Many companies are reducing their drilling and completion activity because of "low" gas prices. Blame it on the slumped economy, or blame it on the difficulty of available credit, or whatever. It seems to me companies are being cautious and waiting for gas prices to rise a bit before investing to get the gas flowing. Activity may has slowed, but it will pick up again.
Peter
Oklahoma
By OGJ editors
HOUSTON, Apr. 23 --
Newfield Exploration Co., Houston, has been slowing its pace of Woodford shale completions in Oklahoma due to low gas prices.
Gross production is 240 MMcfd of gas, and the company is operating 11 rigs in the field, six of which roll off term contract in 2009.
"The timing of rig contract expirations and the fact that more than 90% of the company's 165,000 net acres now held by production provide Newfield with operational flexibility in the second half of 2009," Newfield said.
Laterals Newfield drills in the play are expected to average more than 5,000 ft in 2009.
Thursday, April 30, 2009
Haynesville Shale, Another Very Good Well
The Haynesville Shale Gas Play in northwest Louisiana continues growing with very good results. Note the mention of the "10-stage frac". Horizontal drilling followed by multi-stage frac jobs is becoming the norm for shale gas wells across the country.
Peter
Louisiana
By OGJ editors
HOUSTON, Apr. 28 -- (source)
A well operated by Chesapeake Energy Corp., Oklahoma City, in Caspiana field, Northwest Louisiana, flowed 17 MMcfd of gas from the Haynesville shale formation on state test.
Participant Cubic Energy Inc., Dallas, said the well flowed on a 24/64-in. choke with 6,170 psi flowing tubing pressure after a 10-stage frac. It was completed in February 2009.
The well, Clingman Acres-11H, in 11-15n-15w, Caddo Parish, is just east of Cubic Energy's Johnson Branch acreage. Cubic Energy's working interest in the well is 2.8%.
Peter
Louisiana
By OGJ editors
HOUSTON, Apr. 28 -- (source)
A well operated by Chesapeake Energy Corp., Oklahoma City, in Caspiana field, Northwest Louisiana, flowed 17 MMcfd of gas from the Haynesville shale formation on state test.
Participant Cubic Energy Inc., Dallas, said the well flowed on a 24/64-in. choke with 6,170 psi flowing tubing pressure after a 10-stage frac. It was completed in February 2009.
The well, Clingman Acres-11H, in 11-15n-15w, Caddo Parish, is just east of Cubic Energy's Johnson Branch acreage. Cubic Energy's working interest in the well is 2.8%.
Cimarex Energy Co. And Woodford Shale In Oklahoma
These are pretty good numbers from the Woodford Shale Gas Play in Oklahoma. The average flow rates, successful completion percentage, and number of wells drilled are all impressive.
Peter
Oklahoma
By OGJ editors
HOUSTON, Apr. 29 -- (source)
Cimarex Energy Co., Denver, has participated in 49 wells in the Anadarko basin Woodford shale play since late 2007.
Of the 49 wells, 36 are on line and the rest are either awaiting completion or drilling. The 30-day initial average production rate, normalized for a 4,300-ft lateral, is 4.5 MMcfd.
The company's 2009 program is to drill or participate in 50 gross (23 net) wells. Cimarex holds 98,000 net acres in the play.
Peter
Oklahoma
By OGJ editors
HOUSTON, Apr. 29 -- (source)
Cimarex Energy Co., Denver, has participated in 49 wells in the Anadarko basin Woodford shale play since late 2007.
Of the 49 wells, 36 are on line and the rest are either awaiting completion or drilling. The 30-day initial average production rate, normalized for a 4,300-ft lateral, is 4.5 MMcfd.
The company's 2009 program is to drill or participate in 50 gross (23 net) wells. Cimarex holds 98,000 net acres in the play.
Friday, April 24, 2009
Horn River Shale Gas Play In NE British Columbia Going Strong
The economics of gas wells in the Horn River Shale of northeastern British Columbia, Canada must be excellent. Why? Imagine the cost of bringing in rigs and equipment to this remote area, with its harsh climate and lack of supporting infrastructure. Gas produced from shale, via horizontal drilling and constantly improving hydraulic fracturing technology are key elements to this success.
Peter
Horn River drilling, gas plant take shape
By OGJ editors HOUSTON, Apr. 22 -- (source)
EnCana Corp., Calgary, and its partner Apache Corp., Houston, have adopted a more efficient way to develop gas in the Horn River basin shales of Northeast British Columbia, EnCana said.
The companies hope to be able to drill fewer wells by increasing the number of fracs per horizontal leg to as many as 14 from the eight initially planned.
The companies will drill 12 wells in 2009, down from 20 originally planned.
EnCana is to build the Cabin gas processing plant 60 km northeast of Fort Nelson, BC, on behalf of industry co-owners that are major landholders in the basin. Its first phase is due in service in the third quarter of 2011. Initial capacity is 400 MMcfd, and the plant will be expanded in stages as the basin's gas production grows.
Peter
Horn River drilling, gas plant take shape
By OGJ editors HOUSTON, Apr. 22 -- (source)
EnCana Corp., Calgary, and its partner Apache Corp., Houston, have adopted a more efficient way to develop gas in the Horn River basin shales of Northeast British Columbia, EnCana said.
The companies hope to be able to drill fewer wells by increasing the number of fracs per horizontal leg to as many as 14 from the eight initially planned.
The companies will drill 12 wells in 2009, down from 20 originally planned.
EnCana is to build the Cabin gas processing plant 60 km northeast of Fort Nelson, BC, on behalf of industry co-owners that are major landholders in the basin. Its first phase is due in service in the third quarter of 2011. Initial capacity is 400 MMcfd, and the plant will be expanded in stages as the basin's gas production grows.
The Haynesville Shale Gas Play Continues Hot...
It seems the Haynesville Shale Gas Play is showing no signs of slowing down, in spite of lower gas prices. As they say, "follow the money" and EnCana is investing some big dollars. This is the kind of economic stimulus America needs!
Peter
EnCana boosts Haynesville shale activity
By OGJ editors HOUSTON, Apr. 22 -- (source)
EnCana Corp., Calgary, has a $580 million program to drill 50 Haynesville shale gas wells in East Texas and North Louisiana in 2009.
The company has seen encouraging results from its own drilling and those of other producers, and the 2009 program will enable it to improve its understanding of the play, further evaluate its lands, and retain prospective acreage.
To facilitate unrestrained market access for its gas, the company has committed to supply 150 MMcfd on the proposed Gulf South pipeline expansion and 500 MMcfd on the proposed ETC Tiger pipeline.
Meanwhile, EnCana chalked up a 50% production increase in the Deep Bossier play in East Texas, where it averaged 409 MMcfd of production in the first quarter of 2009 compared with an average of 334 MMcfd for all of 2008.
EnCana drilled 15 wells in the first quarter and 78 in all of East Texas in 2008.
Initial 30-day production rates in Amoruso field averaged more than 19 MMcfd, and the Charlene-1 well completed in January flowed at more than 50 MMcfd on initial tests.
Peter
EnCana boosts Haynesville shale activity
By OGJ editors HOUSTON, Apr. 22 -- (source)
EnCana Corp., Calgary, has a $580 million program to drill 50 Haynesville shale gas wells in East Texas and North Louisiana in 2009.
The company has seen encouraging results from its own drilling and those of other producers, and the 2009 program will enable it to improve its understanding of the play, further evaluate its lands, and retain prospective acreage.
To facilitate unrestrained market access for its gas, the company has committed to supply 150 MMcfd on the proposed Gulf South pipeline expansion and 500 MMcfd on the proposed ETC Tiger pipeline.
Meanwhile, EnCana chalked up a 50% production increase in the Deep Bossier play in East Texas, where it averaged 409 MMcfd of production in the first quarter of 2009 compared with an average of 334 MMcfd for all of 2008.
EnCana drilled 15 wells in the first quarter and 78 in all of East Texas in 2008.
Initial 30-day production rates in Amoruso field averaged more than 19 MMcfd, and the Charlene-1 well completed in January flowed at more than 50 MMcfd on initial tests.
Reach Out And Touch Some Marcellus Shale....Quickly
This sounds clever, very quickly drill multiple horizontal wells, in different directions, from the same relatively small drill pad. Minimize surface disturbance, minimize cost, maximize productivity.
Peter
Custom Drilling Rigs Used In Marcellus Shale Gas Play
Pennsylvania
By OGJ editors HOUSTON, Apr. 16 --
Range Resources Corp., Fort Worth, placed in service two custom-designed drilling rigs in the Marcellus shale gas play in Pennsylvania.
The rigs are equipped with crawlers and can traverse a drill pad in a few hours versus days for conventional rigs. The rigs are expected to save time and money as Range drills multiple laterals from the same pad.
The company's 2009 program calls for drilling more than 60 Marcellus wells.
Peter
Custom Drilling Rigs Used In Marcellus Shale Gas Play
Pennsylvania
By OGJ editors HOUSTON, Apr. 16 --
Range Resources Corp., Fort Worth, placed in service two custom-designed drilling rigs in the Marcellus shale gas play in Pennsylvania.
The rigs are equipped with crawlers and can traverse a drill pad in a few hours versus days for conventional rigs. The rigs are expected to save time and money as Range drills multiple laterals from the same pad.
The company's 2009 program calls for drilling more than 60 Marcellus wells.
Barnett Shale: Best Well Yet?
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.
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.
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.
Friday, April 3, 2009
Marcellus Shale Gas Play: Part 7
Natural gas is a preferred energy source with a wide variety of uses. The future looks good for the development of the Marcellus Shale in the northeastern United States.
Peter
Economic Development
The size of the economic impacts from Marcellus
depend critically on whether the businesses exist
within the Pennsylvania communities to support
ancillary economic activity created by natural gas
exploration and development. The more spending
that occurs outside the community, the less economic
benefit will accrue locally since those dollars will
simply leave the community rather than recirculating
among local businesses.
Similarly, to the extent
nonresidents hold new jobs, the lower the benefit to
the community. The twofold economic development
challenge is thus:
1. Finding ways to help local businesses and workers
compete for the new business opportunities
arising from natural gas.
2. Finding ways to encourage businesses, workers,
and royalty owners to spend their new dollars
locally rather than out of town. New business
start-up and technical assistance should target
business opportunities related to natural gas, and
workforce development training should focus on
the new specialized jobs that will be created (such
as land men who service the wells).
General local business and community development
programs focused on helping local businesses
or downtowns be competitive could similarly help
Pennsylvania communities better compete for the
new spending resulting from the natural gas revenues.
Environmental Impacts
The construction, activity, and existence of natural
gas wells in the community and industry may cause
significant environmental changes to the areas.
These issues should be considered when planning
and enforcing local action to accommodate the
developing gas industry. Possible environmental
concerns that could arise from drilling activity
include:
• Aesthetics and recreation—heightened noise and
the effects of drilling may affect the aesthetics and
recreational value of a resource for both nonconsumptive
(e.g., hiking, birding) and consumptive
(e.g., fishing, hunting) recreational use. This may
affect communities that are promoting natural resource-
based tourism.
• Habitat fragmentation—well sites and associated
infrastructure may fragment Pennsylvania forests.
Fragmentation will decrease habitat quality for
many wildlife species that are dependent on
deep forest habitat; it is also associated with an
increased spread of nonnative and invasive plants,
causing further habitat degradation for native
plants and animals.
• Water impacts—water consumption and
wastewater disposal may affect aquatic resources
both locally and within the larger watershed.
• Timber resources—access roads and pipelines
may cause damage to timber stands, resulting
in loss of forestry income, appraisal, and sale of
timber.
• Soil compaction and long-term site fertility—
well sites may compact the soil, affecting the
long-term health and fertility of the area.
Forestry concerns that show effects on forests,
wildlife, ecology, and local natural balance need to
be addressed by DEP, Conservation Districts, and
other associated agencies through regulation and
enforcement.
After drilling has occurred in an area,
proper site restoration is a necessity. The best ways
to restore sites depend on the location and natural
surroundings, making it necessary for officials to
gather information on the pros and cons of different
methods of site restoration. The type and quantity of
vegetation replanted will make a large impact on the
natural ecology and balance.
What Local Officials Can Do
Local government officials concerned about the
impact of Marcellus shale development on their
community need to greatly expand and upgrade their
comprehensive community planning efforts. The fast
pace of gas drilling—and all its related activities—
means that planning must be done on a continuous,
daily basis. Every new well that is drilled causes small
changes in the community. Monthly meetings of the
planning commission are not sufficient to keep up
with these changes.
We also need a new way to think
about how communities plan for gas exploration.
Comprehensive community planning is more
than just the established “comprehensive plan.” A
comprehensive plan, as permitted in the Municipalities
Planning Code, serves as a useful tool for
municipal management by providing a broad, general
framework for common development issues projected
ten to twenty years into the future. This would be
acceptable if things did not change very quickly, but
that is not the case with gas drilling. Few comprehensive
plans were prepared with major natural gas
development in mind, so they are not adequately
prepared to address the potential impacts of the
Marcellus shale formation.
A more comprehensive view must take into
account all the important issues and how they interrelate
to one another. This view involves more
than just land use. Gas drilling brings many new
factors to communities that have not been experienced
previously in many areas of Pennsylvania.
Exploration of the Marcellus shale will generate
large amounts of money from the leasing of land,
construction, trucking, commerce, and housing development.
Some residents will have more money to
spend, but will they spend it in the community and
region? Will they take that capital somewhere else
if there are no places for them to spend their money
locally?
New opportunities for business development
should increase with gas drilling, which will require
infrastructure investments in roads, water, and
sewer facilities. Housing needs for gas and related
workers will increase. Will their needs be met with a
temporary variety of housing or is the plan to build
long-term residential areas that will be attractive to
gas industry workers and their families?
There will also be new service, public safety, and other expenses
imposed on local governments that may not be
consistent with tax revenues derived from natural gas
drilling or leasing activities.
To address these complex issues, the comprehensive
planning undertaken by municipalities and
counties should have four components:
1. Taxation and municipal finance: a component to
examine tax revenues and expenditures related
to gas exploration and project future financial
resources needed for municipal and county operations,
and school districts in the region.
2. Public investment: for examining and developing
a plan on how municipalities, counties, and
school districts can use their assets and facilities
to generate revenues from drilling, transmission,
water, and wastewater activities related to gas
exploration.
3. Comprehensive land use: a plan to incorporate
natural gas development as a new and distinctive
land use and provide for economic development,
new commercial and residential activity, and
improvements to the local transportation system.
4. Municipal management: a component of planning
to provide personnel that will keep track of
mining activities, carry out inspections, anticipate
production changes, and encourage workforce
development to supply skilled workers. Since gas
exploration is regional in scope, the management
process needs to be carried out jointly by affected
municipalities, counties, and school districts, as
well as the private sector.
The vast economic and social impacts related
to exploration of the Marcellus shale deposit call
for new thinking. Sound, innovative, continuous
comprehensive planning is needed for Pennsylvania
municipalities to maximize the long-term benefits
from Marcellus shale development while minimizing
potential negative impacts.
The experience of some local governments
with the gas companies has been very positive, and
many companies have shown a desire to conduct
themselves appropriately within the community.
The companies are investing millions of dollars into
drilling and pipeline construction with plans to remain
in the drilling areas for years. The length of these
relationships demands a certain level of cooperation
between parties, and jeopardizing the ability of the
companies to operate would be detrimental to a
productive and beneficial relationship. It is important
for municipal officials to ensure good communication
and collaboration, with a method for quickly and
easily addressing problems if they occur.
Areas to Consider
Road Bonding
The Commonwealth can prohibit the use of and
impose size or weight restrictions on highways and
bridges under its jurisdiction in accordance with
Department of Transportation regulations. Trucks
considered heavy haulers must pay for the road
damages that they create; thus, bonding is necessary.
No vehicles in excess of the size or weight
limitations specified are allowed on Pennsylvania
highways unless the department or local authority
grants a waiver. Local authorities that post size or
weight restrictions, either in accordance with the
size, weight, and load chapter or that differ from that
chapter, must comply with the department regulations.
Posting and bonding municipal roads is
authorized in the state vehicle code.
The PennDOT
Bureau of Maintenance and Operations is in charge
of municipal road posting and bonding information.
You can also find codes for the authorization to use
bridges posted owing to condition of the bridge and
to use highways posted because of traffic conditions.
Some of the key provisions of road bonding include:
• Posting: a road must be posted with a weight
limit before a bond can be required of a hauler.
The steps taken to establish a weight limit include
(1) completing an engineering and traffic study
that supports the need for a weight restriction;
(2) passing an ordinance identifying the road
segment and setting the weight restriction; (3)
advertising the posting two times in a general
circulation newspaper at least five days prior
to actual posting; (4) contacting known heavy
haulers who are using the road about executing a
maintenance agreement; and (5) erecting standard
signs showing the weight limit.
• Excess maintenance agreement: after posting a
road, the local government enters into an excess
maintenance agreement with each hauler who will
be operating overweight vehicles on that road.
This agreement allows the local government to
shift responsibility for repairing road damages
on a pro rata basis to the haulers who damage the
road. Note that haulers are only responsible for
damage they cause in excess of normal wear and
tear on the road.
• Permits: driving an overweight vehicle on posted
roads generally requires a permit. The type of
permit depends on the number of vehicles, the
number of posted roads used, and the amount of
use. Permits are issued only after an excess maintenance
agreement has been signed.
• Inspections and monitoring: before overweight
hauling begins, the local government inspects the
road to determine its condition. The hauler who
pays for this service has the right to be present.
After hauling begins, the local government is
responsible for monitoring the condition of the
road and notifying the hauler of any necessary
repairs. If the local government is responsible for
making the repairs under the excess maintenance
agreement, the local government bills the hauler
for the costs.
• Security (bonding): haulers generally must provide
security to ensure payment for any road repairs for
which they are responsible under the agreement.
This security is usually a performance bond, a
standby letter of credit, or a certified bank check.
The regulations specify the amount of security that
may be required for unpaved roads ($6,000 per
linear mile) and paved roads ($12,500 per linear
mile) in cases wherein the hauler agrees not to
downgrade the road. When the local government
and the hauler agree that the road type can be
downgraded during hauling and restored after
hauling ceases, the amount of security required is
$50,000 per linear mile. If the hauler uses several
roads for only a short time or makes relatively few
trips, the rates per mile may be replaced with a flat
rate of $10,000. By following these rules, local
officials can assure taxpayers that they will not
have to pay for road repairs caused by overweight
vehicles.
Local governments considering road bonding or
posting weight limits on bridges should carefully
consider potential impacts on other road users since
they may unintentionally affect others. Bridge weight
limits, for example, could make it difficult for milk
trucks or feed trucks to reach farms, hurting those
businesses.
For more about road bonding, see PennDot
publication 221: Posting and Bonding Procedures for
Municipal Highways, which may be purchased from
the PennDOT store. ftp://ftp.dot.state.pa.us/public/
PubsForms/Publications/PUB%2012.pdf
Zoning and Subdivision and Land Development
Ordinances
At the time of the writing of this publication,
Pennsylvania’s Oil and Gas Act and the Municipalities
Planning Code restrict the ability of local
governments to zone or permit drilling, so zoning
has limited usefulness to influence where and when
drilling occurs. Yet zoning and subdivision and land
development ordinances remain a vitally important
tool for influencing the potential secondary effects
of natural gas activity, such as from possible new
residents, housing, supporting businesses, patterns
of development, and the other spinoff impacts. Much
of the economic opportunity (and challenge) from
Marcellus will be these secondary effects, which can
be influenced and regulated through zoning and other
land-use tools.
Capital Budgeting
Capital budgeting is a powerful but often underutilized
tool of Pennsylvania local governments. By
planning future expenditure needs for infrastructure
and other capital expenses, such as road maintenance
and repair, trucks, and equipment, capital budgets
allow the local government to ensure it has the funds
in hand to pay for upcoming needs. This includes a
schedule of setting funds aside for future needs and
anticipating spending for future needs in current
budget decisions.
Local Natural Gas Task Force
Given the localized nature of many of these impacts,
a local, comprehensive, and proactive approach can
help ensure that a wide range of the community’s
interests are represented—and importantly—
taken into account when decisions are made. One
important way to meet this challenge is to create a
local task force or a similar organized effort to guide
community discussions, information gathering, and
decision making. Members should reflect the broad
community, including businesses, the chamber of
commerce, nonprofits, schools, local government,
and citizens, among others. Such a task force can
ensure that regular communication occurs among
local governments, the business sector, real estate,
workforce development, academics, service
providers, and citizens, and that the community is
able to be proactive about the opportunities.
As of this publication, several counties in Pennsylvania
have already formed local task forces to
address gas exploration and development issues in
their communities. Several counties in Texas helped
pioneer this approach to responding to the natural gas
opportunities and challenges and have found it useful.
For a more in-depth discussion of ways to build a
successful local strategy, see the Penn State publication
“Creating and Fostering a Local Task Force”
available from http://www.naturalgas.psu.edu/.
Leasing Municipal Land
Many Pennsylvania local governments themselves
will have the opportunity to lease their own land, such
as parks, open space, reservoirs, and other municipal
property, and may receive substantial royalty
income in the future. If a local government has this
opportunity, it is vital to take care during the leasing
process.
As with landowners, Penn State Cooperative
Extension’s Marcellus Education Team recommends
talking with several companies and with an attorney
familiar with leasing issues because the typical
contract offered by the companies may not adequately
protect or represent municipal interests and likely
will require some amendments written by an attorney.
Those issues may include the ability to jointly approve
the location of access roads, drilling pad locations, and
how land is cleared (and disposal of the trees).
Site restoration is another postdrilling issue that
local officials should try to address. Restoration is
a requirement for all drilling sites and is regulated
by DEP. However, it is important for local officials
to talk with gas companies about the specifications
of each site’s restoration to ensure that the recreated
habitat is appropriate for the area. Site restoration
should be conducted in accordance to the surrounding
ecology of the well site so that local wildlife is
provided the proper vegetation species and coverage
for their environment.
It is also critical for local officials to carefully
consider how leasing and royalty income will be used.
It may be tempting to use the funds to cover current
operating expenses, reducing taxes in the short run.
But the dollars result from the sale of a capital asset,
so they should be used for capital expenditures that
benefit more than just current residents; the gas being
sold also is owned by future generations of residents,
who also should benefit from the sale. Good fiscal
management suggests viewing these dollars as a
way to invest in the future of the jurisdiction, such as
building infrastructure or purchasing land and other
assets that benefit current and future residents; in
other words, use the windfall gains to improve the
community for the long run, not just for the period
when the gas is flowing.
Looking Ahead
Marcellus shale is providing many Pennsylvania
communities a significant opportunity for strong
economic development and improvements in the
quality of life. Along with these strong opportunities,
major challenges will need to be addressed directly.
The role of local officials should be to help balance
these challenges and benefits to ensure the focus is
not just short-term gain. They must constantly keep
in mind how to use this opportunity to improve
the community for the long run so that when the
Marcellus play is over, the community has improved
and is poised for the future. ■
Peter
Economic Development
The size of the economic impacts from Marcellus
depend critically on whether the businesses exist
within the Pennsylvania communities to support
ancillary economic activity created by natural gas
exploration and development. The more spending
that occurs outside the community, the less economic
benefit will accrue locally since those dollars will
simply leave the community rather than recirculating
among local businesses.
Similarly, to the extent
nonresidents hold new jobs, the lower the benefit to
the community. The twofold economic development
challenge is thus:
1. Finding ways to help local businesses and workers
compete for the new business opportunities
arising from natural gas.
2. Finding ways to encourage businesses, workers,
and royalty owners to spend their new dollars
locally rather than out of town. New business
start-up and technical assistance should target
business opportunities related to natural gas, and
workforce development training should focus on
the new specialized jobs that will be created (such
as land men who service the wells).
General local business and community development
programs focused on helping local businesses
or downtowns be competitive could similarly help
Pennsylvania communities better compete for the
new spending resulting from the natural gas revenues.
Environmental Impacts
The construction, activity, and existence of natural
gas wells in the community and industry may cause
significant environmental changes to the areas.
These issues should be considered when planning
and enforcing local action to accommodate the
developing gas industry. Possible environmental
concerns that could arise from drilling activity
include:
• Aesthetics and recreation—heightened noise and
the effects of drilling may affect the aesthetics and
recreational value of a resource for both nonconsumptive
(e.g., hiking, birding) and consumptive
(e.g., fishing, hunting) recreational use. This may
affect communities that are promoting natural resource-
based tourism.
• Habitat fragmentation—well sites and associated
infrastructure may fragment Pennsylvania forests.
Fragmentation will decrease habitat quality for
many wildlife species that are dependent on
deep forest habitat; it is also associated with an
increased spread of nonnative and invasive plants,
causing further habitat degradation for native
plants and animals.
• Water impacts—water consumption and
wastewater disposal may affect aquatic resources
both locally and within the larger watershed.
• Timber resources—access roads and pipelines
may cause damage to timber stands, resulting
in loss of forestry income, appraisal, and sale of
timber.
• Soil compaction and long-term site fertility—
well sites may compact the soil, affecting the
long-term health and fertility of the area.
Forestry concerns that show effects on forests,
wildlife, ecology, and local natural balance need to
be addressed by DEP, Conservation Districts, and
other associated agencies through regulation and
enforcement.
After drilling has occurred in an area,
proper site restoration is a necessity. The best ways
to restore sites depend on the location and natural
surroundings, making it necessary for officials to
gather information on the pros and cons of different
methods of site restoration. The type and quantity of
vegetation replanted will make a large impact on the
natural ecology and balance.
What Local Officials Can Do
Local government officials concerned about the
impact of Marcellus shale development on their
community need to greatly expand and upgrade their
comprehensive community planning efforts. The fast
pace of gas drilling—and all its related activities—
means that planning must be done on a continuous,
daily basis. Every new well that is drilled causes small
changes in the community. Monthly meetings of the
planning commission are not sufficient to keep up
with these changes.
We also need a new way to think
about how communities plan for gas exploration.
Comprehensive community planning is more
than just the established “comprehensive plan.” A
comprehensive plan, as permitted in the Municipalities
Planning Code, serves as a useful tool for
municipal management by providing a broad, general
framework for common development issues projected
ten to twenty years into the future. This would be
acceptable if things did not change very quickly, but
that is not the case with gas drilling. Few comprehensive
plans were prepared with major natural gas
development in mind, so they are not adequately
prepared to address the potential impacts of the
Marcellus shale formation.
A more comprehensive view must take into
account all the important issues and how they interrelate
to one another. This view involves more
than just land use. Gas drilling brings many new
factors to communities that have not been experienced
previously in many areas of Pennsylvania.
Exploration of the Marcellus shale will generate
large amounts of money from the leasing of land,
construction, trucking, commerce, and housing development.
Some residents will have more money to
spend, but will they spend it in the community and
region? Will they take that capital somewhere else
if there are no places for them to spend their money
locally?
New opportunities for business development
should increase with gas drilling, which will require
infrastructure investments in roads, water, and
sewer facilities. Housing needs for gas and related
workers will increase. Will their needs be met with a
temporary variety of housing or is the plan to build
long-term residential areas that will be attractive to
gas industry workers and their families?
There will also be new service, public safety, and other expenses
imposed on local governments that may not be
consistent with tax revenues derived from natural gas
drilling or leasing activities.
To address these complex issues, the comprehensive
planning undertaken by municipalities and
counties should have four components:
1. Taxation and municipal finance: a component to
examine tax revenues and expenditures related
to gas exploration and project future financial
resources needed for municipal and county operations,
and school districts in the region.
2. Public investment: for examining and developing
a plan on how municipalities, counties, and
school districts can use their assets and facilities
to generate revenues from drilling, transmission,
water, and wastewater activities related to gas
exploration.
3. Comprehensive land use: a plan to incorporate
natural gas development as a new and distinctive
land use and provide for economic development,
new commercial and residential activity, and
improvements to the local transportation system.
4. Municipal management: a component of planning
to provide personnel that will keep track of
mining activities, carry out inspections, anticipate
production changes, and encourage workforce
development to supply skilled workers. Since gas
exploration is regional in scope, the management
process needs to be carried out jointly by affected
municipalities, counties, and school districts, as
well as the private sector.
The vast economic and social impacts related
to exploration of the Marcellus shale deposit call
for new thinking. Sound, innovative, continuous
comprehensive planning is needed for Pennsylvania
municipalities to maximize the long-term benefits
from Marcellus shale development while minimizing
potential negative impacts.
The experience of some local governments
with the gas companies has been very positive, and
many companies have shown a desire to conduct
themselves appropriately within the community.
The companies are investing millions of dollars into
drilling and pipeline construction with plans to remain
in the drilling areas for years. The length of these
relationships demands a certain level of cooperation
between parties, and jeopardizing the ability of the
companies to operate would be detrimental to a
productive and beneficial relationship. It is important
for municipal officials to ensure good communication
and collaboration, with a method for quickly and
easily addressing problems if they occur.
Areas to Consider
Road Bonding
The Commonwealth can prohibit the use of and
impose size or weight restrictions on highways and
bridges under its jurisdiction in accordance with
Department of Transportation regulations. Trucks
considered heavy haulers must pay for the road
damages that they create; thus, bonding is necessary.
No vehicles in excess of the size or weight
limitations specified are allowed on Pennsylvania
highways unless the department or local authority
grants a waiver. Local authorities that post size or
weight restrictions, either in accordance with the
size, weight, and load chapter or that differ from that
chapter, must comply with the department regulations.
Posting and bonding municipal roads is
authorized in the state vehicle code.
The PennDOT
Bureau of Maintenance and Operations is in charge
of municipal road posting and bonding information.
You can also find codes for the authorization to use
bridges posted owing to condition of the bridge and
to use highways posted because of traffic conditions.
Some of the key provisions of road bonding include:
• Posting: a road must be posted with a weight
limit before a bond can be required of a hauler.
The steps taken to establish a weight limit include
(1) completing an engineering and traffic study
that supports the need for a weight restriction;
(2) passing an ordinance identifying the road
segment and setting the weight restriction; (3)
advertising the posting two times in a general
circulation newspaper at least five days prior
to actual posting; (4) contacting known heavy
haulers who are using the road about executing a
maintenance agreement; and (5) erecting standard
signs showing the weight limit.
• Excess maintenance agreement: after posting a
road, the local government enters into an excess
maintenance agreement with each hauler who will
be operating overweight vehicles on that road.
This agreement allows the local government to
shift responsibility for repairing road damages
on a pro rata basis to the haulers who damage the
road. Note that haulers are only responsible for
damage they cause in excess of normal wear and
tear on the road.
• Permits: driving an overweight vehicle on posted
roads generally requires a permit. The type of
permit depends on the number of vehicles, the
number of posted roads used, and the amount of
use. Permits are issued only after an excess maintenance
agreement has been signed.
• Inspections and monitoring: before overweight
hauling begins, the local government inspects the
road to determine its condition. The hauler who
pays for this service has the right to be present.
After hauling begins, the local government is
responsible for monitoring the condition of the
road and notifying the hauler of any necessary
repairs. If the local government is responsible for
making the repairs under the excess maintenance
agreement, the local government bills the hauler
for the costs.
• Security (bonding): haulers generally must provide
security to ensure payment for any road repairs for
which they are responsible under the agreement.
This security is usually a performance bond, a
standby letter of credit, or a certified bank check.
The regulations specify the amount of security that
may be required for unpaved roads ($6,000 per
linear mile) and paved roads ($12,500 per linear
mile) in cases wherein the hauler agrees not to
downgrade the road. When the local government
and the hauler agree that the road type can be
downgraded during hauling and restored after
hauling ceases, the amount of security required is
$50,000 per linear mile. If the hauler uses several
roads for only a short time or makes relatively few
trips, the rates per mile may be replaced with a flat
rate of $10,000. By following these rules, local
officials can assure taxpayers that they will not
have to pay for road repairs caused by overweight
vehicles.
Local governments considering road bonding or
posting weight limits on bridges should carefully
consider potential impacts on other road users since
they may unintentionally affect others. Bridge weight
limits, for example, could make it difficult for milk
trucks or feed trucks to reach farms, hurting those
businesses.
For more about road bonding, see PennDot
publication 221: Posting and Bonding Procedures for
Municipal Highways, which may be purchased from
the PennDOT store. ftp://ftp.dot.state.pa.us/public/
PubsForms/Publications/PUB%2012.pdf
Zoning and Subdivision and Land Development
Ordinances
At the time of the writing of this publication,
Pennsylvania’s Oil and Gas Act and the Municipalities
Planning Code restrict the ability of local
governments to zone or permit drilling, so zoning
has limited usefulness to influence where and when
drilling occurs. Yet zoning and subdivision and land
development ordinances remain a vitally important
tool for influencing the potential secondary effects
of natural gas activity, such as from possible new
residents, housing, supporting businesses, patterns
of development, and the other spinoff impacts. Much
of the economic opportunity (and challenge) from
Marcellus will be these secondary effects, which can
be influenced and regulated through zoning and other
land-use tools.
Capital Budgeting
Capital budgeting is a powerful but often underutilized
tool of Pennsylvania local governments. By
planning future expenditure needs for infrastructure
and other capital expenses, such as road maintenance
and repair, trucks, and equipment, capital budgets
allow the local government to ensure it has the funds
in hand to pay for upcoming needs. This includes a
schedule of setting funds aside for future needs and
anticipating spending for future needs in current
budget decisions.
Local Natural Gas Task Force
Given the localized nature of many of these impacts,
a local, comprehensive, and proactive approach can
help ensure that a wide range of the community’s
interests are represented—and importantly—
taken into account when decisions are made. One
important way to meet this challenge is to create a
local task force or a similar organized effort to guide
community discussions, information gathering, and
decision making. Members should reflect the broad
community, including businesses, the chamber of
commerce, nonprofits, schools, local government,
and citizens, among others. Such a task force can
ensure that regular communication occurs among
local governments, the business sector, real estate,
workforce development, academics, service
providers, and citizens, and that the community is
able to be proactive about the opportunities.
As of this publication, several counties in Pennsylvania
have already formed local task forces to
address gas exploration and development issues in
their communities. Several counties in Texas helped
pioneer this approach to responding to the natural gas
opportunities and challenges and have found it useful.
For a more in-depth discussion of ways to build a
successful local strategy, see the Penn State publication
“Creating and Fostering a Local Task Force”
available from http://www.naturalgas.psu.edu/.
Leasing Municipal Land
Many Pennsylvania local governments themselves
will have the opportunity to lease their own land, such
as parks, open space, reservoirs, and other municipal
property, and may receive substantial royalty
income in the future. If a local government has this
opportunity, it is vital to take care during the leasing
process.
As with landowners, Penn State Cooperative
Extension’s Marcellus Education Team recommends
talking with several companies and with an attorney
familiar with leasing issues because the typical
contract offered by the companies may not adequately
protect or represent municipal interests and likely
will require some amendments written by an attorney.
Those issues may include the ability to jointly approve
the location of access roads, drilling pad locations, and
how land is cleared (and disposal of the trees).
Site restoration is another postdrilling issue that
local officials should try to address. Restoration is
a requirement for all drilling sites and is regulated
by DEP. However, it is important for local officials
to talk with gas companies about the specifications
of each site’s restoration to ensure that the recreated
habitat is appropriate for the area. Site restoration
should be conducted in accordance to the surrounding
ecology of the well site so that local wildlife is
provided the proper vegetation species and coverage
for their environment.
It is also critical for local officials to carefully
consider how leasing and royalty income will be used.
It may be tempting to use the funds to cover current
operating expenses, reducing taxes in the short run.
But the dollars result from the sale of a capital asset,
so they should be used for capital expenditures that
benefit more than just current residents; the gas being
sold also is owned by future generations of residents,
who also should benefit from the sale. Good fiscal
management suggests viewing these dollars as a
way to invest in the future of the jurisdiction, such as
building infrastructure or purchasing land and other
assets that benefit current and future residents; in
other words, use the windfall gains to improve the
community for the long run, not just for the period
when the gas is flowing.
Looking Ahead
Marcellus shale is providing many Pennsylvania
communities a significant opportunity for strong
economic development and improvements in the
quality of life. Along with these strong opportunities,
major challenges will need to be addressed directly.
The role of local officials should be to help balance
these challenges and benefits to ensure the focus is
not just short-term gain. They must constantly keep
in mind how to use this opportunity to improve
the community for the long run so that when the
Marcellus play is over, the community has improved
and is poised for the future. ■
Marcellus Shale Gas Play: Part 6
Money. Who profits and who suffers? There is no question that this shale gas development with generate revenue for everyone, from individuals to local, state and federal governments. The answer to the question of who benefits and who suffers lies in how that money is managed. Governments are notorious for being wasteful; but that is wholly another issue.
Greater employment owing to natural gas activity
will of course increase local earned income taxes,
but because earned income taxes generally go to the
jurisdiction where taxpayers live rather than where
they work, the specific jurisdictions facing higher
service costs due to the Marcellus may not be those
who receive higher earned income tax revenues. Most
Pennsylvanians do not work in the same municipality
where they live and there is little reason to expect
new natural gas workers to be any different.
Tax collections by the state government will
increase in Pennsylvania through the corporate income
tax and sales tax, but these collections will have little
direct benefit to the local jurisdictions, which will face
higher service costs due to natural gas exploration.
In other words, local jurisdictions with natural gas
wells very likely will face higher demands for services
and thus higher costs, and yet receive little new
revenues to pay for those services. The result could be
higher local taxes (paid for by everyone, not just those
directly benefiting from lease or royalty revenues)
or cuts in other services.
It is important to recognize that school districts
and the county and municipal governments that own
land leased for natural gas extraction may receive
significant revenues from leasing and royalties, so
they will receive some benefits. Yet the amount they
receive will not relate directly to the overall costs they
may experience across their jurisdiction.
Clean and Green Act
Under Pennsylvania law, county governments
administer the Clean and Green program, which
provides preferential tax assessments for eligible
Infrastructure
The potential impact of the increased drilling associated
with the Marcellus shale extends beyond the
wells, pipelines, and other natural-gas-related sites
and equipment. The economic and social changes a
region will experience once the industry has established
itself in the area may lead to stress on local
infrastructure, such as increases in road traffic, school
enrollment, and housing needs.
Obtaining seismic data also generates revenue for landowners.
Compressors
Compressors are used to increase the gas pressure
from the wells before being shipped to market and can
produce significant amounts of unwanted noise. Since
compressors run nonstop, this can create concerns for
local officials who handle noise disturbances. Some
well sites will house the compressors in buildings to
decrease the output of noise, which can improve the
problem but also results in the creation of permanent
structures on site.
Pipelines
Any gas produced from wells is valueless unless it
reaches market. Pipelines are necessary for moving
the gas and are laid to travel from the site out to
Pipelines should be acknowledged as permanent
infrastructure of the gas industry and their
construction should be strategic and efficient.
Local officials need to concern themselves with
influencing pipeline construction in hopes of minimizing
potentially unnecessary lines. Excessive lines
across local landscapes could result from poorly
planned or disjointed networks of pipelines. 
Pipelines are needed to collect the gas and move it to the end-users.
Population Change and Impacts on the
Community
Housing, Schools, Crime
As indicated by the experience in Texas and
Wyoming, it is important for local officials to prepare
for the population changes that may occur due to
the Marcellus. As noted in the studies conducted in
similar circumstances across the country, some of
the major associated changes in the community will
likely be:
• The need for adequate housing stock. If an inadequate
amount of housing is an issue, the influx of
workers will not live in the community, therefore
affecting the large array of possible economic
benefits for local business and government.
• Impacts on schools and service industries will
change the dynamic of the community as well,
seeing student population increases, higher
government infrastructure expenses, etc.
• An increase in crime, particularly nonviolent
crimes such as driving under the influence and
drug violations.
• Social tension or animosity between “newcomers”
and “old timers,” or between residents gaining
personally from natural gas and others in the
community who feel they are not benefitting.
• Local officials should reevaluate their comprehensive
plan, official map, and other planning
tools they use in their communities to cater to or
prepare for these changes. In addition, education
and communication can be important tools to deal
with potential changes in the social fabric of the
community.
Peter
Revenues
Due to Pennsylvania’s local tax structure, the revenue
impacts of Marcellus shale on Pennsylvania local
governments and taxpayers will likely be relatively
small compared to the cost and service impacts.
Natural gas exploration and drilling by itself will
provide relatively little new tax revenues to local
jurisdictions in Pennsylvania since natural gas is not
Due to Pennsylvania’s local tax structure, the revenue
impacts of Marcellus shale on Pennsylvania local
governments and taxpayers will likely be relatively
small compared to the cost and service impacts.
Natural gas exploration and drilling by itself will
provide relatively little new tax revenues to local
jurisdictions in Pennsylvania since natural gas is not
subject to local taxation in the Commonwealth. Neither
lease nor royalty income in Pennsylvania is subject to local
lease nor royalty income in Pennsylvania is subject to local
income taxes, nor do Pennsylvania
local jurisdictions benefit directly from higher local
retail sales since they lack authority to levy a local
sales tax.
local jurisdictions benefit directly from higher local
retail sales since they lack authority to levy a local
sales tax.
Greater employment owing to natural gas activity
will of course increase local earned income taxes,
but because earned income taxes generally go to the
jurisdiction where taxpayers live rather than where
they work, the specific jurisdictions facing higher
service costs due to the Marcellus may not be those
who receive higher earned income tax revenues. Most
Pennsylvanians do not work in the same municipality
where they live and there is little reason to expect
new natural gas workers to be any different.
Real property tax collections will increase some
due to new building construction associated with the
Marcellus; but, because reassessment is typically
infrequent in Pennsylvania counties, rising real
property values due to Marcellus will not have an
immediate impact on property tax collections. Under
current law natural gas will not significantly increase
the local tax base, and thus will not significantly
increase local tax revenues.
due to new building construction associated with the
Marcellus; but, because reassessment is typically
infrequent in Pennsylvania counties, rising real
property values due to Marcellus will not have an
immediate impact on property tax collections. Under
current law natural gas will not significantly increase
the local tax base, and thus will not significantly
increase local tax revenues.
Tax collections by the state government will
increase in Pennsylvania through the corporate income
tax and sales tax, but these collections will have little
direct benefit to the local jurisdictions, which will face
higher service costs due to natural gas exploration.
In other words, local jurisdictions with natural gas
wells very likely will face higher demands for services
and thus higher costs, and yet receive little new
revenues to pay for those services. The result could be
higher local taxes (paid for by everyone, not just those
directly benefiting from lease or royalty revenues)
or cuts in other services.
Because Pennsylvania law
limits municipalities’ and counties’ abilities to employ
land-use planning tools to influence the location
of natural gas drilling activities, local governments
will have little ability to prevent or affect drilling in
locations, which will significantly affect local service
costs and taxes.
limits municipalities’ and counties’ abilities to employ
land-use planning tools to influence the location
of natural gas drilling activities, local governments
will have little ability to prevent or affect drilling in
locations, which will significantly affect local service
costs and taxes.
It is important to recognize that school districts
and the county and municipal governments that own
land leased for natural gas extraction may receive
significant revenues from leasing and royalties, so
they will receive some benefits. Yet the amount they
receive will not relate directly to the overall costs they
may experience across their jurisdiction.
In addition,
some may be tempted to use these windfalls for
basic operations (keeping taxes low in the years the
monies are received) rather than to use the monies
for capital expenditures and other investments in
their communities’ future. The natural gas money
provides a great opportunity for local jurisdictions to
improve infrastructure, such as by creating parks or
other investments to be enjoyed by current and future
generations.
some may be tempted to use these windfalls for
basic operations (keeping taxes low in the years the
monies are received) rather than to use the monies
for capital expenditures and other investments in
their communities’ future. The natural gas money
provides a great opportunity for local jurisdictions to
improve infrastructure, such as by creating parks or
other investments to be enjoyed by current and future
generations.
Clean and Green Act
Under Pennsylvania law, county governments
administer the Clean and Green program, which
provides preferential tax assessments for eligible
farm- and forestland. County governments have some
discretion in how they interpret the law, which at the
time of this writing is silent about whether leasing
land for natural gas drilling makes the land ineligible
for Clean and Green (and, if so, whether the rollback
is on the entire enrolled parcel or only on the acreage
directly affected by the drilling).
discretion in how they interpret the law, which at the
time of this writing is silent about whether leasing
land for natural gas drilling makes the land ineligible
for Clean and Green (and, if so, whether the rollback
is on the entire enrolled parcel or only on the acreage
directly affected by the drilling).
County commissioners
and assessment offices need to carefully think
about how they will treat such land and the impact of
that decision on landowners, neighbors, taxpayers,
Clean and Green land, and gas leasing activity.
In Harrisburg there currently is policy discussion
about whether to revise the Clean and Green Act to
provide more clarity on issues of interpretation. For
more information, visit the Pennsylvania Department
of Agriculture Web site, http://www.agriculture.state.pa.us/.
and assessment offices need to carefully think
about how they will treat such land and the impact of
that decision on landowners, neighbors, taxpayers,
Clean and Green land, and gas leasing activity.
In Harrisburg there currently is policy discussion
about whether to revise the Clean and Green Act to
provide more clarity on issues of interpretation. For
more information, visit the Pennsylvania Department
of Agriculture Web site, http://www.agriculture.state.pa.us/.
Infrastructure
The potential impact of the increased drilling associated
with the Marcellus shale extends beyond the
wells, pipelines, and other natural-gas-related sites
and equipment. The economic and social changes a
region will experience once the industry has established
itself in the area may lead to stress on local
infrastructure, such as increases in road traffic, school
enrollment, and housing needs.
Obtaining seismic data also generates revenue for landowners.Access Roads
Once a well site is chosen and established, private
access roads will be built to enable the necessary
large equipment and trucks to reach and service that
particular well. In addition to these newly constructed
roadways to the well pad, the initial preparation to
begin drilling and producing gas delivers a considerable
amount of heavy traffic to surrounding local
roads.
Once a well site is chosen and established, private
access roads will be built to enable the necessary
large equipment and trucks to reach and service that
particular well. In addition to these newly constructed
roadways to the well pad, the initial preparation to
begin drilling and producing gas delivers a considerable
amount of heavy traffic to surrounding local
roads.
It is important to remember, however, that
after site construction, the wells will still generate
consistent truck traffic and road use. Holding tanks
on site for water by-products created during drilling
must be emptied at least once, if not several times,
per week and will be hauled to treatment or injection
facilities. Since wells produce year-round, road use
and truck traffic on both access and local roads will
be occurring year-round.
after site construction, the wells will still generate
consistent truck traffic and road use. Holding tanks
on site for water by-products created during drilling
must be emptied at least once, if not several times,
per week and will be hauled to treatment or injection
facilities. Since wells produce year-round, road use
and truck traffic on both access and local roads will
be occurring year-round.
Compressors
Compressors are used to increase the gas pressure
from the wells before being shipped to market and can
produce significant amounts of unwanted noise. Since
compressors run nonstop, this can create concerns for
local officials who handle noise disturbances. Some
well sites will house the compressors in buildings to
decrease the output of noise, which can improve the
problem but also results in the creation of permanent
structures on site.
Pipelines
Any gas produced from wells is valueless unless it
reaches market. Pipelines are necessary for moving
the gas and are laid to travel from the site out to
central gathering points where the lines continue
transporting larger quantities of gas from numerous
wells to market. The pipeline construction affects
environmental and aesthetic aspects of the area and
generates additional construction sites and associated
disturbances.
transporting larger quantities of gas from numerous
wells to market. The pipeline construction affects
environmental and aesthetic aspects of the area and
generates additional construction sites and associated
disturbances.
Pipelines should be acknowledged as permanent
infrastructure of the gas industry and their
construction should be strategic and efficient.
Local officials need to concern themselves with
influencing pipeline construction in hopes of minimizing
potentially unnecessary lines. Excessive lines
across local landscapes could result from poorly
planned or disjointed networks of pipelines.
Pipelines are needed to collect the gas and move it to the end-users.Population Change and Impacts on the
Community
Housing, Schools, Crime
As indicated by the experience in Texas and
Wyoming, it is important for local officials to prepare
for the population changes that may occur due to
the Marcellus. As noted in the studies conducted in
similar circumstances across the country, some of
the major associated changes in the community will
likely be:
• The need for adequate housing stock. If an inadequate
amount of housing is an issue, the influx of
workers will not live in the community, therefore
affecting the large array of possible economic
benefits for local business and government.
• Impacts on schools and service industries will
change the dynamic of the community as well,
seeing student population increases, higher
government infrastructure expenses, etc.
• An increase in crime, particularly nonviolent
crimes such as driving under the influence and
drug violations.
• Social tension or animosity between “newcomers”
and “old timers,” or between residents gaining
personally from natural gas and others in the
community who feel they are not benefitting.
• Local officials should reevaluate their comprehensive
plan, official map, and other planning
tools they use in their communities to cater to or
prepare for these changes. In addition, education
and communication can be important tools to deal
with potential changes in the social fabric of the
community.
Marcellus Shale Gas Play: Part 5
Once again, there are many issues that must be dealt with in this kind of Shale Gas development. The old adage that "there ain't no free lunch" certainly applies. But are giant wind turbines for generating electricity any less disruptive of the environment? Are thousands of acres of solar panels better for the environment? Are they close to being as efficient a source of energy as natural gas?
Can we dam-up some more rivers and create hydro-electricity? Can we build more nuclear power plants? What about cutting trees to burn for heat? How intelligent is it to plow up hundreds of thousands of acres, plant corn, water and fertilize it, harvest it, and then distill it to produce ethanol to burn as a fuel in our vehicles? Honest answers to these questions make drilling for natural gas our best option.
Peter
Local Issues
Roads
The process of drilling, fracing, and maintaining
natural gas wells can create significant heavy truck
traffic on rural roads, many of which were not
designed for carrying vehicles of this size. A recent
well in Lycoming County, for example, reportedly
required 77 tractor trailer loads simply to bring the
drilling equipment to the site.
Traffic will also include
trucks carrying large amounts of water. A report from
Denton, Texas, suggests that each drilling site could
require 364 such water truck trips, which would be
equivalent to 3,494,400 car trips (Denton County Oil
and Gas Task Force, 2005).
Local governments do have the option of
requiring companies to post a bond, but this requires
careful planning ahead of time in order to achieve
this, and the local government must be diligent about
following procedures to recover costs if the gas
company causes damage.
Water Issues
Water usage has been a concern in other states where
deep well drilling and hydrofracing have generated
both a demand for large quantities of water and
resulting waste fluids that require removal and
treatment. The millions of gallons of water required
for drilling and the associated waste products are also
major concerns here in Pennsylvania. As in other
states, the source of water
used in drilling raises an
issue, as do the waste fluids,
their treatment and disposal,
and natural bodies of water in the
vicinities of drilling activity and the
communities tied to them.
Use
The Susquehanna River Basin
Commission (SRBC) regulates
significant water use
within its jurisdiction
(discussed below)
and recently ruled
that companies can
purchase water from
other permitted users with
excess capacity without prior approval of the SRBC,
provided that the total amounts used do not exceed
the permitted quantity.
As a result, widespread
interest has arisen among natural gas companies
in purchasing water from municipal water systems
and other already permitted users. If approached by
such a company, municipal water systems need to
carefully consider how much surplus capacity they
can sell without jeopardizing other users or other
future water-dependent economic development
opportunities.
Large water withdrawals may come from many
sources other than municipal water companies
(streams, ponds, lakes, etc.) and can have significant
effects if not performed carefully. Water withdrawals
generally exceeding 10,000 gallons per day require
permits or registration with DEP under authority
of the Water Resources Planning Act.
Withdrawals occurring in the Susquehanna or Delaware River
watersheds also require permits from the Susquehanna
River Basin Commission or the Delaware River Basin
Commission (discussed ahead). In addition, the Clean
Streams Law limits the amount of water that can be
withdrawn from streams to maintain sufficient stream
flows to protect aquatic life.
These various regulations have all
caused the shutting down of gas well drilling
operations that failed to acquire the proper permits or
exceeded allowable withdrawals from streams.
Another concern with deep gas well drilling
technologies is the disposal of large volumes of
wastewater resulting from the hydrofracturing
process. The water used in the drilling process is
mixed with sand and other products, and then is
pumped into the shale formation under high pressure
to fracture the shale so the natural gas can be
accessed. The volume of wastewater produced during
gas well drilling and operation can vary considerably
depending on the depth and location of the gas well.
One study in Pennsylvania found that the average
volumes of water produced during shallow gas well
drilling in western Pennsylvania was 25,000 gallons
during drilling, 50,000 gallons during stimulation,
and 150 gallons per day during production.
Drilling companies must identify where they
plan to obtain and store the water used in the drilling
operations and where the wastewater generated as part
of the drilling process (“frac” water) is to be stored,
treated, and disposed.
Erosion and Stormwater
Gas well construction involves extensive earth
disturbance, including roads, drilling pads, and
pipelines that can speed erosion. Drilling pads alone
may be four to six acres in size for deeper gas wells,
which is a larger portion of disturbed earth than used
for shallow well pads.
Various regulations, implemented through DEP
and Pennsylvania Conservation Districts, are in
place to protect surface water and groundwater from
erosion and sedimentation due to these disturbances.
Erosion and sediment control plan requirements
under state law apply to any earth disturbance
activities, including oil and gas drilling (Pa. Code
Chapter 102).
Erosion and sediment plans require gas
companies to use preventative measures such as filter
fence, sediment traps, vegetation, hay bales, culverts
with energy dissipaters, and rocked road entrances
to minimize erosion. These plans also include a
requirement to restore vegetation to the drill site
within nine months of well completion by planting
grass, trees, or crop plots.
For oil and gas activity on less than five acres,
an erosion and sediment control plan must contain
best management practices to minimize point-source
discharges to surface waters, preserve the integrity of
stream channels, and protect the physical, biological,
and chemical qualities of the receiving waterway.
For oil and gas activities that disturb more
than five acres at one time, a notice of intent and
general permit for authorization to control erosion
and sediment must be completed. The erosion and
sediment control plan or the notice of intent must be
submitted to DEP or an authorized county conservation
district for review and approval.
The DEP’s Bureau of Oil and Gas and each
individual county’s Conservation District oversee
the enforcement of erosion and sediment regulations
related to gas well operations.
Groundwater
While many residents throughout Pennsylvania
have voiced concerns about private water well and
spring contamination that can occur from gas well
drilling, the reality of these fears has shown to be
less prominent than assumed.
Data collected thus far from various
regulatory agencies responsible for
enforcement of gas well drilling regulations indicate
that more than 95 percent of complaints received
from homeowners suspecting problems from nearby
gas well drilling are in actuality due to preexisting
problems or other land-use activities such as
agriculture. However, when contamination does
occur as a result of drilling, the impacts can vary
greatly.
While the instances are low, it is important
to be aware of the range of possible complications.
Pennsylvania law requires that before drilling to
deeper zones, gas drillers must install cemented steel
casing through all freshwater aquifers. This casing
protects groundwater by isolating the borehole from
the groundwater system. It also keeps water from
the surface and other geologic strata from mixing
with and contaminating groundwater through the
borehole.
When pollution of private water supplies
from gas well activity occurs, it is often documented
as primarily stemming from absent or corroded well
casings on older or abandoned gas wells. That does
not mean that there are not pollution risks in newer
deep well drilling. Groundwater contamination can
result from flooded or leaking brine pits that contain
bottom-hole stimulation and production fluids from
drilling activities.
In the event of these types of mishaps and
negligence, pollution can still occur despite the
variety of regulations through DEP and the SRBC
and DRBC. When contamination does occur, it
should be noted that gas well brines are highly mineralized
and contain levels of some pollutants that are
far above levels considered safe for drinking water
supplies. As a result, even small amounts of brine
pollution can result in significant impacts to drinking
water supplies.
If problems with drinking water supplies are
encountered, state law requires drilling operators to
replace or restore water supplies affected by drilling.
Landowners should contact the drilling company
if problems with water supply wells develop.
Landowners who are not satisfied with the drilling
company’s response should contact the nearest DEP
regional office. DEP will investigate complaints
within ten days and issue orders as necessary to
replace or restore water supplies.
More information about water contaminates can
be found in related publications available through
the local Penn State Cooperative Extension office or
www.naturalgas.psu.edu.
Can we dam-up some more rivers and create hydro-electricity? Can we build more nuclear power plants? What about cutting trees to burn for heat? How intelligent is it to plow up hundreds of thousands of acres, plant corn, water and fertilize it, harvest it, and then distill it to produce ethanol to burn as a fuel in our vehicles? Honest answers to these questions make drilling for natural gas our best option.
Peter
Local Issues
Roads
The process of drilling, fracing, and maintaining
natural gas wells can create significant heavy truck
traffic on rural roads, many of which were not
designed for carrying vehicles of this size. A recent
well in Lycoming County, for example, reportedly
required 77 tractor trailer loads simply to bring the
drilling equipment to the site.
Traffic will also include
trucks carrying large amounts of water. A report from
Denton, Texas, suggests that each drilling site could
require 364 such water truck trips, which would be
equivalent to 3,494,400 car trips (Denton County Oil
and Gas Task Force, 2005).
Local governments do have the option of
requiring companies to post a bond, but this requires
careful planning ahead of time in order to achieve
this, and the local government must be diligent about
following procedures to recover costs if the gas
company causes damage.
Water Issues
Water usage has been a concern in other states where
deep well drilling and hydrofracing have generated
both a demand for large quantities of water and
resulting waste fluids that require removal and
treatment. The millions of gallons of water required
for drilling and the associated waste products are also
major concerns here in Pennsylvania. As in other
states, the source of water
used in drilling raises an
issue, as do the waste fluids,
their treatment and disposal,
and natural bodies of water in the
vicinities of drilling activity and the
communities tied to them.
Use
The Susquehanna River Basin
Commission (SRBC) regulates
significant water use
within its jurisdiction
(discussed below)
and recently ruled
that companies can
purchase water from
other permitted users with
excess capacity without prior approval of the SRBC,
provided that the total amounts used do not exceed
the permitted quantity.
As a result, widespread
interest has arisen among natural gas companies
in purchasing water from municipal water systems
and other already permitted users. If approached by
such a company, municipal water systems need to
carefully consider how much surplus capacity they
can sell without jeopardizing other users or other
future water-dependent economic development
opportunities.
Large water withdrawals may come from many
sources other than municipal water companies
(streams, ponds, lakes, etc.) and can have significant
effects if not performed carefully. Water withdrawals
generally exceeding 10,000 gallons per day require
permits or registration with DEP under authority
of the Water Resources Planning Act.
Withdrawals occurring in the Susquehanna or Delaware River
watersheds also require permits from the Susquehanna
River Basin Commission or the Delaware River Basin
Commission (discussed ahead). In addition, the Clean
Streams Law limits the amount of water that can be
withdrawn from streams to maintain sufficient stream
flows to protect aquatic life.
These various regulations have all
caused the shutting down of gas well drilling
operations that failed to acquire the proper permits or
exceeded allowable withdrawals from streams.
Another concern with deep gas well drilling
technologies is the disposal of large volumes of
wastewater resulting from the hydrofracturing
process. The water used in the drilling process is
mixed with sand and other products, and then is
pumped into the shale formation under high pressure
to fracture the shale so the natural gas can be
accessed. The volume of wastewater produced during
gas well drilling and operation can vary considerably
depending on the depth and location of the gas well.
One study in Pennsylvania found that the average
volumes of water produced during shallow gas well
drilling in western Pennsylvania was 25,000 gallons
during drilling, 50,000 gallons during stimulation,
and 150 gallons per day during production.
Drilling companies must identify where they
plan to obtain and store the water used in the drilling
operations and where the wastewater generated as part
of the drilling process (“frac” water) is to be stored,
treated, and disposed.
Erosion and Stormwater
Gas well construction involves extensive earth
disturbance, including roads, drilling pads, and
pipelines that can speed erosion. Drilling pads alone
may be four to six acres in size for deeper gas wells,
which is a larger portion of disturbed earth than used
for shallow well pads.
Various regulations, implemented through DEP
and Pennsylvania Conservation Districts, are in
place to protect surface water and groundwater from
erosion and sedimentation due to these disturbances.
Erosion and sediment control plan requirements
under state law apply to any earth disturbance
activities, including oil and gas drilling (Pa. Code
Chapter 102).
Erosion and sediment plans require gas
companies to use preventative measures such as filter
fence, sediment traps, vegetation, hay bales, culverts
with energy dissipaters, and rocked road entrances
to minimize erosion. These plans also include a
requirement to restore vegetation to the drill site
within nine months of well completion by planting
grass, trees, or crop plots.
For oil and gas activity on less than five acres,
an erosion and sediment control plan must contain
best management practices to minimize point-source
discharges to surface waters, preserve the integrity of
stream channels, and protect the physical, biological,
and chemical qualities of the receiving waterway.
For oil and gas activities that disturb more
than five acres at one time, a notice of intent and
general permit for authorization to control erosion
and sediment must be completed. The erosion and
sediment control plan or the notice of intent must be
submitted to DEP or an authorized county conservation
district for review and approval.
The DEP’s Bureau of Oil and Gas and each
individual county’s Conservation District oversee
the enforcement of erosion and sediment regulations
related to gas well operations.
Groundwater
While many residents throughout Pennsylvania
have voiced concerns about private water well and
spring contamination that can occur from gas well
drilling, the reality of these fears has shown to be
less prominent than assumed.
Data collected thus far from various
regulatory agencies responsible for
enforcement of gas well drilling regulations indicate
that more than 95 percent of complaints received
from homeowners suspecting problems from nearby
gas well drilling are in actuality due to preexisting
problems or other land-use activities such as
agriculture. However, when contamination does
occur as a result of drilling, the impacts can vary
greatly.
While the instances are low, it is important
to be aware of the range of possible complications.
Pennsylvania law requires that before drilling to
deeper zones, gas drillers must install cemented steel
casing through all freshwater aquifers. This casing
protects groundwater by isolating the borehole from
the groundwater system. It also keeps water from
the surface and other geologic strata from mixing
with and contaminating groundwater through the
borehole.
When pollution of private water supplies
from gas well activity occurs, it is often documented
as primarily stemming from absent or corroded well
casings on older or abandoned gas wells. That does
not mean that there are not pollution risks in newer
deep well drilling. Groundwater contamination can
result from flooded or leaking brine pits that contain
bottom-hole stimulation and production fluids from
drilling activities.
In the event of these types of mishaps and
negligence, pollution can still occur despite the
variety of regulations through DEP and the SRBC
and DRBC. When contamination does occur, it
should be noted that gas well brines are highly mineralized
and contain levels of some pollutants that are
far above levels considered safe for drinking water
supplies. As a result, even small amounts of brine
pollution can result in significant impacts to drinking
water supplies.
If problems with drinking water supplies are
encountered, state law requires drilling operators to
replace or restore water supplies affected by drilling.
Landowners should contact the drilling company
if problems with water supply wells develop.
Landowners who are not satisfied with the drilling
company’s response should contact the nearest DEP
regional office. DEP will investigate complaints
within ten days and issue orders as necessary to
replace or restore water supplies.
More information about water contaminates can
be found in related publications available through
the local Penn State Cooperative Extension office or
www.naturalgas.psu.edu.
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