The Barnett Shale still has a lot of life in it, to say the least. It looks like these shale gas plays are unlike conventional oil and gas fields which exhibit steady and predictable decline. It seems technology and production rates just keep improving.
Peter
Best Barnett Shale well ever?
Texas-North
By OGJ editors HOUSTON, Apr. 21 -- (source)
Range Resources Corp., Fort Worth, completed a well at what it believes to be the highest 30-day average reported to date from any Barnett shale well.
The well, in southern Tarrant County in the Fort Worth basin play, averaged 9.6 MMcfd of dry gas in its first 30 days on line.
The well went to 7,350 ft true vertical depth and has a 2,100-ft lateral. Range Resources was still leasing around the well in mid-April.
Friday, April 24, 2009
Thursday, April 23, 2009
The Eagle Ford Shale: A Major New Gas Play?
If true, these results indicate a major new shale gas play. Not much is said, but the implication is it involves horizontal drilling and hydraulic fracturing. Of course there is always the need for accurate steering of the drill bit to make sure the well stays in the preferred "zone", or the stratigraphic interval with the highest productivity.
Peter
Petrohawk calls Eagle Ford a top shale play
By OGJ editors HOUSTON, Apr. 21 --
Formation characteristics from two of its first five wells indicate that the Cretaceous Eagle Ford shale in LaSalle and McMullen counties of South Texas "is one of the highest quality shale reservoirs discovered in the US," said Petrohawk Energy Corp., Houston.
Petrohawk raised its internally estimated ultimate recovery assumption for wells in the play to a midpoint of 5.5 bcfe/well, with a range of 4-7 bcfe/well, based on gas in place data derived from the core analysis from the two wells and performance of wells completed to date.
Petrohawk cited encouraging parameters from the two wells 30 miles apart: the Dora Martin-1H in LaSalle County and the Donnell-1H in McMullen County.
Core analysis from the two wells indicates 180-210 bcf/sq mile of free gas in place, 83-85% gas saturation, 9.4-10.7% porosity, 1,110-1,280 nanodarcies of permeability, and 4.4-4.7% total organic carbon.
Petrohawk recognizes a trend across the field from southwest to northeast of increasing condensate yield, from no condensate production from the Dora Martin-1H to a yield of 110 bbl/MMcf of gas from the Donnell-1H.
The Eagle Ford shale has been encountered in all five wells from 11,000 ft to 11,700 ft true vertical depth. Petrohawk has leased 160,000 contiguous net acres prospective for the formation in LaSalle and McMullen counties. The Texas Railroad Commission has named the area Hawkville field.
Petrohawk operated one horizontal rig in the play in the quarter ended Mar. 31 and has added a second rig.
Three wells were drilled and two were completed in the quarter. The Donnell-1H was completed on Feb. 20 at 3.6 MMcfd and 395 b/d of condensate on a 19/64-in. choke with 3,585 psi flowing casing pressure. The Brown Trust-1H was completed on Mar. 26 at a rate of 8.1 MMcfd and 200 b/d of condensate on a 24/64 in. choke with 4,210 psi flowing casing pressure.
"Production data from the four wells completed to date indicates lower initial annual decline rates, and a flatter hyperbolic decline, than those observed in other shale plays," Petrohawk said.
The company's first three wells, which had pilot holes, averaged 53 days from spud to rig release. The fourth had intermediate casing but no pilot hole and took 32 days. The fifth well was drilled in 22 days without intermediate pipe or a pilot hole.
Drilling and completion costs range from $4.5 million to $5.5 million/well.
Peter
Petrohawk calls Eagle Ford a top shale play
By OGJ editors HOUSTON, Apr. 21 --
Formation characteristics from two of its first five wells indicate that the Cretaceous Eagle Ford shale in LaSalle and McMullen counties of South Texas "is one of the highest quality shale reservoirs discovered in the US," said Petrohawk Energy Corp., Houston.
Petrohawk raised its internally estimated ultimate recovery assumption for wells in the play to a midpoint of 5.5 bcfe/well, with a range of 4-7 bcfe/well, based on gas in place data derived from the core analysis from the two wells and performance of wells completed to date.
Petrohawk cited encouraging parameters from the two wells 30 miles apart: the Dora Martin-1H in LaSalle County and the Donnell-1H in McMullen County.
Core analysis from the two wells indicates 180-210 bcf/sq mile of free gas in place, 83-85% gas saturation, 9.4-10.7% porosity, 1,110-1,280 nanodarcies of permeability, and 4.4-4.7% total organic carbon.
Petrohawk recognizes a trend across the field from southwest to northeast of increasing condensate yield, from no condensate production from the Dora Martin-1H to a yield of 110 bbl/MMcf of gas from the Donnell-1H.
The Eagle Ford shale has been encountered in all five wells from 11,000 ft to 11,700 ft true vertical depth. Petrohawk has leased 160,000 contiguous net acres prospective for the formation in LaSalle and McMullen counties. The Texas Railroad Commission has named the area Hawkville field.
Petrohawk operated one horizontal rig in the play in the quarter ended Mar. 31 and has added a second rig.
Three wells were drilled and two were completed in the quarter. The Donnell-1H was completed on Feb. 20 at 3.6 MMcfd and 395 b/d of condensate on a 19/64-in. choke with 3,585 psi flowing casing pressure. The Brown Trust-1H was completed on Mar. 26 at a rate of 8.1 MMcfd and 200 b/d of condensate on a 24/64 in. choke with 4,210 psi flowing casing pressure.
"Production data from the four wells completed to date indicates lower initial annual decline rates, and a flatter hyperbolic decline, than those observed in other shale plays," Petrohawk said.
The company's first three wells, which had pilot holes, averaged 53 days from spud to rig release. The fourth had intermediate casing but no pilot hole and took 32 days. The fifth well was drilled in 22 days without intermediate pipe or a pilot hole.
Drilling and completion costs range from $4.5 million to $5.5 million/well.
Wednesday, April 22, 2009
Shale Gas Development In U.S. --- Table of Contents
The following summarizes what is covered in the recent publication by The Department of Energy (DOE). (source)
For our purposes here, we are most interested in the geological, engineering and economic aspects of shale gas development, but comments on any of the following subjects are welcome.
(As an aside, do any of our political lawmakers and decision-makers read and understand the significance of extracting this abundant natural gas? It is used to heat and cool our homes, power our industry, and can even be easily used to power our vehicles when it is compressed. If we really want to reduce our dependence on "foreign oil" we should be aggressively producing this gas! The DOE estimates we have enough to last 100 years! What are we waiting for? Windmills, solar panels and nuclear power plants? That's crazy! We have this natural gas here and now, with established infrastructure and known technology; let's go get it!)
Peter
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER
TABLE OF CONTENTS
Table of Contents ---i
List of Exhibits---iii
INTRODUCTION---1
THE IMPORTANCE OF SHALE GAS --- 3
The Role of Natural Gas in the United States’ Energy Portfolio ---3
The Advantages of Natural Gas --- 5
Natural Gas Basics ---6
Unconventional Gas--- 7
The Role of Shale Gas in Unconventional Gas---8
Looking Forward ---10
SHALE GAS DEVELOPMENT IN THE UNITED STATES ---13
Shale Gas – Geology ---14
Sources of Natural Gas---16
Shale Gas in the United States ---16
The Barnett Shale ---18
The Fayetteville Shale---19
The Haynesville Shale ---20
The Marcellus Shale ---21
The Woodford Shale ---22
The Antrim Shale ---23
The New Albany Shale ---24
REGULATORY FRAMEWORK--- 25
Federal Environmental Laws Governing Shale Gas Development--- 25
State Regulation ---25
Local Regulation ---27
Regulation of Impacts on Water Quality ---29
Clean Water Act---29
Safe Drinking Water Act --- 32
Oil Pollution Act of 1990 – Spill Prevention Control and Countermeasure---33
State Regulations and Regional Cooperation --- 35
Regulation of Impacts on Air Quality---35
Clean Air Act ---35
Air Quality Regulations ---36
Air Permits ---36
Regulation of Impacts to Land ---37
Resource Conservation and Recovery Act (RCRA) ---37
Endangered Species Act---38
State Endangered Species Protections ---39
Oil and Gas Operations on Public Lands ---39
Federal Lands ---39
State Lands ---40
Other Federal Laws and Requirements that Protect the Environment---40
Comprehensive Environmental Response, Compensation, and Liability Act ---40
Emergency Planning and Community Right-to-Know Act---41
Occupational Safety and Health Act ---42
Summary ---42
ENVIRONMENTAL CONSIDERATIONS --- 43
Horizontal Wells ---46
Reducing Surface Disturbance ---47
Reducing Wildlife Impacts --- 48
Reducing Community Impacts --- 49
Protecting Groundwater: Casing and Cementing Programs ---51
Hydraulic Fracturing ---56
Fracture Design ---56
Fracturing Process---58
Fracturing Fluids and Additives ---61
Water Availability ---64
Water Management ---66
Naturally Occurring Radioactive Material (NORM) ---70
Air Quality ---71
Sources of Air Emissions --- 72
Composition of Air Emissions --- 72
Technological Controls and Practices---74
Summary ---76
Acronyms and Abbreviations ---79
DEFINITIONS --- 81
END NOTES---83
For our purposes here, we are most interested in the geological, engineering and economic aspects of shale gas development, but comments on any of the following subjects are welcome.
(As an aside, do any of our political lawmakers and decision-makers read and understand the significance of extracting this abundant natural gas? It is used to heat and cool our homes, power our industry, and can even be easily used to power our vehicles when it is compressed. If we really want to reduce our dependence on "foreign oil" we should be aggressively producing this gas! The DOE estimates we have enough to last 100 years! What are we waiting for? Windmills, solar panels and nuclear power plants? That's crazy! We have this natural gas here and now, with established infrastructure and known technology; let's go get it!)
Peter
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER
TABLE OF CONTENTS
Table of Contents ---i
List of Exhibits---iii
INTRODUCTION---1
THE IMPORTANCE OF SHALE GAS --- 3
The Role of Natural Gas in the United States’ Energy Portfolio ---3
The Advantages of Natural Gas --- 5
Natural Gas Basics ---6
Unconventional Gas--- 7
The Role of Shale Gas in Unconventional Gas---8
Looking Forward ---10
SHALE GAS DEVELOPMENT IN THE UNITED STATES ---13
Shale Gas – Geology ---14
Sources of Natural Gas---16
Shale Gas in the United States ---16
The Barnett Shale ---18
The Fayetteville Shale---19
The Haynesville Shale ---20
The Marcellus Shale ---21
The Woodford Shale ---22
The Antrim Shale ---23
The New Albany Shale ---24
REGULATORY FRAMEWORK--- 25
Federal Environmental Laws Governing Shale Gas Development--- 25
State Regulation ---25
Local Regulation ---27
Regulation of Impacts on Water Quality ---29
Clean Water Act---29
Safe Drinking Water Act --- 32
Oil Pollution Act of 1990 – Spill Prevention Control and Countermeasure---33
State Regulations and Regional Cooperation --- 35
Regulation of Impacts on Air Quality---35
Clean Air Act ---35
Air Quality Regulations ---36
Air Permits ---36
Regulation of Impacts to Land ---37
Resource Conservation and Recovery Act (RCRA) ---37
Endangered Species Act---38
State Endangered Species Protections ---39
Oil and Gas Operations on Public Lands ---39
Federal Lands ---39
State Lands ---40
Other Federal Laws and Requirements that Protect the Environment---40
Comprehensive Environmental Response, Compensation, and Liability Act ---40
Emergency Planning and Community Right-to-Know Act---41
Occupational Safety and Health Act ---42
Summary ---42
ENVIRONMENTAL CONSIDERATIONS --- 43
Horizontal Wells ---46
Reducing Surface Disturbance ---47
Reducing Wildlife Impacts --- 48
Reducing Community Impacts --- 49
Protecting Groundwater: Casing and Cementing Programs ---51
Hydraulic Fracturing ---56
Fracture Design ---56
Fracturing Process---58
Fracturing Fluids and Additives ---61
Water Availability ---64
Water Management ---66
Naturally Occurring Radioactive Material (NORM) ---70
Air Quality ---71
Sources of Air Emissions --- 72
Composition of Air Emissions --- 72
Technological Controls and Practices---74
Summary ---76
Acronyms and Abbreviations ---79
DEFINITIONS --- 81
END NOTES---83
Sunday, April 19, 2009
Shale Gas Development And Potential In Canada
The technology (see other articles on this blog) largely developed in the United States to produce natural gas from shale formations, is attracting attention and investment in other countries. Here is a glimpse of what is happening in Canada. What has been called "unconventional gas" is now becoming accepted and actively pursued.
Peter
October 08, 2008
Horn River Basin Project (British Columbia, Canada)
Fort St John (October 8, 2008):
Geoscience BC is pleased to announce, in partnership with the Horn River Basin Shale Gas Producers Group and the B.C. Ministry of Energy, Mines and Petroleum Resources, a $5 million geoscience research program in the Horn River Basin of northeast B.C.
Unlocking the gas from the shale formations in the Horn River Basin presents significant new geological and technological challenges to the industry. To assist the industry and the Provincial Government in assuring that the maximum benefit is realized from the development of this resource, Geoscience BC is committing up to $5 million to this program. The funding will be matched with contributions from industry, academia and other project partners, and will be used for geoscience studies in the basin, focused on identifying and evaluating potential water sources for shale gas production.
"The potential of British Columbia's oil and gas resources is incredible," said Energy, Mines and Petroleum Resources Minister Richard Neufeld, "and data compiled from these projects will provide important information that will be used for the exploration and development of the oil and gas industry. The possibilities are staggering, which is why we are taking a thoughtful and ambitious approach to resource exploration and development."
A top priority for industry in the development of the shale gas resource in the Horn River Basin, is the identification and characterization of subsurface water source aquifers, both as potential sources of water for gas production, and also as sites for spent water disposal, and possibly CO2 sequestration. Use of subsurface water in gas production may significantly reduce the surface environmental footprint of development, and help to protect surface fresh water aquifers."The Horn River Basin producers group is excited about the opportunity to partner with Geoscience BC to identify potential subsurface water sources" said Rob Spitzer, Chair of the Horn River Basin Producers Group. "This is an excellent example of the kind of collaboration that will ensure the responsible development of the Horn River Basin."
In addition to the saline aquifer studies, basin-wide formation characterization studies of the gas-bearing shales, and fault and fracture identification and mapping, may be undertaken. These studies will help to unravel the complexity of the Horn River Basin reservoirs, and assist the industry in the orderly and environmentally sustainable development of the shale gas resource in the Basin.
"Geoscience BC looks forward to contributing to the priority needs of both industry and government through supporting the development of innovative solutions to the challenges presented by the exploration and development of the Horn River Basin shale gas," said Dr. 'Lyn Anglin, President and CEO of Geoscience BC. "These studies will help contribute to cost-effective and environmentally sound development of British Columbia's unconventional gas resources."
Funding mechanisms for this program and details of projects to be undertaken, will be published as they become available. The Horn River Basin shale gas producers group consists of the major industry players, which are Apache Canada Ltd., Encana, Devon Canada Corp., EOG Resources Canada, Nexen Inc., Quicksilver, Imperial Oil Resources/ExxonMobil Canada and Stone Mountain Resources. The purpose of the group is to facilitate cooperation and communication between major industry players, key stakeholders and First Nations in the area.
Geoscience BC is an industry-led, industry-focused not-for-profit society. Its mandate includes the collection, interpretation and marketing of geoscience data and expertise to promote investment in resource exploration and development in British Columbia. Geoscience BC is funded by the Provincial Government and works in partnership with industry, academia, government, First Nations and communities to attract mineral and oil & gas investment to BC.
For more information, please contact: Geoscience BC'Lyn Anglin, PhDPresident and CEO (604) 290-1194www.geosciencebc.com
Peter
October 08, 2008
Horn River Basin Project (British Columbia, Canada)
Fort St John (October 8, 2008):
Geoscience BC is pleased to announce, in partnership with the Horn River Basin Shale Gas Producers Group and the B.C. Ministry of Energy, Mines and Petroleum Resources, a $5 million geoscience research program in the Horn River Basin of northeast B.C.
Unlocking the gas from the shale formations in the Horn River Basin presents significant new geological and technological challenges to the industry. To assist the industry and the Provincial Government in assuring that the maximum benefit is realized from the development of this resource, Geoscience BC is committing up to $5 million to this program. The funding will be matched with contributions from industry, academia and other project partners, and will be used for geoscience studies in the basin, focused on identifying and evaluating potential water sources for shale gas production.
"The potential of British Columbia's oil and gas resources is incredible," said Energy, Mines and Petroleum Resources Minister Richard Neufeld, "and data compiled from these projects will provide important information that will be used for the exploration and development of the oil and gas industry. The possibilities are staggering, which is why we are taking a thoughtful and ambitious approach to resource exploration and development."
A top priority for industry in the development of the shale gas resource in the Horn River Basin, is the identification and characterization of subsurface water source aquifers, both as potential sources of water for gas production, and also as sites for spent water disposal, and possibly CO2 sequestration. Use of subsurface water in gas production may significantly reduce the surface environmental footprint of development, and help to protect surface fresh water aquifers."The Horn River Basin producers group is excited about the opportunity to partner with Geoscience BC to identify potential subsurface water sources" said Rob Spitzer, Chair of the Horn River Basin Producers Group. "This is an excellent example of the kind of collaboration that will ensure the responsible development of the Horn River Basin."
In addition to the saline aquifer studies, basin-wide formation characterization studies of the gas-bearing shales, and fault and fracture identification and mapping, may be undertaken. These studies will help to unravel the complexity of the Horn River Basin reservoirs, and assist the industry in the orderly and environmentally sustainable development of the shale gas resource in the Basin.
"Geoscience BC looks forward to contributing to the priority needs of both industry and government through supporting the development of innovative solutions to the challenges presented by the exploration and development of the Horn River Basin shale gas," said Dr. 'Lyn Anglin, President and CEO of Geoscience BC. "These studies will help contribute to cost-effective and environmentally sound development of British Columbia's unconventional gas resources."
Funding mechanisms for this program and details of projects to be undertaken, will be published as they become available. The Horn River Basin shale gas producers group consists of the major industry players, which are Apache Canada Ltd., Encana, Devon Canada Corp., EOG Resources Canada, Nexen Inc., Quicksilver, Imperial Oil Resources/ExxonMobil Canada and Stone Mountain Resources. The purpose of the group is to facilitate cooperation and communication between major industry players, key stakeholders and First Nations in the area.
Geoscience BC is an industry-led, industry-focused not-for-profit society. Its mandate includes the collection, interpretation and marketing of geoscience data and expertise to promote investment in resource exploration and development in British Columbia. Geoscience BC is funded by the Provincial Government and works in partnership with industry, academia, government, First Nations and communities to attract mineral and oil & gas investment to BC.
For more information, please contact: Geoscience BC'Lyn Anglin, PhDPresident and CEO (604) 290-1194www.geosciencebc.com
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.
Sunday, April 12, 2009
Range Resources And The Marcellus Shale Gas Play
In spite of all the economic gloom and doom Americans still need natural gas. Here is one company looking at a bright future in the Marcellus Shale Gas Play of the American northeast.
Peter
Sunday, Apr 12, 2009
Posted on Wed, Apr. 08, 2009 (source)
Range Resources happy about its 2004 venture into gas field
By JACK Z. SMITH jzsmith@star-telegram.com
The Marcellus Shale in the Appalachian area of the eastern United States is fast becoming one of the hottest natural gas drilling plays in the nation, the subject of speculation that its production could eventually outstrip the Barnett Shale of North Texas.
But John Pinkerton, chairman and CEO of Range Resources Corp. of Fort Worth, said the company felt quite lonely when it made a pioneering foray into the sprawling Marcellus field in Pennsylvania in 2004.
"We felt like the Marine running up the hill, coming out of the bunker, and nobody else is around him," Pinkerton told a rapt audience of several hundred people at the Omni Fort Worth Hotel on Wednesday at a Hart Energy Publishing conference on developing unconventional gas reserves.
Five years later, Pinkerton can reel off a litany of reasons why he’s ecstatic about Range’s prospects in the Marcellus, which he calls "a huge sandbox" of 65 million acres that dwarfs the Barnett Shale expanse of 3 million acres.
Walking the walk
Range is putting its money where its mouth is.
"We’ve invested almost a billion dollars in the Marcellus," Pinkerton said. "For a company our size, that’s a heck of a lot of money."
Range, with 25-plus years of experience in older Appalachian fields, has about 1.4 million net acres under lease for Marcellus drilling, making it a premier player there. Range has acreage in southwest and northeast Pennsylvania, plus southern New York.
Pinkerton said Range, which has drilled successful vertical and horizontal wells in the Marcellus, hopes to roughly triple its production in the gas shale to 80 million to 100 million cubic feet a day by year’s end. After making some initial mistakes, Range has "recorded terrific well results," with the last 10 horizontal wells brought online in 2008, making an average initial production of 7.3 million cubic feet per day, Pinkerton said.
Range is also making large investments in natural gas processing facilities and pipelines.
Marcellus pluses
A primary benefit of the Marcellus play is that "you’re in the best spot on planet Earth to sell gas" in the heavily populated Northeast and can therefore draw premium prices, Pinkerton said. Marcellus leasing costs are low and Pennsylvania doesn’t levy a severance tax on natural gas, he added.
Range’s pioneering Marcellus effort drew plaudits from another conference speaker, Mike Walen, a senior vice president of Cabot Oil and Gas Corp., also a significant player in the Marcellus.
"I tip my hat to Range Resources," Walen said. "They did a heck of a job to discover the play in 2004. This is a world-class play."
Peter
Sunday, Apr 12, 2009
Posted on Wed, Apr. 08, 2009 (source)
Range Resources happy about its 2004 venture into gas field
By JACK Z. SMITH jzsmith@star-telegram.com
The Marcellus Shale in the Appalachian area of the eastern United States is fast becoming one of the hottest natural gas drilling plays in the nation, the subject of speculation that its production could eventually outstrip the Barnett Shale of North Texas.
But John Pinkerton, chairman and CEO of Range Resources Corp. of Fort Worth, said the company felt quite lonely when it made a pioneering foray into the sprawling Marcellus field in Pennsylvania in 2004.
"We felt like the Marine running up the hill, coming out of the bunker, and nobody else is around him," Pinkerton told a rapt audience of several hundred people at the Omni Fort Worth Hotel on Wednesday at a Hart Energy Publishing conference on developing unconventional gas reserves.
Five years later, Pinkerton can reel off a litany of reasons why he’s ecstatic about Range’s prospects in the Marcellus, which he calls "a huge sandbox" of 65 million acres that dwarfs the Barnett Shale expanse of 3 million acres.
Walking the walk
Range is putting its money where its mouth is.
"We’ve invested almost a billion dollars in the Marcellus," Pinkerton said. "For a company our size, that’s a heck of a lot of money."
Range, with 25-plus years of experience in older Appalachian fields, has about 1.4 million net acres under lease for Marcellus drilling, making it a premier player there. Range has acreage in southwest and northeast Pennsylvania, plus southern New York.
Pinkerton said Range, which has drilled successful vertical and horizontal wells in the Marcellus, hopes to roughly triple its production in the gas shale to 80 million to 100 million cubic feet a day by year’s end. After making some initial mistakes, Range has "recorded terrific well results," with the last 10 horizontal wells brought online in 2008, making an average initial production of 7.3 million cubic feet per day, Pinkerton said.
Range is also making large investments in natural gas processing facilities and pipelines.
Marcellus pluses
A primary benefit of the Marcellus play is that "you’re in the best spot on planet Earth to sell gas" in the heavily populated Northeast and can therefore draw premium prices, Pinkerton said. Marcellus leasing costs are low and Pennsylvania doesn’t levy a severance tax on natural gas, he added.
Range’s pioneering Marcellus effort drew plaudits from another conference speaker, Mike Walen, a senior vice president of Cabot Oil and Gas Corp., also a significant player in the Marcellus.
"I tip my hat to Range Resources," Walen said. "They did a heck of a job to discover the play in 2004. This is a world-class play."
Wednesday, April 8, 2009
Compressed Natural Gas: Fuel Of The Future For Autos?
The following article gives a brief summary of what could be done with natural gas. The cost of these home fueling stations called "The Phill" is high today, but as with most things, if they were made in quantity the price would come down.
As I see it, one of the beauties of this system is that many, if not most people already have natural gas being piped into their homes for heating and cooking. It is usually very safe, and all the infrastructure to supply this gas is in place. Can anyone think of a better way of lessening our dependence on foreign oil?
As I've shown before on this blog, natural gas is the cleanest of hydrocarbon-based fuels, and as we're seeing with these Shale Gas plays around the United States, the gas is there, in the ground, ready to be produced. Someone with some deep pockets ought to buy the company making "The Phill". Boone Pickens has apparently tried, and maybe he will still succeed.
Peter
Maker of Natural Gas Fueling Systems Tanks
By Clifford Krauss (source)
FuelMaker.com The Phill, a residential compressed natural gas fueling system, never really caught on.
Natural gas is cheap and plentiful, and last summer the future for vehicles fueled by compressed natural gas — or CNG — looked bright. But then crude oil and gasoline prices tanked. Now, the future of CNG cars looks a lot less certain.
It hardly got any attention, but late last week FuelMaker, the Honda-owned maker of natural gas fueling systems — including a residential model called the “Phill” — filed for bankruptcy.
Clean Energy Fuels, a natural gas distributor owned by T. Boone Pickens, had been trying to buy the company from Honda for $17 million, but the two sides could never make a deal. The Phill, which has been on the market about six years, never caught on. Perhaps that is because it takes four hours to fill an empty tank with the device, and it costs up to $6,000.
An even bigger problem for FuelMaker might have been the fact that very few drivers own CNG vehicles. Most are fleet cars, buses and trucks owned by companies and public transportation agencies. And, of course, few gasoline filling stations offer compressed natural gas.
At the moment, the Honda Civic GX is the only CNG car on the market, and it is available at only a select number of dealerships in a few states including California and New York.
As I see it, one of the beauties of this system is that many, if not most people already have natural gas being piped into their homes for heating and cooking. It is usually very safe, and all the infrastructure to supply this gas is in place. Can anyone think of a better way of lessening our dependence on foreign oil?
As I've shown before on this blog, natural gas is the cleanest of hydrocarbon-based fuels, and as we're seeing with these Shale Gas plays around the United States, the gas is there, in the ground, ready to be produced. Someone with some deep pockets ought to buy the company making "The Phill". Boone Pickens has apparently tried, and maybe he will still succeed.
Peter
Maker of Natural Gas Fueling Systems Tanks
By Clifford Krauss (source)
FuelMaker.com The Phill, a residential compressed natural gas fueling system, never really caught on.
Natural gas is cheap and plentiful, and last summer the future for vehicles fueled by compressed natural gas — or CNG — looked bright. But then crude oil and gasoline prices tanked. Now, the future of CNG cars looks a lot less certain.
It hardly got any attention, but late last week FuelMaker, the Honda-owned maker of natural gas fueling systems — including a residential model called the “Phill” — filed for bankruptcy.
Clean Energy Fuels, a natural gas distributor owned by T. Boone Pickens, had been trying to buy the company from Honda for $17 million, but the two sides could never make a deal. The Phill, which has been on the market about six years, never caught on. Perhaps that is because it takes four hours to fill an empty tank with the device, and it costs up to $6,000.
An even bigger problem for FuelMaker might have been the fact that very few drivers own CNG vehicles. Most are fleet cars, buses and trucks owned by companies and public transportation agencies. And, of course, few gasoline filling stations offer compressed natural gas.
At the moment, the Honda Civic GX is the only CNG car on the market, and it is available at only a select number of dealerships in a few states including California and New York.
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