsylvania State University and the University of New York at Fredonia released a report estimating recoverable reserves at 50 Tcf. Since then, The New York Times and USA Today have run stories on the Marcellus and the formation’s producing potential.
The Marcellus Shale is part of a large suite of rocks known as the Devonian shales, and stretches NE-SW about 600 mi across several Appalachian states, including New York, Pennsylvania and West Virginia, Fig. 2. 16 The naturally fractured, dry gas-producing Marcellus covers an area of about 54,000 square mi, 17 and ranges in thickness from 50 to 200 ft. Like the Fayetteville, the Marcellus thins from east to west, with 200-ft sections in northeastern Pennsylvania and 50-ft sections in northern West Virginia, Ohio, Pennsylvania and western New York. The formation depth ranges from 5,000 to 8,000 ft below sea level. 18
Fig. 2 . Map of the Marcellus and Devonian Shales. 16The organic richness of the Marcellus, however, decreases generally from north in New York to south in West Virginia. The thermal maturity of the shale is an estimated 1.5 to 3% vitrinite reflectance (Ro). 18
As of April 2008, Range Resources held about 1.15 million acres of the Marcellus play, and had drilled 10 successful horizontal wells with initial production rates ranging from 2.6 to 5.8 MMcfd. 19 Other players in the Marcellus include Atlas Energy Resources and Chesapeake (largest lease holder with 1.2 million acres). Atlas, whose drilling plan is focused primarily in southwestern Pennsylvania, announced in February that it had 21 producing vertical wells, with 6 more due to be completed and producing shortly. 20
Marcellus players face the problem of minimal public information on the area, and have to resort to academic papers and regional geologic information due to the lack of log data. Oilfield services and equipment in the area are also somewhat scarce, with only four or six Appalachian rigs capable of drilling horizontal wells. 16
WOODFORD
Activity in the Woodford Shale began in 2003-2004 as a vertical play, but quickly transitioned to horizontal wells after the Barnett became horizontally driven. 21
The Woodford Shale is located in Oklahoma on the western end of the Arkoma Basin, and ranges in age from Middle Devonian to Early Mississippian. The stratigraphic equivalent to the Bakken and Antrim Shales, the Woodford shows a wide range of thermal maturities from 0.7 to 4.89% Ro?. Although known to be a gas-producing formation, the Woodford may have the potential to produce oil as well, 22 and the silica-rich shale has provided a good environment for fracturing due to its brittle nature. 21
The Woodford has seen many players in the area including Newfield Exploration, Devon, Chesapeake and XTO Energy. Newfield has about 165,000 net acres in the Woodford, is looking to drill about 100 horizontal wells this year and had a gross production of 165 MMcfd as of February 2008.23 Drilling depths for Newfield have ranged from 6,000 to 13,000 ft, with lateral lengths to about 5,000 ft. 21
For a more in-depth discussion on the characteristics and production potential of the Woodford Shale, please see page 83.
BARNETT
No unconventional play article would be complete without a mention of the Barnett. The very well-known Barnett Shale is the gas play that introduced horizontal drilling and fracture stimulation techniques to the unconventional shale gas field, allowing other plays’ production potential to be realized. Indeed, every time a new shale gas play is discovered, it is compared to the Barnett, or is called the “next Barnett” or a “baby Barnett.”
The Mississippian Barnett in the Fort Worth Basin of Texas is about 6,500 to 8,000 ft deep, and thickens toward the northeast-from about 30 to 50 ft thick in the south to about 1,000 ft thick in the northeast. 24
At the end of 2007, the total number of Barnett producing wells over time was at about 8,960, with cumulative production of 3.69 Tcf and 11.6 million bbl of oil. The rate of production from 8,435 active Barnett wells in December 2007 was 3.524 Bcfd plus 7,477 bpd. From 2003 to 2007, horizontal wells have become the dominant well orientation. In 2003, about 21% of wells completed in the Barnett were horizontal; in 2007, about 94% were horizontal. 25
The Barnett continues as the giant that it has become in the past five years. The players list in the Barnett is exhaustive, with Devon, Chesapeake, XTO, Encana, EOG and others. Devon has drilled more than 1,300 wells in the Barnett since 2002, and produces nearly 600 MMcfd. 26
BAKKEN
The April 2008 USGS assessment of the Bakken Formation in the Williston Basin has caused a flurry of activity in the area, particularly because of the undiscovered, technically recoverable oil resource estimation-between 3.0 and 4.3 billion bbl. The large increase in the Bakken’s recoverable resources (formerly estimated by the USGS at 151 million bbl in 1995) is due to the same factor that has lead to expanding shale gas plays: advances in horizontal drilling and hydraulic fracturing.
The Upper Devonian-Early Mississippian Bakken is a continuous, 200,000-sq mi formation composed of sandstone, siltstone and dolomite bounded by two shale layers. Average porosity in the Bakken is between 8% and 12%, and permeability ranges from 0.05 mD to 0.5 mD. The Bakken is about 2-mi deep, and has a net thickness of about 6 ft to 15 ft. Key players in the region include EOG Resources, Whiting Petroleum, Brigham Exploration, Hess, Newfield Exploration, XTO and Marathon. 27 For a more comprehensive view on the Bakken assessment, please see World Oil June 2008, page 83.
OTHER PLAYS
There are a multitude of unconventional shale plays being assessed, and the following are a few from various parts of the US.
Utica. Located in New York, northern Pennsylvania, Quebec and Ontario, the Utica Shale is an Upper Ordovician reservoir with typical low permeability, high organic content and varying thickness-the formation ranges from 150 to 1,000 ft across New York. The Utica’s close proximity to the Marcellus makes it interesting, but recently drilled Utica wells have “not responded well to the normal shale fracturing practices.” 28 Forest Oil has acquired 269,000 net acres of the Quebec Utica, and in April 2008, reported 1 MMcfd production rates from two 4,800-ft vertical wells. 29
Chattanooga.
This Devonian shale formation extends across a large part of the US, although the gas play is centered in southern Kentucky, eastern Tennessee and northern Alabama, Fig. 3. Sources cite the Chattanooga as being an equivalent to both the Marcellus and the Woodford Shales, all of which are Devonian formations. 30,31
Fig. 3 . Map of the Chattanooga Shale play (shaded). 30
The USGS reported in 2007 on the petroleum system of the Black Warrior Basin in Alabama and Mississippi that encompasses part of the Chattanooga Shale. The USGS report focused on the carbonates and sandstones, and discussed the Floyd and Chattanooga Shales as source rocks alone-no unconventional shale gas assessment was released. The Chattanooga is a Devonian-age shale that is separated from the Mississippian-age Floyd Shale by a thin layer of chert and limestone, and they are often referred in relation to each other. The Alabama Chattanooga play lies in the eastern Black Warrior Basin, and is a thin unit with a Total Organic Carbon (TOC) weight percent range of 2.4-12.7. 32 The Tennessee Chattanooga play is relatively shallow compared to other gas plays with depths ranging from 1,500 to 2,000 ft. 33
In 2007, CNX Gas Corp. drilled a horizontal well in Tennessee with an initial production rate of 3.9 MMcfd. 34 Atlas Energy Resources announced in June 2008 the successful drilling of four horizontal wells in the formation. 35
Floyd. In close contact with the Chattanooga Shale, the Floyd play is situated in the Black Warrior Basin of Mississippi and Alabama. The formation is primarily shale, but also contains clay, sandstone and limestone beds, with chert and large siderite modules. 32 Found at depths from about 4,000 ft to 9,000 ft below surface level, 36 the Floyd thickens toward the northeast, with a maximum thickness of about 600 ft, and has a TOC percent weight of about 1.8. The Floyd is believed to be the source rock for the conventional reservoirs in the area. 32 Carrizo Oil and Gas drilled a horizontal well in the Floyd in July 2007,37 and Murphy Oil drilled several wells in 2006. 38 With minimal news concerning the Floyd in 2008, play activity seems to have slowed down.
New Albany.
Found in the Illinois Basin, the New Albany Shale is a mostly Devonian-aged formation (the top few feet of the unit are Mississippian) that spans Kentucky, Indiana and, to a smaller extent, Illinois. The New Albany can be correlated with the Antrim Shale of Michigan and Indiana, and the Chattanooga Shale of Tennessee. 39 The New Albany gas play has been focused in Kentucky and southeastern Indiana. Formation thickness varies-the shale is about 100 to 140 ft thick in southeastern Indiana and almost 340 ft thick farther southwest in the Illinois Basin. 40 The USGS released a report in 2007 on the Illinois Basin that assessed the undiscovered, technically recoverable gas resources of the New Albany Shale at 3.79 Tcf. 41 Aurora Oil and Gas reported an average production of 424 Mcfd from their New Albany holdings in the first quarter 2008. 42 CNX Gas drilled six wells in the New Albany in 2007 to determine reservoir information and future drilling locations. 34
As the Barnett proves to be continually successful, shale plays, oil and gas, are looking to be important in the future.
There are already whispers of the Haynesville being the next Barnett, and although those rumors have been heard before about other plays, expect to hear about the Haynesville, and the Bakken and Marcellus, in the months to come.
LITERATURE CITED
1 “Core leasing area: Haynesville Shale map,” Haynesville Shale Map, http://haynesvilleshalemap.com/, accessed July 7, 2008.
2 Welborn, V., “What is the Haynesville Shale?” Shreveport Times , July 7, 2008.
3 “Shale gas fever drives land drilling in US,” Platts Oilgram News , July 4, 2008, pg. 6.
4 “Chesapeake and PXP announce Haynesville Shale joint venture,” Yahoo Financial News, July 1, 2008, http://bix.yahoo.com/bw/080701/20080701006524.html, accessed July 8, 2007.
5 “Petrohawk Energy Corporation reports Haynesville Shale result and leasehold update,” Fox Business, June 30, 2008, http://www.foxbusiness.com/story/markets/industries/energy/petrohawk-energy-corporation-reports-haynesville-shale-result-leasehold-update/, accessed July 8, 2008.
6 “Forest Oil increases holdings in E. Texas, N. La,” Forbes.com, June 30, 2008, http://www.forbes.com/feeds/ap/2008/06/30/ap5169765.html, accessed July 10, 2008.
7 “GMX Resources Inc. announces Haynesville/Bossier Shale drilling to begin 3Q08,” Prime Newswire, July 7, 2008, http://www.primenewswire.com/newsroom/news.html?d=145868, accessed July 10, 2008.
8 Fuquay, J., “Chesapeake, EnCana, boost activity in Louisiana gas shale,” Star-Telegram , June 16, 2008.
9 Brown, D., “Barnett may have Arkansas cousin,” AAPG Explorer , Feb. 2006.
10 “The Fayetteville Shale play: A geologic overview,” Arkansas Business.com, Aug. 27, 2007, http://www.arkansasbusiness.com/article.aspx?aID=99154, accessed July 8, 2008.
11 Shelby, P., “Fayetteville Shale play of North-Central Arkansas: A project update,” presented at the AAPG Annual Convention, San Antonio, Texas, April 20-23, 2008.
12 “Baker Hughes US rig count- Summary report,” Baker Hughes- Investor relations- Rig counts, http://164.109.37.157/Reports/StandardReport.aspx, accessed July 11, 2008.
13 “Fayetteville Shale play,” Southwestern Energy Company, http://www.swn.com/operations/fayetteville.shale.asp, accessed July 8, 2008.
14 “Chesapeake reports Haynesville Shale discovery in Louisiana and announces CapEx increase,” OilVoice, March 24, 2008, http://www.oilvoice.com/n/Chesapeake_Reports_Haynesville_Shale_Discovery_in_Louisiana_and_Announces_CapEx_Increase/92f01da5.aspx, accessed July 11, 2008.
15 US Department of the Interior, US Geological Society, “Assessment of undiscovered oil and gas resources of the Appalachian Basin Province, 2002,” USGS Fact Sheet FS-009-03, February 2003.
16 Durham, L. S., “Another shale making seismic waves,” AAPG Explorer, March 2008.
17 Mayhood, K., “Low down, rich and stingy,” The Columbus Dispatch , March 11, 2008.
18 Milici, R. C. and C. S. Swezey, “Assessment of Appalachian Basin oil and gas resources: Devonian Shale- Middle and Upper Paleozoic total petroleum system,” Open file report series 2006-1237, USGS Reston, Virginia, 2006, pp.38-39.
19 “Range announces record first quarter results,” OilVoice, April 24, 2008, http://www.oilvoice.com/n/Range_Announces_Record_First_Quarter_Results/4c59a7ac.aspx, accessed July 11, 2008.
20 “Atlas Energy Resources, LLC increases estimated reserve potential from Marcellus Shale to between 4 and 6 Tcf,” Reuters, Feb. 21, 2008, http://www.reuters.com/article/pressRelease/idUS127932+21-Feb-2008+MW20080221, accessed July 14, 2008.
21 Brown, D., “Big potential boost the Woodford,” AAPG Explorer , July 2008.
22 Comer, J. B., “Reservoir characteristics and production potential of the Woodford Shale,” World Oil , August 2008, pp. 83.
23 “Newfield Exploration announces 2008 capital program,” Reuters, Feb. 4, 2008, http://www.reuters.com/article/pressRelease/idUS139442+04-Feb-2008+PRN20080204, accessed July 11, 2008.
24 Hayden, J. and D. Pursell, “The Barnett Shale: Visitors guide to the hottest gas play in the US,” Tudor Pickering, Oct. 2005, http://www.tudorpickering.com/pdfs/TheBarnettShaleReport.pdf, accessed July 10, 2008.
25 “Number of vertical and horizontal producer wells in the Barnett Shale as of Jan. 1, 2008,” Powell Barnett Shale Newsletter , March 27, 2008, http://www.barnetshalenews.com/documents/VHchart%201-1-08.pdf, accessed July 10, 2008. 26 “Operations- Barnett Shale,” Devon Energy, http://www.devonenergy.com/Operation/FeatuerStories/Pages/barnett_shale.aspx, accessed July 10, 2008.
27 Cohen, D. M., “USGS names Bakken play the largest oil accumulation in the Lower 48,” World Oil , June 2008, pp. 83-84.
28 Paktinat, J., Pinkhouse, J., Fontaine, J., Lash, G. and G. Penny, “Investigation of methods to improve Utica Shale hydraulic fracturing in the Appalachian Basin,” presented at the AAPG Annual Convention, San Antonio, Texas, April 20-23, 2008.
29 “Forest Oil announces significant gas discovery in Utica Shale…” Reuters, April 1, 2008, http://www.reuters.com/article/pressRelease/idUS134787+01-Apr-2008+BW20080401, accessed July 11, 2008.
30 “Chattanooga Shale natural gas field,” Oil Shale Gas, http://www.oilshalegas.com/chattanoogashale.com, accessed July 9, 2008.
31 “AMI Project,” Irvine Energy PLC, http://www.irvineenergy.com/projects/index.htm, accessed July 9, 2008.
32 USGS Black Warrior Basin Province assessment team, “Geologic assessment of undiscovered oil and gas resources of the Black Warrior Basin Province, Alabama and Mississippi,” Hatch, J. R. and M. J. Pawlewicz, compilers, USGS Digital Data Series DDS-69-I, 2007, 76 p.
33 “Domestic Energy announces Appalachian Shale plan,” Reuters, April 28, 2008, http://www.reuters.com/article/preeRelease/idUS139048+28-Apr-2008+MW20080428, accessed July 9, 2008.
34 “CNX Gas reports fourth quarter and full year 2007 results,” Reuters, Jan. 29, 2008, http://www.reuters.com/article/pressRelease/idUS140410+29-Jan-2008+PRN20080129, accessed July 11, 2008.
35 “Atlas Energy announces four successful horizontal wells in Tennessee’s Chattanooga Shale, and a net acreage position of 105,000 acres in the play,” OilVoice, June 21, 2008, http://www.oilvoice.com/n/Atlas_Energy_Announces_Four_Successful_Horizontal_Wells_in_Tennessees_Chattanooga_Shale/9fc6bbe0.aspx, accessed July 9, 2008.
36 “Floyd Shale potential of the Black Warrior Basin: Executive summary,” Mississippi Geological Society eBulletin , Vol. 55, No. 7, March 2007.
37 “Carrizo Oil & Gas, Inc. announces record production and third quarter 2007 financial results,” Carrizo Oil & Gas, Nov. 8, 2007, http://carrizo.mediaroom.com/index.php?s=43&iten=154, accessed July 10, 2008.
38 Edmonds, C., “New shales may be ready to deliver,” The Street, Feb. 22, 2007, http://www.thestreet.com/story/10340267/1/new-shales-may-be-ready-to-deliver.html, accessed July 10, 2008.
39 “New Albany Shale,” Indiana Geological Survey, http://igs.indiana.edu/Geology/structure/compendium/html/comp82hw.cfm, accessed July 9, 2008.
40 Comer, J. B., Hasenmueller, N. R., Mastalerz, M. D., Rupp, J. A., Shaffer, N. R. and C. W. Zuppann, “The New Albany Shale gas play in southern Indiana,” presented at AAPG Eastern Section Meeting, Buffalo, N.Y., Oct. 8-11, 2006.
41 US Department of the Interior, US Geological Survey, “Assessment of undiscovered oil and gas resources of the Illinois Basin, 2007,” USGS Fact Sheet 2007-3058, August 2007.
42 “Aurora Oil & Gas Corp. announces first quarter 2008 results,” Reuters, May 9, 2008, http://www.reuters.com/article/pressRelease/idUS248894+09-May-2008+PRN20080509, accessed July 11, 2008.
Friday, February 20, 2009
Petrohawk: A Very Successful Producer In Shale Gas Plays
Consider the following facts and figures. The numbers of wells drilled, their success rate, and production rates all demonstrate a very skilled operation. The follwing comes from Petrohawk's own website here.
Peter
Petrohawk Provides Fourth Quarter Operational Update (2008)
Final Proved Reserves up 34% Year Over Year at 1.42 Tcfe, 419% of Production Replaced Haynesville Shale Gross Operated Production Reaches 160 Mmcfe/d
HOUSTON, Feb. 3 /PRNewswire-FirstCall/ -- Petrohawk Energy Corporation ("Petrohawk" or the "Company") (NYSE: HK) provided its fourth quarter 2008 operational update, including additional drilling results in the Haynesville Shale and proved reserves for year-end 2008.
During the fourth quarter, Petrohawk drilled 218 wells, with a success rate of 98%. On average, 32 operated rigs and 15 non-operated rigs were running during the quarter, including a combination of spudder rigs and horizontal rigs in both the Haynesville Shale and Fayetteville Shale development programs. For 2008, Petrohawk drilled 739 total wells, also with a success rate of 98%.
Production for the fourth quarter was approximately 361 million cubic feet of natural gas equivalent (Mmcfe/d), a 15% quarter over quarter increase and a 52% increase over fourth quarter 2007, on a pro forma basis. Petrohawk exited the quarter producing approximately 400 Mmcfe/d. Full year 2008 production was approximately 305 Mmcfe/d.
strong>Haynesville Shale
Petrohawk recently placed four additional wells online utilizing production practices consistent with previously reported wells. The initial production rates of these wells averaged 17.7 Mmcfe/d, detailed as follows:
The Mack Hogan #4 (Bossier Parish, Section 3, 16N, 11W) had an initial production rate of 13.4 Mmcfe/d on a 24/64" choke with 6,350# flowing casing pressure.
The Osborne 8 #3H (Bossier Parish, Section 8, 16N, 11W) had an initial production rate of 18.8 Mmcfe/d on a 24/64" choke with 6,800# flowing casing pressure.
The Roos "A" #5 (Bossier Parish, Section 3, 16N, 11W) had an initial production rate of 15.1 Mmcfe/d on a 24/64" choke with 6,100# flowing casing pressure.
The Griffith 11 #1 (DeSoto Parish, Section 11, 13N, 14W) had an initial production rate of 23.3 Mmcfe/d on a 28/64" choke with 7,550# flowing casing pressure. This well is a significant step-out to the southwest from existing completions.
Two Haynesville Shale completions, the Sample 4 #1 and the R.E. Smith Jr. 32 #1, experienced mechanical problems that resulted in lower than expected initial production rates. On the Sample 4 #1, a valve malfunctioned following completion, causing casing damage in the lateral portion of the well. The Company elected to produce the well on a 12/64" choke as a precaution against further wellbore damage. This well had an initial production rate of 5.4 Mmcfe/d with 7,020# flowing casing pressure. The R.E. Smith Jr. 32 #1 screened out halfway through completion due to the inadvertent firing of a perforating gun in the curve of the lateral. With only six stages of fracture stimulation, this well had an initial production rate of 11.1 Mmcfe/d on a 20/64" choke with 5,900# flowing casing pressure.
The Company is currently producing approximately 160 Mmcfe/d gross from the Haynesville Shale with 16 operated wells on production. Eleven operated wells have been on production 30 days or more, averaging 15.2 Mmcfe/d over their first 30 days of production. Eight operated wells have been on production 60 days or more, averaging 13.2 Mmcfe/d over their first 60 days of production. The four wells on production greater than 90 days have averaged 8.8 Mmcfe/d over their first 90 days of production. All operated wells to date have been produced utilizing similar production practices. During 2009, Petrohawk will conduct a pilot program on certain wells whereby production practices will be altered to restrict production by utilizing smaller choke sizes. The Company will monitor this subset of wells for effects on decline rate and mechanical operation.
Petrohawk's current drilling and completion methodology focuses on completing wells with longer laterals and maximizing the number of frac stages, spaced approximately 325 feet apart. The objective of this technique is to minimize the total number of wells required to effectively drain the reservoir, resulting in lower overall development costs. The Company is currently targeting lateral lengths between 4,300' and 4,600' with up to 15 frac stages. Petrohawk's first four completions averaged 3,339' in lateral length with 10 frac stages while the last twelve completions have averaged 3,958' in lateral length and 12 stages (with the exception of the R.E. Smith Jr 32 #3, which had down hole mechanical issues and only six frac stages).
During 2008, the Company utilized a "pre-drill" program whereby smaller, "spudder" rigs drilled the vertical portion of the wellbore in advance of horizontal rigs moving in to drill the lateral. At year end 2008, Petrohawk had eleven operated horizontal rigs running in the Haynesville Shale. The Company expects spud-to-first sales to average approximately 75 days during 2009, assuming longer laterals are drilled.
Petrohawk has budgeted $690 million for Haynesville Shale drilling in 2009. Seventy-five to eighty gross operated wells are budgeted, with approximately 6 wells expected to be completed per month. The Company expects to operate an average of 12 rigs in the play in 2009 with an emphasis on holding operated acreage.
Eagle Ford Shale
A second well in Petrohawk's Eagle Ford Shale discovery in South Texas, formally known as Hawkville Field, was completed in mid-January. The Dora Martin #1H, located approximately 14 miles west of the Company's first Eagle Ford Shale well, tested at a rate of 8.3 Mmcfe/d on a 22/64" choke with 4,610# flowing casing pressure. The well was drilled to a true vertical depth of approximately 11,000' and had a lateral length of 4,300' with 12 stages of fracture stimulation. The Company has also reached total depth on its third well, the Donnell #1H. Completion is scheduled for mid-February. Petrohawk is currently running one rig in the play with drilling and completion expected to average 50 days.
Fayetteville Shale
During the fourth quarter, Petrohawk drilled 44 operated and 74 non-operated wells in the Fayetteville Shale. Of 143 horizontal wells drilled during 2008, 113 had state test data available at December 31, 12 were waiting on state tests to be performed, and 18 were waiting on completion due to the delayed in-operation date of the Boardwalk pipeline. Current gross operated production in the Fayetteville Shale reached approximately 145 Mmcfe/d as of December 31, 2008.
Throughout 2008, the Company experienced significant operational improvements in the results of its completions, primarily as a result of drilling longer laterals with cemented liners. This supported by the following data comparing first quarter 2008 and fourth quarter 2008 techniques and results as follows:
Percentage of cemented liners increased from 4% in the first quarter to 100% in the fourth quarter.
Average lateral length increased from 2,286' in the first quarter to 2,655' in the fourth quarter, a 16% increase.
Average number of frac stages increased from 6.0 in the first quarter to 7.6 in the fourth quarter, a 27% increase.
Average state initial production test rate increased from 1.919 Mmcfe/d in the first quarter to 2.456 in Mmcfe/d in the fourth quarter, a 28% increase.
Percentage of completions that tested greater than 3 Mmcfe/d increased from 12% in the first quarter to 54% in the fourth quarter, with 2 wells in the second half of 2008 testing greater than 5 Mmcfe/d.
Price realizations and overall production from the Fayetteville Shale were impacted in the fourth quarter by a delay in the completion of a new third-party pipeline, which increased demand on other transportation lines servicing the play, causing wider than normal basis differentials. Production was either sold at lower than normal prices or shut in at various times during the quarter as a result of these market conditions. The new pipeline, constructed by Boardwalk Pipeline Partners LP, is currently in service and the Company currently expects no additional transportation constraints on its production in the area.
New Gathering Subsidiary - Hawk Field Services, LLC
During 2008, Petrohawk initiated construction of its own gathering systems servicing the Company's as well as third party production in the Fayetteville Shale and Haynesville Shale. Operating under a new subsidiary, Hawk Field Services, LLC, Petrohawk constructed approximately 100 miles of gathering lines in the Fayetteville Shale in 2008, with approximately 150 miles of gathering lines currently in service, under construction or planned in the Haynesville Shale during 2009.
Petrohawk Fourth Quarter and Full Year 2008 Earnings Conference Call
Petrohawk has scheduled a conference call for Wednesday, February 25, 2009 at 9:30 a.m. CDT (10:30 a.m. EDT) to discuss fourth quarter and full year 2008 financial and operating results. To access, dial 800-644-8607 five to ten minutes before the call begins. Please reference Petrohawk Energy Conference ID 81822729. International callers may also participate by dialing 706-679-8184. A replay of the call will be available approximately two hours after the live broadcast ends and will be accessible until March 11, 2009. To access the replay, please dial 800-642-1687 and reference conference ID 81822729. International callers may listen to a playback by dialing 706-645-9291. In addition, the call will be webcast live on Petrohawk's website at http://www.petrohawk.com/. A replay of the call will be available at that site through March 11, 2008.
Petrohawk Energy Corporation is an independent energy company engaged in the acquisition, production, exploration and development of natural gas and oil with properties concentrated in North Louisiana, Arkansas, East Texas, Oklahoma and the Permian basin.
For more information contact Joan Dunlap, Vice President - Investor Relations, at 832-204-2737 or jdunlap@petrohawk.com. For additional information about Petrohawk, please visit our website at http://www.petrohawk.com/.
Peter
Petrohawk Provides Fourth Quarter Operational Update (2008)
Final Proved Reserves up 34% Year Over Year at 1.42 Tcfe, 419% of Production Replaced Haynesville Shale Gross Operated Production Reaches 160 Mmcfe/d
HOUSTON, Feb. 3 /PRNewswire-FirstCall/ -- Petrohawk Energy Corporation ("Petrohawk" or the "Company") (NYSE: HK) provided its fourth quarter 2008 operational update, including additional drilling results in the Haynesville Shale and proved reserves for year-end 2008.
During the fourth quarter, Petrohawk drilled 218 wells, with a success rate of 98%. On average, 32 operated rigs and 15 non-operated rigs were running during the quarter, including a combination of spudder rigs and horizontal rigs in both the Haynesville Shale and Fayetteville Shale development programs. For 2008, Petrohawk drilled 739 total wells, also with a success rate of 98%.
Production for the fourth quarter was approximately 361 million cubic feet of natural gas equivalent (Mmcfe/d), a 15% quarter over quarter increase and a 52% increase over fourth quarter 2007, on a pro forma basis. Petrohawk exited the quarter producing approximately 400 Mmcfe/d. Full year 2008 production was approximately 305 Mmcfe/d.
strong>Haynesville Shale
Petrohawk recently placed four additional wells online utilizing production practices consistent with previously reported wells. The initial production rates of these wells averaged 17.7 Mmcfe/d, detailed as follows:
The Mack Hogan #4 (Bossier Parish, Section 3, 16N, 11W) had an initial production rate of 13.4 Mmcfe/d on a 24/64" choke with 6,350# flowing casing pressure.
The Osborne 8 #3H (Bossier Parish, Section 8, 16N, 11W) had an initial production rate of 18.8 Mmcfe/d on a 24/64" choke with 6,800# flowing casing pressure.
The Roos "A" #5 (Bossier Parish, Section 3, 16N, 11W) had an initial production rate of 15.1 Mmcfe/d on a 24/64" choke with 6,100# flowing casing pressure.
The Griffith 11 #1 (DeSoto Parish, Section 11, 13N, 14W) had an initial production rate of 23.3 Mmcfe/d on a 28/64" choke with 7,550# flowing casing pressure. This well is a significant step-out to the southwest from existing completions.
Two Haynesville Shale completions, the Sample 4 #1 and the R.E. Smith Jr. 32 #1, experienced mechanical problems that resulted in lower than expected initial production rates. On the Sample 4 #1, a valve malfunctioned following completion, causing casing damage in the lateral portion of the well. The Company elected to produce the well on a 12/64" choke as a precaution against further wellbore damage. This well had an initial production rate of 5.4 Mmcfe/d with 7,020# flowing casing pressure. The R.E. Smith Jr. 32 #1 screened out halfway through completion due to the inadvertent firing of a perforating gun in the curve of the lateral. With only six stages of fracture stimulation, this well had an initial production rate of 11.1 Mmcfe/d on a 20/64" choke with 5,900# flowing casing pressure.
The Company is currently producing approximately 160 Mmcfe/d gross from the Haynesville Shale with 16 operated wells on production. Eleven operated wells have been on production 30 days or more, averaging 15.2 Mmcfe/d over their first 30 days of production. Eight operated wells have been on production 60 days or more, averaging 13.2 Mmcfe/d over their first 60 days of production. The four wells on production greater than 90 days have averaged 8.8 Mmcfe/d over their first 90 days of production. All operated wells to date have been produced utilizing similar production practices. During 2009, Petrohawk will conduct a pilot program on certain wells whereby production practices will be altered to restrict production by utilizing smaller choke sizes. The Company will monitor this subset of wells for effects on decline rate and mechanical operation.
Petrohawk's current drilling and completion methodology focuses on completing wells with longer laterals and maximizing the number of frac stages, spaced approximately 325 feet apart. The objective of this technique is to minimize the total number of wells required to effectively drain the reservoir, resulting in lower overall development costs. The Company is currently targeting lateral lengths between 4,300' and 4,600' with up to 15 frac stages. Petrohawk's first four completions averaged 3,339' in lateral length with 10 frac stages while the last twelve completions have averaged 3,958' in lateral length and 12 stages (with the exception of the R.E. Smith Jr 32 #3, which had down hole mechanical issues and only six frac stages).
During 2008, the Company utilized a "pre-drill" program whereby smaller, "spudder" rigs drilled the vertical portion of the wellbore in advance of horizontal rigs moving in to drill the lateral. At year end 2008, Petrohawk had eleven operated horizontal rigs running in the Haynesville Shale. The Company expects spud-to-first sales to average approximately 75 days during 2009, assuming longer laterals are drilled.
Petrohawk has budgeted $690 million for Haynesville Shale drilling in 2009. Seventy-five to eighty gross operated wells are budgeted, with approximately 6 wells expected to be completed per month. The Company expects to operate an average of 12 rigs in the play in 2009 with an emphasis on holding operated acreage.
Eagle Ford Shale
A second well in Petrohawk's Eagle Ford Shale discovery in South Texas, formally known as Hawkville Field, was completed in mid-January. The Dora Martin #1H, located approximately 14 miles west of the Company's first Eagle Ford Shale well, tested at a rate of 8.3 Mmcfe/d on a 22/64" choke with 4,610# flowing casing pressure. The well was drilled to a true vertical depth of approximately 11,000' and had a lateral length of 4,300' with 12 stages of fracture stimulation. The Company has also reached total depth on its third well, the Donnell #1H. Completion is scheduled for mid-February. Petrohawk is currently running one rig in the play with drilling and completion expected to average 50 days.
Fayetteville Shale
During the fourth quarter, Petrohawk drilled 44 operated and 74 non-operated wells in the Fayetteville Shale. Of 143 horizontal wells drilled during 2008, 113 had state test data available at December 31, 12 were waiting on state tests to be performed, and 18 were waiting on completion due to the delayed in-operation date of the Boardwalk pipeline. Current gross operated production in the Fayetteville Shale reached approximately 145 Mmcfe/d as of December 31, 2008.
Throughout 2008, the Company experienced significant operational improvements in the results of its completions, primarily as a result of drilling longer laterals with cemented liners. This supported by the following data comparing first quarter 2008 and fourth quarter 2008 techniques and results as follows:
Percentage of cemented liners increased from 4% in the first quarter to 100% in the fourth quarter.
Average lateral length increased from 2,286' in the first quarter to 2,655' in the fourth quarter, a 16% increase.
Average number of frac stages increased from 6.0 in the first quarter to 7.6 in the fourth quarter, a 27% increase.
Average state initial production test rate increased from 1.919 Mmcfe/d in the first quarter to 2.456 in Mmcfe/d in the fourth quarter, a 28% increase.
Percentage of completions that tested greater than 3 Mmcfe/d increased from 12% in the first quarter to 54% in the fourth quarter, with 2 wells in the second half of 2008 testing greater than 5 Mmcfe/d.
Price realizations and overall production from the Fayetteville Shale were impacted in the fourth quarter by a delay in the completion of a new third-party pipeline, which increased demand on other transportation lines servicing the play, causing wider than normal basis differentials. Production was either sold at lower than normal prices or shut in at various times during the quarter as a result of these market conditions. The new pipeline, constructed by Boardwalk Pipeline Partners LP, is currently in service and the Company currently expects no additional transportation constraints on its production in the area.
New Gathering Subsidiary - Hawk Field Services, LLC
During 2008, Petrohawk initiated construction of its own gathering systems servicing the Company's as well as third party production in the Fayetteville Shale and Haynesville Shale. Operating under a new subsidiary, Hawk Field Services, LLC, Petrohawk constructed approximately 100 miles of gathering lines in the Fayetteville Shale in 2008, with approximately 150 miles of gathering lines currently in service, under construction or planned in the Haynesville Shale during 2009.
Petrohawk Fourth Quarter and Full Year 2008 Earnings Conference Call
Petrohawk has scheduled a conference call for Wednesday, February 25, 2009 at 9:30 a.m. CDT (10:30 a.m. EDT) to discuss fourth quarter and full year 2008 financial and operating results. To access, dial 800-644-8607 five to ten minutes before the call begins. Please reference Petrohawk Energy Conference ID 81822729. International callers may also participate by dialing 706-679-8184. A replay of the call will be available approximately two hours after the live broadcast ends and will be accessible until March 11, 2009. To access the replay, please dial 800-642-1687 and reference conference ID 81822729. International callers may listen to a playback by dialing 706-645-9291. In addition, the call will be webcast live on Petrohawk's website at http://www.petrohawk.com/. A replay of the call will be available at that site through March 11, 2008.
Petrohawk Energy Corporation is an independent energy company engaged in the acquisition, production, exploration and development of natural gas and oil with properties concentrated in North Louisiana, Arkansas, East Texas, Oklahoma and the Permian basin.
For more information contact Joan Dunlap, Vice President - Investor Relations, at 832-204-2737 or jdunlap@petrohawk.com. For additional information about Petrohawk, please visit our website at http://www.petrohawk.com/.
Wednesday, February 18, 2009
More Horizontal Drilling Success
If there is a bright spot, (sorry seismic interpreters, no pun intended) in today's domestic oil and gas industry, it seems to lie in the area of horizontal drilling, completion and production from so-called unconventional reservoirs. The following notes are from two recent examples reported in the February 16 issue of the Oil and Gas Journal, page 36.
Note in particular the GeoResources, Inc. well in the Austin Chalk of south Texas' Giddings Field that produced 1BCF in its first 60 days of production. At $4/MCF, that equals $4 Million return in 60 days, which probably paid the cost of drilling and completing the well. Not bad, I'd say.
Petrohawk Energy Corp. of Houston is also doing very well with their wells in the Haynesville Shale Play in NW Louisiana and the Fayetteville Shale Play in Arkansas, both involving horizontal drilling. The company claims to have replaced "419 % of its production in 2008". Now that is the kind of economic stimulation we could use more of!
Peter
Note in particular the GeoResources, Inc. well in the Austin Chalk of south Texas' Giddings Field that produced 1BCF in its first 60 days of production. At $4/MCF, that equals $4 Million return in 60 days, which probably paid the cost of drilling and completing the well. Not bad, I'd say.
Petrohawk Energy Corp. of Houston is also doing very well with their wells in the Haynesville Shale Play in NW Louisiana and the Fayetteville Shale Play in Arkansas, both involving horizontal drilling. The company claims to have replaced "419 % of its production in 2008". Now that is the kind of economic stimulation we could use more of!
Peter
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