The Abstract
"This report, prepared in cooperation with the Pennsylvania Department of Environmental Protection (PaDEP), the Eastern Pennsylvania Coalition for Abandoned Mine Reclamation, and the Dauphin County Conservation District, provides estimates of water budgets and groundwater volumes stored in abandoned underground mines in the Western Middle Anthracite Coalfield, which encompasses an area of 120 square miles in eastern Pennsylvania. The estimates are based on preliminary simulations using a groundwater-flow model and an associated geographic information system that integrates data on the mining features, hydrogeology, and streamflow in the study area. The Mahanoy and Shamokin Creek Basins were the focus of the study because these basins exhibit extensive hydrologic effects and water-quality degradation from the abandoned mines in their headwaters in the Western Middle Anthracite Coalfield. Proposed groundwater withdrawals from the flooded parts of the mines and stream-channel modifications in selected areas have the potential for altering the distribution of groundwater and the interaction between the groundwater and streams in the area.
Preliminary three-dimensional, steady-state simulations of groundwater flow by the use of MODFLOW are presented to summarize information on the exchange of groundwater among adjacent mines and to help guide the management of ongoing data collection, reclamation activities, and water-use planning. The conceptual model includes high-permeability mine voids that are connected vertically and horizontally within multicolliery units (MCUs). MCUs were identified on the basis of mine maps, locations of mine discharges, and groundwater levels in the mines measured by PaDEP. The locations and integrity of mine barriers were determined from mine maps and groundwater levels. The permeability of intact barriers is low, reflecting the hydraulic characteristics of unmined host rock and coal.
A steady-state model was calibrated to measured groundwater levels and stream base flow, the latter at many locations composed primarily of discharge from mines. Automatic parameter estimation used MODFLOW-2000 with manual adjustments to constrain parameter values to realistic ranges. The calibrated model supports the conceptual model of high-permeability MCUs separated by low-permeability barriers and streamflow losses and gains associated with mine infiltration and discharge. The simulated groundwater levels illustrate low groundwater gradients within an MCU and abrupt changes in water levels between MCUs. The preliminary model results indicate that the primary result of increased pumping from the mine would be reduced discharge from the mine to streams near the pumping wells. The intact barriers limit the spatial extent of mine dewatering. Considering the simulated groundwater levels, depth of mining, and assumed bulk porosity of 11 or 40 percent for the mined seams, the water volume in storage in the mines of the Western Middle Anthracite Coalfield was estimated to range from 60 to 220 billion gallons, respectively.
Details of the groundwater-level distribution and the rates of some mine discharges are not simulated well using the preliminary model. Use of the model results should be limited to evaluation of the conceptual model and its simulation using porous-media flow methods, overall water budgets for the Western Middle Anthracite Coalfield, and approximate storage volumes. Model results should not be considered accurate for detailed simulation of flow within a single MCU or individual flooded mine. Although improvements in the model calibration were possible by introducing spatial variability in permeability parameters and adjusting barrier properties, more detailed parameterizations have increased uncertainty because of the limited data set.
The preliminary identification of data needs includes continuous streamflow, mine discharge rate, and groundwater levels in the mines and adjacent areas. Data collected when the system is responding to hydrologic stresses such as recharge or pumping changes would provide information on hydraulic barrier integrity and groundwater/surface-water exchanges; the latter would also be informed by tracer studies and streambed surveys. Use of transient simulations, calibrated with transient measurements, is suggested to provide an independent estimate of the storage capacity of the mines."
Source:
Water Budgets and Groundwater Volumes for Abandoned Underground Mines in the Western Middle Anthracite Coalfield, Schuylkill, Columbia, and Northumberland Counties, Pennsylvania—Preliminary Estimates with Identification of Data Needs, By Daniel J. Goode, Charles A. Cravotta III, Roger J. Hornberger, Michael A. Hewitt, Robert E. Hughes, Daniel J. Koury, and Lee W. Eicholtz
How does this apply to the Marcellus Shale Play?
1. Mine Drainage may be the perfect surrogate raw water for Marcellus and other Unconventional Gas.
2. The concept
a. Select natrual or induced minewater discharge areas near existing wastewater treatment plans, raillines, or other accessible areas. It would be best to use rail rather than hauling or pipeline installed along rail right-of-ways.
Phase I
a. Rank Sites and Characterize Sources
b. Interpet Minewater as Natural or Artifical Discharge Points and install a rapid treatment module to aerate the water and remove iron and manganese. Collect iron and managense oxides and use as a raw material for treating other waste streams.
c. Send this water by rail or pipeline to Fracwater Treatment Areas or a central storage area.
d. Blend the fracwater and AMD waste streams
e. Repeat-
Phase II - Use a portion of the revenue to install passive treatment systems.
Phase III- Discontinue use of the fluid for hydraulic fracturing, but use the passive systems to treat natural discharges and pipelines to faciliate the movement of production water for treatment.
Phase IV - Use the water to reclaim abandon mine lands by helping to establish a native grassland - growing switchgrass and other native grasses. Harvest these grasses as a future sustainable field. My reclaiming the land - we are also helping to reduce the volume of acid mine drainage.
Just a thought
Brian Oram, PG
Native of Wilkes Barre, PA
http://www.bfenvironmental.com/
Showing posts with label frac water. Show all posts
Showing posts with label frac water. Show all posts
Tuesday, February 21, 2012
Saturday, October 29, 2011
PSU Study on Marcellus Drilling Impacts on Drinking Water Bromide
"Study on Marcellus Drilling Impacts on Drinking Water
Penn State scientists just released a report on water quality in private water wells in rural PA before and after drilling of nearby Marcellus Shale gas wells. Although the study didn’t find significant contamination of drinking water wells, researchers caution that there needs to be more intensive study.
They also noted unexpected high levels of bromide after drilling, and expressed concern for health impacts. In addition to testing water, the study also documented the enforcement of existing regulations and the extent of voluntary testing by homeowners.
The study, which took place in 2010 and 2011 focused on 233 water wells located in close proximity to Marcellus gas well pads. Phase I of the study (2010) tested 48 water wells within 2500 feet of a well pad both pre- and post-drilling. Phase II tested an additional 185 wells located within 5000 feet of a Marcellus gas well pad post-drilling.
A statistical analysis of pre- and post-drilling water chemistry did not find significant differences due to drilling or hydro-fracking when considering the pollutants “most prominent in drilling waste fluids.” Unlike the Duke study, this study found no significant increase in methane after drilling, and no significant correlations with distance from the well pad.
But, the researchers pointed out, this lack of data could be due to the lack of testing beyond 1000 feet. According to PA law the industry is presumed responsible for pollution of water supplies within 1000 feet of a well pad for six months after drilling. So, few people pay for testing beyond that distance.
One thing the scientists did find was increased levels of bromide in water wells after drilling and/or fracking. “These increases may suggest more subtle impacts to groundwater and the need for more research,” they write. Increased bromide levels were often accompanied by increased levels of sediment and metals in the water. These increased levels were observed within 3000 feet of the gas well pads – suggesting that 3000 feet is a more reasonable distance for testing than the current 1000 feet.
Bromide is rarely tested as part of the industry-sponsored pre-drilling baseline sampling. The PSU researchers selected bromide as a parameter for their study because it is typically not found in detectable concentrations in undisturbed groundwater and because it is found in relatively high concentrations in drilling gas wastes. For those reasons it serves as a good indicator of the influence of gas drilling on groundwater.
In the pre-drilling samples bromide levels were always well below detection levels (0.1 ppm). But in seven wells bromide was detected in measurable concentrations. Those wells were located within 1670 feet of five different Marcellus well pads that were operated by three separate companies.
While bromide does not present a health hazard by itself, it combines with disinfection agents to create a carcinogenic byproduct - and that concerns the researchers. They suggest two potential sources of the bromide: drilling mud and flowback fluids."
You can read more of their findings at
http://www.rural.palegislature.us/documents/reports/Marcellus_and_drinking_water_2011_rev.pdf
Comments
1. The above is not my work - but since this author will not permit me to comment - I will place my comments here:
a. It would have been good for PSU to document the type of activities that were used by those three companies. This could have generated a better idea of the practice that may have caused the problem. This could have lended support to : liners, closed loop drilling, use of only freshwater while drilling through the freshewater system, self-contained sites, etc. Also there was no comment regarding well location - side slope, upgradient, and/or downgradient.
b. Why after completing Phase I - and identifing a bromide issue was not this parameter evaluated in Phase II - did i miss something. If the only fingerprint from Phase I was bromide - why not do it in Phase II - and funding is not answer.
c. Did private well construction play a role?
d. The actual water quality data for the six wells presented in Figure 9 should be provided.
e. We recommended bromide monitoring in 2009.
Penn State scientists just released a report on water quality in private water wells in rural PA before and after drilling of nearby Marcellus Shale gas wells. Although the study didn’t find significant contamination of drinking water wells, researchers caution that there needs to be more intensive study.
They also noted unexpected high levels of bromide after drilling, and expressed concern for health impacts. In addition to testing water, the study also documented the enforcement of existing regulations and the extent of voluntary testing by homeowners.
The study, which took place in 2010 and 2011 focused on 233 water wells located in close proximity to Marcellus gas well pads. Phase I of the study (2010) tested 48 water wells within 2500 feet of a well pad both pre- and post-drilling. Phase II tested an additional 185 wells located within 5000 feet of a Marcellus gas well pad post-drilling.
A statistical analysis of pre- and post-drilling water chemistry did not find significant differences due to drilling or hydro-fracking when considering the pollutants “most prominent in drilling waste fluids.” Unlike the Duke study, this study found no significant increase in methane after drilling, and no significant correlations with distance from the well pad.
But, the researchers pointed out, this lack of data could be due to the lack of testing beyond 1000 feet. According to PA law the industry is presumed responsible for pollution of water supplies within 1000 feet of a well pad for six months after drilling. So, few people pay for testing beyond that distance.
One thing the scientists did find was increased levels of bromide in water wells after drilling and/or fracking. “These increases may suggest more subtle impacts to groundwater and the need for more research,” they write. Increased bromide levels were often accompanied by increased levels of sediment and metals in the water. These increased levels were observed within 3000 feet of the gas well pads – suggesting that 3000 feet is a more reasonable distance for testing than the current 1000 feet.
Bromide is rarely tested as part of the industry-sponsored pre-drilling baseline sampling. The PSU researchers selected bromide as a parameter for their study because it is typically not found in detectable concentrations in undisturbed groundwater and because it is found in relatively high concentrations in drilling gas wastes. For those reasons it serves as a good indicator of the influence of gas drilling on groundwater.
In the pre-drilling samples bromide levels were always well below detection levels (0.1 ppm). But in seven wells bromide was detected in measurable concentrations. Those wells were located within 1670 feet of five different Marcellus well pads that were operated by three separate companies.
While bromide does not present a health hazard by itself, it combines with disinfection agents to create a carcinogenic byproduct - and that concerns the researchers. They suggest two potential sources of the bromide: drilling mud and flowback fluids."
You can read more of their findings at
http://www.rural.palegislature.us/documents/reports/Marcellus_and_drinking_water_2011_rev.pdf
Comments
1. The above is not my work - but since this author will not permit me to comment - I will place my comments here:
a. It would have been good for PSU to document the type of activities that were used by those three companies. This could have generated a better idea of the practice that may have caused the problem. This could have lended support to : liners, closed loop drilling, use of only freshwater while drilling through the freshewater system, self-contained sites, etc. Also there was no comment regarding well location - side slope, upgradient, and/or downgradient.
b. Why after completing Phase I - and identifing a bromide issue was not this parameter evaluated in Phase II - did i miss something. If the only fingerprint from Phase I was bromide - why not do it in Phase II - and funding is not answer.
c. Did private well construction play a role?
d. The actual water quality data for the six wells presented in Figure 9 should be provided.
e. We recommended bromide monitoring in 2009.
Saturday, February 19, 2011
The right way to Manage Water in Northeast PA
SRBC’s role in regulating natural gas development in the Marcellus Shale
"Part two - What SRBC does not regulate and trends in water usage
February 17, 2011 - By Susan Obleski
This column is presented weekly by the Public Education sub-committee of the Clinton County Natural Gas Task Force in an effort to provide accurate, up-to-date information on activities surrounding the Marcellus Shale formation and the natural gas exploration industry. For more information on Task Force activities, visit the Task Force page on the Clinton County government website at http://www.clintoncountypa.com/.
This represents the second in a series of articles from the Susquehanna River Basin Commission covering its role as it relates to the natural gas industry.
This article continues the focus on the Susquehanna River Basin Commission's (SRBC) regulation of natural gas well development in the Marcellus Shale, using the question and answer format drawn from SRBC's Frequently Asked Questions handout, which is available through SRBC's website at www.srbc.net/programs/ marcellus-faq.htm.
This week's questions will: (1) Help readers understand what SRBC does not regulate regarding natural gas activities, and (2) give readers a perspective on amounts of water used for drilling and hydrofracturing activities in the Susquehanna basin.
Q: Does SRBC regulate for water quality?
No. SRBC has never regulated water quality for any projects, whether for natural gas development or other purposes. The framers of the Susquehanna River Basin Compact were very deliberate when they directed SRBC to avoid duplicating the efforts of its four members - the commonwealth of Pennsylvania, the states of New York and Maryland and the federal government. Since the states had already assumed responsibility for regulating water quality, SRBC consciously chose not to regulate water quality to avoid what would be an obvious duplication with regulatory agencies such as the Pennsylvania Department of Environmental Protection.
Q: Does SRBC regulate frac fluid treatment, recycling and disposal?
No. SRBC does not regulate the capture, storage, transport, treatment, recycling or disposal of wastewater - known as flowback fluids - from natural gas drilling and hydrofracturing activities. The state agencies have the lead on those regulations. SRBC does, however, require natural gas companies to abide by all other agencies' water quality and waste management requirements; failure to do so can result in the modification, suspension or revocation of SRBC's approval. SRBC also requires natural gas companies to report post-hydrofracturing information to the commission. These reports allow SRBC to track freshwater used, recycled flowback fluids utilized, origin of both freshwater/wastewater and destinations of wastewater and unused freshwater. And if natural gas companies propose to import flowback fluids for their operations in the Susquehanna River Basin, the recycled wastewater will be regulated as would any other water source under SRBC's diversion regulation.
Q: How much water has SRBC approved for natural gas development and how much more does SRBC anticipate approving?
A typical Marcellus Shale hydraulic fracturing operation for a horizontal gas well uses three to five million gallons of water over a two- to five-day period. As the natural gas industry has expanded its activities in the Susquehanna River Basin, it continues to seek new withdrawals so that water sources can be closer to the drilling areas, thereby minimizing hauling distances for water tanker trucks or lengths of water pipelines. SRBC allows gas companies to utilize shared sources (stream withdrawals) previously approved for use by another natural gas company to help reduce the number of intake locations, as long as the access and use agreements are registered with SRBC. As of September 2010, SRBC had approved withdrawals totaling approximately 79 million gallons per day at 133 locations largely in the Pennsylvania portion of the basin but a few in the New York portion as well.
As demand for water increases, the industry continues to focus on improved water management and conservation practices, including the reuse of flowback and production fluids, thereby reducing the quantity of freshwater necessary for hydrofracturing. Recent estimates indicate that the actual water use from the entire Marcellus and Utica Shale natural gas industry at full build-out is expected to be approximately 30 million gallons per day (gpd). To put that into perspective, water use for recreation is about 50 million gpd, water use for power production is about 150 million gpd and water use for public water supplies is about 325 million gpd. Although the move from exploration to production will provide management challenges and may necessitate regulatory changes, SRBC anticipates that gas industry water use can be accommodated along with demands from other uses.
Q: In addition to SRBC-approved withdrawals, what other sources of water can be used by natural gas companies?
SRBC's expedited approval-by-rule (ABR) process allows companies to use sources of water that have already been approved for their use at any of their drilling pads and to utilize shared sources (stream withdrawals) previously approved for use by another natural gas company, as long as access and use agreements are registered with SRBC. Gas companies may also request approval to use other sources of water, such as public water supplies or a source of lesser quality water, such as from wastewater or noncontact cooling.
In Pennsylvania, SRBC and the state Department of Environmental Protection are working with the industry to facilitate the withdrawal and use of impaired waters, including mine drainage (see photo of mine-drainage impacted river) and wastewater. This practice alone may greatly reduce existing stresses on the aquatic habitat in many areas. In addition, many of the gas companies are reusing up to 100 percent of the flowback fluids for other hydrofracturing sites.
Q: Can a private landowner sell water to the natural gas industry if its property has a pond, an old well or a stream?
Yes. The private landowner can sell water but must apply to and receive SRBC approval for the withdrawal as with any other public or business interest.
Q: What does a private landowner have to do to sell water to the gas industry?
In most instances, natural gas companies submit the applications to withdraw water from privately owned lands after reaching agreements with the landowner. However, private landowners may submit applications directly to SRBC requesting approval for a withdrawal and bulk sale of that water to the natural gas industry. The landowner must demonstrate, through written agreements, that one or more natural gas companies have committed to purchase the water. The application process including forms, fees and notices is the same as for other project sponsors. Information about the process and the appropriate forms are available on SRBC's website.
Q: How much water from public water suppliers has been used?
Between June 2008 and October 2010, according to the post-hydrofracture reports for 338 wells in the Pennsylvania portion of the basin, about 314 million gallons which equates to about 38 percent of the water used in hydrofracturing has been provided by public water suppliers. Public water suppliers are second, only behind surface water withdrawals, in preference as water sources for the natural gas industry. Due to the coordinated nature of the review for a bulk water purchase from public water suppliers, it is usually "easier" for a natural gas company to get approved to use these sources than new withdrawal points. This allows for operations to commence faster, allowing time for permitting and constructing surface water withdrawals. The recent trend has been for natural gas companies to rely more heavily on their own surface withdrawals.
Q: When considering a request to transfer fracing fluids into the Susquehanna basin, what issues would be evaluated?
As for any in-basin diversion, SRBC staff would evaluate the water quality of the proposed water source, the proposed use within the basin and the project's location. SRBC staff would assess the potential of the proposed diversion to result in water quality degradation that may be injurious to any existing or potential groundwater or surface water use. If the water were to be used for hydrofracturing, quality impacts from discharge would not be significant but adequate controls during transport and containment and storage on-site would likely be evaluated to insure that the integrity of the basin's waters would not be adversely affected. Staff would also consider public concerns and any mitigating circumstances.
---
This article was submitted by Susan Obleski, director of communications, Susquehanna River Basin Commission. She can be reached by email at sobleski@srbc.net. Information was compiled largely from existing products collaboratively produced by SRBC staff."
Not my work - great article
"Part two - What SRBC does not regulate and trends in water usage
February 17, 2011 - By Susan Obleski
This column is presented weekly by the Public Education sub-committee of the Clinton County Natural Gas Task Force in an effort to provide accurate, up-to-date information on activities surrounding the Marcellus Shale formation and the natural gas exploration industry. For more information on Task Force activities, visit the Task Force page on the Clinton County government website at http://www.clintoncountypa.com/.
This represents the second in a series of articles from the Susquehanna River Basin Commission covering its role as it relates to the natural gas industry.
This article continues the focus on the Susquehanna River Basin Commission's (SRBC) regulation of natural gas well development in the Marcellus Shale, using the question and answer format drawn from SRBC's Frequently Asked Questions handout, which is available through SRBC's website at www.srbc.net/programs/ marcellus-faq.htm.
This week's questions will: (1) Help readers understand what SRBC does not regulate regarding natural gas activities, and (2) give readers a perspective on amounts of water used for drilling and hydrofracturing activities in the Susquehanna basin.
Q: Does SRBC regulate for water quality?
No. SRBC has never regulated water quality for any projects, whether for natural gas development or other purposes. The framers of the Susquehanna River Basin Compact were very deliberate when they directed SRBC to avoid duplicating the efforts of its four members - the commonwealth of Pennsylvania, the states of New York and Maryland and the federal government. Since the states had already assumed responsibility for regulating water quality, SRBC consciously chose not to regulate water quality to avoid what would be an obvious duplication with regulatory agencies such as the Pennsylvania Department of Environmental Protection.
Q: Does SRBC regulate frac fluid treatment, recycling and disposal?
No. SRBC does not regulate the capture, storage, transport, treatment, recycling or disposal of wastewater - known as flowback fluids - from natural gas drilling and hydrofracturing activities. The state agencies have the lead on those regulations. SRBC does, however, require natural gas companies to abide by all other agencies' water quality and waste management requirements; failure to do so can result in the modification, suspension or revocation of SRBC's approval. SRBC also requires natural gas companies to report post-hydrofracturing information to the commission. These reports allow SRBC to track freshwater used, recycled flowback fluids utilized, origin of both freshwater/wastewater and destinations of wastewater and unused freshwater. And if natural gas companies propose to import flowback fluids for their operations in the Susquehanna River Basin, the recycled wastewater will be regulated as would any other water source under SRBC's diversion regulation.
Q: How much water has SRBC approved for natural gas development and how much more does SRBC anticipate approving?
A typical Marcellus Shale hydraulic fracturing operation for a horizontal gas well uses three to five million gallons of water over a two- to five-day period. As the natural gas industry has expanded its activities in the Susquehanna River Basin, it continues to seek new withdrawals so that water sources can be closer to the drilling areas, thereby minimizing hauling distances for water tanker trucks or lengths of water pipelines. SRBC allows gas companies to utilize shared sources (stream withdrawals) previously approved for use by another natural gas company to help reduce the number of intake locations, as long as the access and use agreements are registered with SRBC. As of September 2010, SRBC had approved withdrawals totaling approximately 79 million gallons per day at 133 locations largely in the Pennsylvania portion of the basin but a few in the New York portion as well.
As demand for water increases, the industry continues to focus on improved water management and conservation practices, including the reuse of flowback and production fluids, thereby reducing the quantity of freshwater necessary for hydrofracturing. Recent estimates indicate that the actual water use from the entire Marcellus and Utica Shale natural gas industry at full build-out is expected to be approximately 30 million gallons per day (gpd). To put that into perspective, water use for recreation is about 50 million gpd, water use for power production is about 150 million gpd and water use for public water supplies is about 325 million gpd. Although the move from exploration to production will provide management challenges and may necessitate regulatory changes, SRBC anticipates that gas industry water use can be accommodated along with demands from other uses.
Q: In addition to SRBC-approved withdrawals, what other sources of water can be used by natural gas companies?
SRBC's expedited approval-by-rule (ABR) process allows companies to use sources of water that have already been approved for their use at any of their drilling pads and to utilize shared sources (stream withdrawals) previously approved for use by another natural gas company, as long as access and use agreements are registered with SRBC. Gas companies may also request approval to use other sources of water, such as public water supplies or a source of lesser quality water, such as from wastewater or noncontact cooling.
In Pennsylvania, SRBC and the state Department of Environmental Protection are working with the industry to facilitate the withdrawal and use of impaired waters, including mine drainage (see photo of mine-drainage impacted river) and wastewater. This practice alone may greatly reduce existing stresses on the aquatic habitat in many areas. In addition, many of the gas companies are reusing up to 100 percent of the flowback fluids for other hydrofracturing sites.
Q: Can a private landowner sell water to the natural gas industry if its property has a pond, an old well or a stream?
Yes. The private landowner can sell water but must apply to and receive SRBC approval for the withdrawal as with any other public or business interest.
Q: What does a private landowner have to do to sell water to the gas industry?
In most instances, natural gas companies submit the applications to withdraw water from privately owned lands after reaching agreements with the landowner. However, private landowners may submit applications directly to SRBC requesting approval for a withdrawal and bulk sale of that water to the natural gas industry. The landowner must demonstrate, through written agreements, that one or more natural gas companies have committed to purchase the water. The application process including forms, fees and notices is the same as for other project sponsors. Information about the process and the appropriate forms are available on SRBC's website.
Q: How much water from public water suppliers has been used?
Between June 2008 and October 2010, according to the post-hydrofracture reports for 338 wells in the Pennsylvania portion of the basin, about 314 million gallons which equates to about 38 percent of the water used in hydrofracturing has been provided by public water suppliers. Public water suppliers are second, only behind surface water withdrawals, in preference as water sources for the natural gas industry. Due to the coordinated nature of the review for a bulk water purchase from public water suppliers, it is usually "easier" for a natural gas company to get approved to use these sources than new withdrawal points. This allows for operations to commence faster, allowing time for permitting and constructing surface water withdrawals. The recent trend has been for natural gas companies to rely more heavily on their own surface withdrawals.
Q: When considering a request to transfer fracing fluids into the Susquehanna basin, what issues would be evaluated?
As for any in-basin diversion, SRBC staff would evaluate the water quality of the proposed water source, the proposed use within the basin and the project's location. SRBC staff would assess the potential of the proposed diversion to result in water quality degradation that may be injurious to any existing or potential groundwater or surface water use. If the water were to be used for hydrofracturing, quality impacts from discharge would not be significant but adequate controls during transport and containment and storage on-site would likely be evaluated to insure that the integrity of the basin's waters would not be adversely affected. Staff would also consider public concerns and any mitigating circumstances.
---
This article was submitted by Susan Obleski, director of communications, Susquehanna River Basin Commission. She can be reached by email at sobleski@srbc.net. Information was compiled largely from existing products collaboratively produced by SRBC staff."
Not my work - great article
Monday, September 6, 2010
Hydraulic Fracturing - Induced Fractures and the Freshwater Aquifer
I came across these Industry Articles and a resource guide from the League of Women Voters- they do not appear to be peer reviewed, but I think it is good starting point in the discussion.
http://www.pinntech.com/pubs/NL/Frac_Attack_Eprint.pdf
or
http://www.bfenvironmental.com/pdfs/inducedfracturingoilreporter.pdf
http://www.bfenvironmental.com/pdfs/Hydraulic_Fracturing_Paper_-_World_Watch.pdf
http://www.bfenvironmental.com/pdfs/HydraulicFracturingReport1.2008.pdf
http://www.bfenvironmental.com/pdfs/Sample20Fluid20Composition-BJ20Services.pdf
http://www.bfenvironmental.com/pdfs/Sample20Fluid20Composition-Halliburton.pdf
http://www.bfenvironmental.com/pdfs/Marcellus_Shale_Study_Guide_Parts_1-5.pdf
It is my understanding from a different report that fracing process may initially create fractures that radiate about 1000 to 1500 feet from a well, but the production zone is limited to a distance of about 300 to 500 feet because the fractures beyond this distance do not stay open. (Source World Watch Report)
Instructions for the tipline can be found at: http://www.epa.gov/region03/marcellus_shale/tipline.html
http://www.pinntech.com/pubs/NL/Frac_Attack_Eprint.pdf
or
http://www.bfenvironmental.com/pdfs/inducedfracturingoilreporter.pdf
http://www.bfenvironmental.com/pdfs/Hydraulic_Fracturing_Paper_-_World_Watch.pdf
http://www.bfenvironmental.com/pdfs/HydraulicFracturingReport1.2008.pdf
http://www.bfenvironmental.com/pdfs/Sample20Fluid20Composition-BJ20Services.pdf
http://www.bfenvironmental.com/pdfs/Sample20Fluid20Composition-Halliburton.pdf
http://www.bfenvironmental.com/pdfs/Marcellus_Shale_Study_Guide_Parts_1-5.pdf
It is my understanding from a different report that fracing process may initially create fractures that radiate about 1000 to 1500 feet from a well, but the production zone is limited to a distance of about 300 to 500 feet because the fractures beyond this distance do not stay open. (Source World Watch Report)
Instructions for the tipline can be found at: http://www.epa.gov/region03/marcellus_shale/tipline.html
Thursday, July 15, 2010
Delaware River Basin - Marcellus Shale Status Agency to reconsider natural gas drilling stoppage
Not may work - just posting email received - please go to original article.
"Agency to reconsider natural gas drilling stoppage
By GEOFF MULVIHILL and MARC LEVY (AP) –
http://www.kansascity.com/2010/07/14/2084138/agency-to-reconsider-natural-gas.html
WEST TRENTON, N.J. — The Delaware River Basin Commission agreed Wednesday to hold hearings in northeast Pennsylvania on whether to strengthen or weaken its moratorium on natural gas drilling deep below the river basin.
At issue the quality and quantity of water in the Delaware River watershed, a mile beneath which lies the vast and natural gas-rich Marcellus Shale formation, most of it in New York and Pennsylvania. The gas is extracted by hydraulic fracturing or "fracking," a horizontal drilling process using millions of gallons of water mixed with chemicals and sand — with the potential, critics say, to pollute and deplete the region's water resources.
Nearly 600 residents attended Wednesday's daylong DRBC meeting to plead their clashing cases: that drilling is needed not only to produce relatively clean energy but to save economically desperate communities — or that the process threatens groundwater and surface water pollution and could deplete streams and aquifers.
Landowners like Judy Ahrens of Hanesdale, Pa., argued that they should be able to lease the mineral rights to their land.
"It enables those of us who have farms to keep our farms so they can be passed on to our families so they don't have to be split up and developed," she said. Ahrens has sold the mineral rights on her 120-acre hay farm to a gas company.
Opponents say they are concerned about the chemicals used in fracking, some of them toxic and suspected human carcinogens.
"If we can't protect our drinking water, at what point are we letting corporate America just take over?" asked Carmen Barnes, of New York City, before the meeting.
In a related development Wednesday, one of the leading natural gas drillers in Pennsylvania disclosed the chemicals it uses in fracking, saying it wants to defuse the growing controversy about the industry's secrecy over the chemicals.
"We believe strongly that there's nothing to hide and the way to demonstrate it is to show it," said Matt Pitzarella, a spokesman for Range Resources Corp.
The Fort Worth, Texas-based company, which has permits to drill hundreds of wells in Pennsylvania's Marcellus Shale, does not use carcinogenic materials in its process, Pitzarella said.
The Marcellus Shale has drawn a stampede of natural gas drilling companies to Pennsylvania in the last two years, lured by higher prices for natural gas and the ability to use the fracking process to extract huge amounts of the fuel. Last year, the DRBC declared a moratorium on drilling in the Delaware River basin while it works on regulations; without a permit to withdraw water, drilling companies can't operate.
That moratorium was extended in May to exploratory drilling as well. But Wednesday, it voted to allow two new exploratory wells in a part of Wayne County, Pa.
The commission said it expects to have a draft of its proposed regulations later this summer and a final vote by the end of the year.
Some gas interests are calling for the commission to overturn the moratorium entirely.
The DRBC, a compact representing the federal government and the states of Delaware, New York, New Jersey and Pennsylvania, has legal authority for water quality and quantity issues in the Delaware River basin.
While Pennsylvania does allow natural gas drilling by hydraulic fracturing, New York has declared a moratorium while it adopts its own state regulations.
Critics of the fracking process point to a major blowout on June 3 in Clearfield County, Pa., where gas and wastewater spewed out of control for 16 hours before the well was capped. On Tuesday, Pennsylvania's Department of Environmental Protection slapped a $400,000 penalty on the driller, EOG Resources Inc., and its contractor on the job, for failing to use a proper backup system when it hooked the well to a pipeline.
The Range Resources announcement was well-received by the nonprofit environmental group Clean Water Action.
"This has been the most responsive thing we've seen industry do," said Myron Arnowitt, the group's Pennsylvania state director. "It sounds like they are starting to get what would be helpful for people."
Pitzarella, the Range Resources spokesman, said the company provided to The Associated Press the complete list of hazardous chemicals it uses in its Pennsylvania drilling operations. The hazardous chemicals are heavily diluted with water and sand, he said, and make up no more than 0.04 percent of everything pumped into the ground.
"At that dilution, they pose little and probably zero health impacts," Pitzarella said. Still, Arnowitt said he worries that the chemicals are not diluted enough to be safe for human exposure.
State environmental regulators, as well as industry officials, say they know of no examples of fracking chemicals poisoning underground drinking water sources in Pennsylvania or elsewhere. However, environmental advocates contend that not enough research has been done to come to that conclusion.
Arnowitt said he needed time to study the list and concentrations.
"The concentrations are certainly high enough that ... I don't think anyone looking at this could say, 'Oh yeah, this looks fine,'" Arnowitt said.
The chemicals include hydrochloric acid, glutaraldehyde, ethylene glycol, methanol, ethanol, propargyl alcohol, sodium hydroxide and n-alkyl dimethyl benzyl ammonium chloride.
The Sierra Club congratulated Range Resources on the "first step" and then called on other gas drilling companies to disclose their chemicals used in each state.
Levy reported from Harrisburg."
Comments
1. Threat to water resources - non-point source pollution and uncontrolled urban runoff and lack of recharge is our biggest threat to our water resources. This means - agricultural runoff, urban runoff, etc. In addition, the endocrin disruptors and cancer treatment drugs and medications are entering our streams and watersheds through improper disposal, wastewater discharges, poor non-point source pollution control, and uncontrolled discharges from CSOs (combined sewer overflows). Professionally speaking - I believe that CSOs, poorly treated wastewater and uncontrolled urban/ agriculutural runoff are significant threats to our watersheds.
2.I believe in full disclosure on chemicals that are used and volumes used and I would hope that the industry would attempt to use chemicals that are efficient and environmentally benign as possible - this should be regulated by the State and not a federal agency. I do not have a problem with the frac process being part of a regulatory review and permitting - but since this is not deep well injection - this permit should be handled by the PADEP.
3. I do not believe the River Basin should delay permits in this manner over this activity - Deep well injection is covered by the EPA and fracking is not deep well injection- I do not believe they have the authority to regulate and there is no need to get an NPDES permit for the frac process.
4. I believe state regulations need to be changed, we need more disclosure.
Just my thoughts
Saturday, May 15, 2010
Baseline Independent Water Testing Water Quality Testing - Marcellus Shale Development What Parameters Should be Tested?
For the past 20 years, I have stressed the importance of private well construction standards and getting your water tested for your private well or water source. Because of the specifics concerns with respect to the Marcellus Shale, the citizens are recognizing the importance of documenting the baseline quality of their drinking water and recreational water sources. The primary concern is that many professionals are recommending baseline analysis that either provide a very broad range of parameters that are not specific enough to target the Marcellus Shale or a baseline analysis that targets only the potential impacts related to the develop of natural gas and in some cases there are companies with very little experience in environmental consulting.
From the citizens perspective - It is my professional opinion, the baseline analysis needs to take into consideration the following:
a. The existing geological conditions that may affect water quality for the region or area.
b. The existing land-use or activities occurring within the recharge zone for the well or spring or watershed area for the surfacewater resource.
c. Potential sources of contaminants from proposed developments that target the various phases of the development, i.e., drilling / drilling muds, intermixing of freshwater with saline and brine water, interception of shallow gas deposits, and management of the drilling pad.
d. The existing quality of your water and type of water source.
Of these 4 items, I believe that if the professional you are considering hiring does not ask you questions about your well and your current water quality you will not be establishing an affective baseline. In addition, the professional providing this information should not be just reading off a list of recommendations by some third party, but have solid understanding of earth sciences, hydrology, well drilling, and groundwater. Remember - you are establishing a "legal" baseline that may need to address a multitude of issues not just Marcellus Shale Drilling or Hydrofracing.
Establishing a baseline - the following questions should be asked and used in the decision making process.
1. Where are you located and What is the type of water source?
2. If it is a well, what is the depth of the well, static water level, and depth of casing?
3. Does the water system have an existing treatment system? If yes, why?
4. Does the water quality change when there is a heavy rain or snow melt?
5. Has it been tested in the past?
6. Are there any problems or issues? Such as: discolored water, metallic taste, turbidity, staining, blue-green staining, etc
7. This water source supports what type of use? Single-family home, house and small farm, etc.
8. What is the size of your parcel?
9. What is the existing and past use of your parcel?
10. What is the land-use surrounding and upgradient of this source?
If the person conducting your baseline analysis - is not asking you these questions - he/she may not be providing you the help you need.
The following is a listing of parameters that PADEP identified as "potential parameters of concern" as it relates to Marcellus Shale Wastewater (2009):
pH, acidity, alkalinity, aluminum, ammonia nitrogen, arsenic, barium, benzene, biochemical oxygen demand, boron, bromide, cadmium, chemical oxygen demand, chlorides, total chromium, cobalt, copper, ethylene glycol, gross alpha, gross beta, total hardness, iron, lead, lithium, magnesium, manganese, MBAS (surfactants), mercury, molybdenum, nickel, nitrate, nitrite, oil & grease, osomtic pressure, total phenolics, selenium, silver, sodium, specific conductance, strontium, sulfates, toluene, total dissolved solids, total kjeldahl nitrogen, total suspended solids, zinc, total nitrogen, and total phosphorous.
Again - these are parameters of concern or interest from a wastewater perspective, but it is possible to use this list to create a suitable baseline for testing private wells. For the parameters listed above - I would recommend the following:
Minimum Baseline Monitoring for Northeast Pennsylvania
pH, acidity, alkalinity, ammonia nitrogen, arsenic, barium, bromide, chemical oxygen demand, chlorides, total hardness, iron, manganese, MBAS (surfactants), nitrate+ nitrite, oil & grease, sodium, specific conductance, potassium, selenium, strontium, sulfates, total dissolved solids, total suspended solids, methane/ethane, and VOCs with MTBE.
Why pH - it is cheap and in our area we tend to have low pH water and the water is corrosive.
Why Acidity - our water may have a low pH, but it does not have a very high acidity - frac water, mine drainage, and other water associated with pyrite oxidation can.
Why Alkalinity - this relates to corrosion and possible chemistry of shale deposits with inter-bedded limestones
Ammonia Nitrogen - based on review of frac water chemistry
Arsenic - baseline levels are just below or above drinking water standard NOW
Barium - not typical in freshwater, but typical of drilling mud, flowback water.
Bromide-This is commonly used as a biocide.
Chemical oxygen demand - normally this should be low, but a low cost means of evaluating water chemical changes.
Chlorides - brine water has a high chloride content - also relates to road salt, urban runoff, sewage, etc.
Total Hardness - normally are water is typically soft, i.e., low hardness- frac and flowback water has significantly higher hardness. Locally - we may have elevated levels of iron and manganese.
MBAS - surfactants - freshwater pretty much absent - may be present in sewage and in frac water and flow back water.
Nitrate+Nitrite - freshwater flow - can be caused by fertilizers, sewage, urban runoff, frac water
Oil and Grease - we are talking about drilling, lubricants - also gas stations, service stations, and improper disposal locally, urban runoff, and spill
Sodium - freshwater low - sources may be road salt, urban runoff, brine water, flowback water, water softeners
Specific Conductance - cheap - indicator test.
Potassium - freshwater low - source salting, sewage, urban runoff, brine water, flow backwater, water softeners
Selenium - connate water has elevated levels of selenium and reportedly flow back water has concentrations ranging from - 2 to 100 pbb
Strontium- reportedly flow back water strontium concentrations ranged from 400 ppb to over 4600 mg/L
Sulfates- we have a drinking water limit - 250 mg/L - elevated levels can be a diuretic.
Total Dissolved Solids - this is a gross measure of the sum of the inorganic material (iron, chloride, sulfate, etc) dissolved in the water - there is a standard - 500 mg/L
Total Suspended Solids- This is suspended materials - groundwater typically has a very low suspended solids, but this can increase because of the presence of metal oxides, corrosion of casing, poor well construction, damage to a well and more.
Methane / Ethane- Time to be honest - we have areas where the freshwater aquifer contains methane and we have areas that prior to drilling - we could light the gas at the "tap" and we have had problems.
VOCs with MTBE- We use other petrochemicals that may be already present at trace levels and we have a lot of existing gasoline stations, underground unregistered private fuel tanks, oil tanks and more. Guess wait - 1 gallon of gasoline can contaminate 1,000,000 gallons of water.
More to Come
1. Working on a list of organic chemicals|- this is not the final word.
2. Looking into lead (this may already be a problem for some wells with corrosive water).
3. Looking into lithium
Understanding your drinking water new - Free Publication
http://www.wilkes.edu/water
I hope you find this useful
Mr Brian Oram, PG
This is a living document and subject to change with more information. Independent water testing, certified testing laboratories.
From the citizens perspective - It is my professional opinion, the baseline analysis needs to take into consideration the following:
a. The existing geological conditions that may affect water quality for the region or area.
b. The existing land-use or activities occurring within the recharge zone for the well or spring or watershed area for the surfacewater resource.
c. Potential sources of contaminants from proposed developments that target the various phases of the development, i.e., drilling / drilling muds, intermixing of freshwater with saline and brine water, interception of shallow gas deposits, and management of the drilling pad.
d. The existing quality of your water and type of water source.
Of these 4 items, I believe that if the professional you are considering hiring does not ask you questions about your well and your current water quality you will not be establishing an affective baseline. In addition, the professional providing this information should not be just reading off a list of recommendations by some third party, but have solid understanding of earth sciences, hydrology, well drilling, and groundwater. Remember - you are establishing a "legal" baseline that may need to address a multitude of issues not just Marcellus Shale Drilling or Hydrofracing.
Establishing a baseline - the following questions should be asked and used in the decision making process.
1. Where are you located and What is the type of water source?
2. If it is a well, what is the depth of the well, static water level, and depth of casing?
3. Does the water system have an existing treatment system? If yes, why?
4. Does the water quality change when there is a heavy rain or snow melt?
5. Has it been tested in the past?
6. Are there any problems or issues? Such as: discolored water, metallic taste, turbidity, staining, blue-green staining, etc
7. This water source supports what type of use? Single-family home, house and small farm, etc.
8. What is the size of your parcel?
9. What is the existing and past use of your parcel?
10. What is the land-use surrounding and upgradient of this source?
If the person conducting your baseline analysis - is not asking you these questions - he/she may not be providing you the help you need.
The following is a listing of parameters that PADEP identified as "potential parameters of concern" as it relates to Marcellus Shale Wastewater (2009):
pH, acidity, alkalinity, aluminum, ammonia nitrogen, arsenic, barium, benzene, biochemical oxygen demand, boron, bromide, cadmium, chemical oxygen demand, chlorides, total chromium, cobalt, copper, ethylene glycol, gross alpha, gross beta, total hardness, iron, lead, lithium, magnesium, manganese, MBAS (surfactants), mercury, molybdenum, nickel, nitrate, nitrite, oil & grease, osomtic pressure, total phenolics, selenium, silver, sodium, specific conductance, strontium, sulfates, toluene, total dissolved solids, total kjeldahl nitrogen, total suspended solids, zinc, total nitrogen, and total phosphorous.
Again - these are parameters of concern or interest from a wastewater perspective, but it is possible to use this list to create a suitable baseline for testing private wells. For the parameters listed above - I would recommend the following:
Minimum Baseline Monitoring for Northeast Pennsylvania
pH, acidity, alkalinity, ammonia nitrogen, arsenic, barium, bromide, chemical oxygen demand, chlorides, total hardness, iron, manganese, MBAS (surfactants), nitrate+ nitrite, oil & grease, sodium, specific conductance, potassium, selenium, strontium, sulfates, total dissolved solids, total suspended solids, methane/ethane, and VOCs with MTBE.
Why pH - it is cheap and in our area we tend to have low pH water and the water is corrosive.
Why Acidity - our water may have a low pH, but it does not have a very high acidity - frac water, mine drainage, and other water associated with pyrite oxidation can.
Why Alkalinity - this relates to corrosion and possible chemistry of shale deposits with inter-bedded limestones
Ammonia Nitrogen - based on review of frac water chemistry
Arsenic - baseline levels are just below or above drinking water standard NOW
Barium - not typical in freshwater, but typical of drilling mud, flowback water.
Bromide-This is commonly used as a biocide.
Chemical oxygen demand - normally this should be low, but a low cost means of evaluating water chemical changes.
Chlorides - brine water has a high chloride content - also relates to road salt, urban runoff, sewage, etc.
Total Hardness - normally are water is typically soft, i.e., low hardness- frac and flowback water has significantly higher hardness. Locally - we may have elevated levels of iron and manganese.
MBAS - surfactants - freshwater pretty much absent - may be present in sewage and in frac water and flow back water.
Nitrate+Nitrite - freshwater flow - can be caused by fertilizers, sewage, urban runoff, frac water
Oil and Grease - we are talking about drilling, lubricants - also gas stations, service stations, and improper disposal locally, urban runoff, and spill
Sodium - freshwater low - sources may be road salt, urban runoff, brine water, flowback water, water softeners
Specific Conductance - cheap - indicator test.
Potassium - freshwater low - source salting, sewage, urban runoff, brine water, flow backwater, water softeners
Selenium - connate water has elevated levels of selenium and reportedly flow back water has concentrations ranging from - 2 to 100 pbb
Strontium- reportedly flow back water strontium concentrations ranged from 400 ppb to over 4600 mg/L
Sulfates- we have a drinking water limit - 250 mg/L - elevated levels can be a diuretic.
Total Dissolved Solids - this is a gross measure of the sum of the inorganic material (iron, chloride, sulfate, etc) dissolved in the water - there is a standard - 500 mg/L
Total Suspended Solids- This is suspended materials - groundwater typically has a very low suspended solids, but this can increase because of the presence of metal oxides, corrosion of casing, poor well construction, damage to a well and more.
Methane / Ethane- Time to be honest - we have areas where the freshwater aquifer contains methane and we have areas that prior to drilling - we could light the gas at the "tap" and we have had problems.
VOCs with MTBE- We use other petrochemicals that may be already present at trace levels and we have a lot of existing gasoline stations, underground unregistered private fuel tanks, oil tanks and more. Guess wait - 1 gallon of gasoline can contaminate 1,000,000 gallons of water.
More to Come
1. Working on a list of organic chemicals|- this is not the final word.
2. Looking into lead (this may already be a problem for some wells with corrosive water).
3. Looking into lithium
Understanding your drinking water new - Free Publication
http://www.wilkes.edu/water
I hope you find this useful
Mr Brian Oram, PG
This is a living document and subject to change with more information. Independent water testing, certified testing laboratories.
Saturday, April 3, 2010
DEP to require companies to list chemicals used at each gas well
DEP to require companies to list chemicals used at each gas well
Direct Url - http://thetimes-tribune.com/news/dep-to-require-companies-to-list-chemicals-used-at-each-gas-well-1.711837
(Note this is not my work)
by laura legere (staff writer)
Published: April 2, 2010
CLARKS SUMMIT - Gas drilling companies operating in Pennsylvania will have to provide the names of chemicals used at each well site under regulations proposed by the state's environmental oversight agency.
The requirement, which was added last week to the most recent draft of proposed well construction regulations, was discussed by the head of the Department of Environmental Protection's Bureau of Oil and Gas Management at a meeting of the Abington Council of Governments Thursday night.
The new proposal would require each company to include a list of the names and the total volume of chemicals used to hydraulically fracture each well as part of a report the drillers submit once each well is completed.
The regulations, if approved, will give a well-by-well picture of the chemicals that are mixed with water and sand and injected underground to break apart gas-bearing rock formations including the Marcellus Shale.
Scott Perry, who was appointed director of the bureau in mid-January, said the requirement was just added now to the suite of regulations first proposed in September "because we heard what the concerns of the public were."
Although drillers provide the department with Material Safety Data Sheets that outline what chemicals the companies plan to use at a well site, Mr. Perry said that prior to the new completion report requirements "we didn't ask for what chemicals were used to frack a well.""It's important for transparency, for people to be able to see what's going on," he said. The list will not include the volumes of individual chemicals used at a well site, he said.
He also insisted that even though the department is proposing to strengthen its disclosure requirements, hydraulic fracturing is not a threat to water supplies.
"There has never been any evidence of fracking ever causing direct contamination of fresh groundwater in Pennsylvania or anywhere else," he said.
"If I honestly thought that fracking was causing a direct communication with groundwater resources, I wouldn't be talking about how we have a chemical list. That is the ultimate half-measure. I would be saying, 'This cannot occur.' "
The proposed regulations will be presented at a meeting of the Environmental Quality Board on May 19, Mr. Perry said.
Contact the writer: llegere@timesshamrock.com
*******
This was part of my comments to the proposed legistation - I still believe it does not require the release of proprietory data - but it is important to note the MSDS sheets and information have always been included as part of the permitting process. Also - this report will be generated after completion to document what was actually used.
Looking for environmental or water quality monitoring equipment for field work.
Direct Url - http://thetimes-tribune.com/news/dep-to-require-companies-to-list-chemicals-used-at-each-gas-well-1.711837
(Note this is not my work)
by laura legere (staff writer)
Published: April 2, 2010
CLARKS SUMMIT - Gas drilling companies operating in Pennsylvania will have to provide the names of chemicals used at each well site under regulations proposed by the state's environmental oversight agency.
The requirement, which was added last week to the most recent draft of proposed well construction regulations, was discussed by the head of the Department of Environmental Protection's Bureau of Oil and Gas Management at a meeting of the Abington Council of Governments Thursday night.
The new proposal would require each company to include a list of the names and the total volume of chemicals used to hydraulically fracture each well as part of a report the drillers submit once each well is completed.
The regulations, if approved, will give a well-by-well picture of the chemicals that are mixed with water and sand and injected underground to break apart gas-bearing rock formations including the Marcellus Shale.
Scott Perry, who was appointed director of the bureau in mid-January, said the requirement was just added now to the suite of regulations first proposed in September "because we heard what the concerns of the public were."
Although drillers provide the department with Material Safety Data Sheets that outline what chemicals the companies plan to use at a well site, Mr. Perry said that prior to the new completion report requirements "we didn't ask for what chemicals were used to frack a well.""It's important for transparency, for people to be able to see what's going on," he said. The list will not include the volumes of individual chemicals used at a well site, he said.
He also insisted that even though the department is proposing to strengthen its disclosure requirements, hydraulic fracturing is not a threat to water supplies.
"There has never been any evidence of fracking ever causing direct contamination of fresh groundwater in Pennsylvania or anywhere else," he said.
"If I honestly thought that fracking was causing a direct communication with groundwater resources, I wouldn't be talking about how we have a chemical list. That is the ultimate half-measure. I would be saying, 'This cannot occur.' "
The proposed regulations will be presented at a meeting of the Environmental Quality Board on May 19, Mr. Perry said.
Contact the writer: llegere@timesshamrock.com
*******
This was part of my comments to the proposed legistation - I still believe it does not require the release of proprietory data - but it is important to note the MSDS sheets and information have always been included as part of the permitting process. Also - this report will be generated after completion to document what was actually used.
Looking for environmental or water quality monitoring equipment for field work.
Saturday, March 27, 2010
House Bill 2235 - Moratorium for Leasing State Forest Land
Personally - I consider the mineral and gas rights owned by the State via State Forest and other land the same as a Royality Owner. A royality owner has the right to lease or not to lease property. I am a little concern about the 5 year time line and it was not clear in the regulations what is going to be done to fund this evaluation. To be honest, the State Forest and other leasing programs are significantly better than the Oil and Gas Law and permitting process used by the State. These programs have better provisions for control, siting, and bonding.
The primary weakness in the HB 2235 is that is does not appear to provide funding for the assessment and the assesment does not look at critical management options. These options, provisions, or considerations would include evaluating the leasing process to develop a lease that protects the environment and the states assests, feasibility analysis to determine if it may be better to allow the State to directly hirer a contractor to develop the Gas Resource rather than leasing out the resource ((This way that State in the gas business - why should we give away 80 % of this value), PA should maintain ownership and control of the pore space and does not address issues related to how monies for leasing could be allocated and utilized to benefit the community.
Funds from leasing should be used in ways that helps us to get off fossil fuels - even the best estimates are there are only 100 years of gas available. The money should not go to pay current salaries, but used to fund environmental education, alternative energy projects (such as grants to citizens to improve efficiency, install solar, wind, or ground source systems - i.e., decrease energy demand and consumption and install systems at the point of us), sustainable infrastructure, improve water and wastewater treatment plants, purchase forested land for other drilling (carbon capture) and other programs that create economic value and reduce energy and water consumption.
This bill only seems to cover conducting some type of environmental inventory, but provides nothing related to the interpretation of the data to make recommendations on areas that could be accessed via the vertical leg of the well. Yes our forested lands are critical habitate, but we need to manage the resource. Also - this assessment should include an easement of the geology for the area. If the report only identifies the surface features, the recommendations may not make sense from a geological or energy stand point.
This bill only covers a portion of the work that is needed to evaluate the option to lease State Owned Land or not. The HB should include an evaluation of Best Practices that should be utilizied in these areas. A partial listing of best practices may include the following:
a. Using partially degraded water or treated wastewater or stormwater for frac fluid and using recirculation systems;
b. Selecting Frac Chemicals that are as environmentally benign as possible and commercially available;
c. Prohibit the on-site disposal of cuttings and the use of lined ponds for storing water that had been used for fracking;
d. Require the implementation of a monitoring program that includes on-site monitoring wells and pre and post monitoring for streams, wetlands, and surfacewater;
e. Require a multiple casement approach that properly seals the unconsolidated and shallow consolidated aquifer and protects water with a TDS of < 10,000 mg/L;
f. The leasing process should not include provisions for deep well injection or carbon sequestration - these rights should be retained by PA (pore space should be owned by the state) and;
f. Require third party inspectors hirer by the State or the State should hire a gas company as a consultant and pay their fees, but PA maintain the full royality rights.
Just my thoughts
Brian
The primary weakness in the HB 2235 is that is does not appear to provide funding for the assessment and the assesment does not look at critical management options. These options, provisions, or considerations would include evaluating the leasing process to develop a lease that protects the environment and the states assests, feasibility analysis to determine if it may be better to allow the State to directly hirer a contractor to develop the Gas Resource rather than leasing out the resource ((This way that State in the gas business - why should we give away 80 % of this value), PA should maintain ownership and control of the pore space and does not address issues related to how monies for leasing could be allocated and utilized to benefit the community.
Funds from leasing should be used in ways that helps us to get off fossil fuels - even the best estimates are there are only 100 years of gas available. The money should not go to pay current salaries, but used to fund environmental education, alternative energy projects (such as grants to citizens to improve efficiency, install solar, wind, or ground source systems - i.e., decrease energy demand and consumption and install systems at the point of us), sustainable infrastructure, improve water and wastewater treatment plants, purchase forested land for other drilling (carbon capture) and other programs that create economic value and reduce energy and water consumption.
This bill only seems to cover conducting some type of environmental inventory, but provides nothing related to the interpretation of the data to make recommendations on areas that could be accessed via the vertical leg of the well. Yes our forested lands are critical habitate, but we need to manage the resource. Also - this assessment should include an easement of the geology for the area. If the report only identifies the surface features, the recommendations may not make sense from a geological or energy stand point.
This bill only covers a portion of the work that is needed to evaluate the option to lease State Owned Land or not. The HB should include an evaluation of Best Practices that should be utilizied in these areas. A partial listing of best practices may include the following:
a. Using partially degraded water or treated wastewater or stormwater for frac fluid and using recirculation systems;
b. Selecting Frac Chemicals that are as environmentally benign as possible and commercially available;
c. Prohibit the on-site disposal of cuttings and the use of lined ponds for storing water that had been used for fracking;
d. Require the implementation of a monitoring program that includes on-site monitoring wells and pre and post monitoring for streams, wetlands, and surfacewater;
e. Require a multiple casement approach that properly seals the unconsolidated and shallow consolidated aquifer and protects water with a TDS of < 10,000 mg/L;
f. The leasing process should not include provisions for deep well injection or carbon sequestration - these rights should be retained by PA (pore space should be owned by the state) and;
f. Require third party inspectors hirer by the State or the State should hire a gas company as a consultant and pay their fees, but PA maintain the full royality rights.
Just my thoughts
Brian
Monday, August 17, 2009
Solutions for Natural Gas Development for Northeastern Pennsylvania
The following are just my ideas related to natural gas development in Pennsylvania. To minimize problems with natural gas development, the citizens, communities, educators, and companies should consider working together and it may be advisable to implement the following:
1. Establish private well construction standards that include grouting annular spaces and initial water quality testing. This monitoring should include documenting static water level and direction of groundwater flow.
2. Requiring predrilling and post-drilling water testing of groundwater wells, springs, and surfacewater sources.
3. Royality owners with wells should consider replacing substandard wells with sanitary wells. If royality owners have old hand-dug wells, these wells should be abandon.
4. Royality owners should reach out to none royality owners and encourage them to get their wells tested.
5. Drilling and Exploration companies
a. Install at least one nested groundwater well within the general vicinity of the construction pad or establish additional regional monitoring sites to better understand the vertical extent of the freshwater aquifer. These wells should be fitted with a pressure transducer and the water pressure should be monitored during the drilling and fracing process.
The nested wells should be divided into zone - shallow groundwater consolidate formation (< 150 feet), moderately deep consolidated (150 - 400 feet), deep consolidated (400 to 600 feet), deep possible brine water (600 to 1500 feet), and if shallow gas is present from 1500 to 2500 feet.
b. In the production well - the drillers should install additional fresh water casing. The first freshwater casing should not extend more than 300 feet below ground - Typical depth of most private wells) and should not penetrate a shallow gas producing formation. The second freshwater (shallow gas) casing should extend from 300 feet to 800 feet or the maximum depth of private wells and community water supplies within 1 mile from the production well and this casing should not penetrate a shallow gas zone. If a shallow gas bearing zone is encountered, a separate casing would have to be installed. There are databases available to assist with this evaluation or it may be necessary to survey local well drillers and private well owners.
Note: It may be advisable to have a PA licensed geologist be part of the decision making regarding the extent and depth of the freshwater casing.
Note: Casings should be cemented to the surface. The revisions in the casing should include the installation of the 13 3/8 casing that is used for coal seams - even when coal is not present and this casing should be grouted to the surface.
Possible Casing Breakdown
1. 24 inch conductor casing - up to 60 feet.
2. 20 inch casing - up to 600 feet to 800 feet (i.e., freshwater interface) cemented to the surface * - If many of the surrounding private wells are shallow the well design may want to attempt to add a casing segment that has a maximum depth of 300 feet and then 600 feet.
3. 13 3/8 inch casing - up to 1000 feet cemented to the surface
4. 9 5/8 casing - seal off shallow gas - cemented to the surface
5. 5 1/2 casing - this should be cemented to within the 9 5/8 casing.
c. These decisions would be based on a combination of database searches, information from local drillers, information from surrounding private wells, and on-site water quality monitoring during drilling to document the variation in the freshwater chemistry and presence of shallow gas deposits.
d. At the production well - it appears that it may be necessary to improve the cementing process to make sure that the freshwater sections are properly cementing. I believe that limiting the vertical leg of each casing section and grouting segment will help and create multiple barriers in the system and conducting third party assessments of the cement seal are necessary.
In addition, the cement should be field tested. From experience with drilling in the consolidated formation in PA, it is possible that the minimum amount of cement required to fill the annulus may be 3 to 5 times the actual void volume. This would take into consideration loss of cement to the formation or fractured zones.
Limiting the vertical sections also limits the chance that shallow gas may be pushed by grouting into a shallow freshwater zone.
6. If PA levees a tax on natural gas - a portion of the funding should go to a program to replace substandard private wells, install water treatment for sites that have been impacted, and water systems for areas that have been impacted by natural gas drilling. The program could then take the legal action to recover from the companies- so each homeowner does not have to carry the financial burden.
7. Municipalites - should develop a private well construction and permitting ordinance and facilitate education and outreach in the community.
Just a few thoughts.
Brian Oram, Professional Geologist
B. F. Environmental Consultants
http://www.bfenvironmental.com
1. Establish private well construction standards that include grouting annular spaces and initial water quality testing. This monitoring should include documenting static water level and direction of groundwater flow.
2. Requiring predrilling and post-drilling water testing of groundwater wells, springs, and surfacewater sources.
3. Royality owners with wells should consider replacing substandard wells with sanitary wells. If royality owners have old hand-dug wells, these wells should be abandon.
4. Royality owners should reach out to none royality owners and encourage them to get their wells tested.
5. Drilling and Exploration companies
a. Install at least one nested groundwater well within the general vicinity of the construction pad or establish additional regional monitoring sites to better understand the vertical extent of the freshwater aquifer. These wells should be fitted with a pressure transducer and the water pressure should be monitored during the drilling and fracing process.
The nested wells should be divided into zone - shallow groundwater consolidate formation (< 150 feet), moderately deep consolidated (150 - 400 feet), deep consolidated (400 to 600 feet), deep possible brine water (600 to 1500 feet), and if shallow gas is present from 1500 to 2500 feet.
b. In the production well - the drillers should install additional fresh water casing. The first freshwater casing should not extend more than 300 feet below ground - Typical depth of most private wells) and should not penetrate a shallow gas producing formation. The second freshwater (shallow gas) casing should extend from 300 feet to 800 feet or the maximum depth of private wells and community water supplies within 1 mile from the production well and this casing should not penetrate a shallow gas zone. If a shallow gas bearing zone is encountered, a separate casing would have to be installed. There are databases available to assist with this evaluation or it may be necessary to survey local well drillers and private well owners.
Note: It may be advisable to have a PA licensed geologist be part of the decision making regarding the extent and depth of the freshwater casing.
Note: Casings should be cemented to the surface. The revisions in the casing should include the installation of the 13 3/8 casing that is used for coal seams - even when coal is not present and this casing should be grouted to the surface.
Possible Casing Breakdown
1. 24 inch conductor casing - up to 60 feet.
2. 20 inch casing - up to 600 feet to 800 feet (i.e., freshwater interface) cemented to the surface * - If many of the surrounding private wells are shallow the well design may want to attempt to add a casing segment that has a maximum depth of 300 feet and then 600 feet.
3. 13 3/8 inch casing - up to 1000 feet cemented to the surface
4. 9 5/8 casing - seal off shallow gas - cemented to the surface
5. 5 1/2 casing - this should be cemented to within the 9 5/8 casing.
c. These decisions would be based on a combination of database searches, information from local drillers, information from surrounding private wells, and on-site water quality monitoring during drilling to document the variation in the freshwater chemistry and presence of shallow gas deposits.
d. At the production well - it appears that it may be necessary to improve the cementing process to make sure that the freshwater sections are properly cementing. I believe that limiting the vertical leg of each casing section and grouting segment will help and create multiple barriers in the system and conducting third party assessments of the cement seal are necessary.
In addition, the cement should be field tested. From experience with drilling in the consolidated formation in PA, it is possible that the minimum amount of cement required to fill the annulus may be 3 to 5 times the actual void volume. This would take into consideration loss of cement to the formation or fractured zones.
Limiting the vertical sections also limits the chance that shallow gas may be pushed by grouting into a shallow freshwater zone.
6. If PA levees a tax on natural gas - a portion of the funding should go to a program to replace substandard private wells, install water treatment for sites that have been impacted, and water systems for areas that have been impacted by natural gas drilling. The program could then take the legal action to recover from the companies- so each homeowner does not have to carry the financial burden.
7. Municipalites - should develop a private well construction and permitting ordinance and facilitate education and outreach in the community.
Just a few thoughts.
Brian Oram, Professional Geologist
B. F. Environmental Consultants
http://www.bfenvironmental.com
Friday, July 3, 2009
Of Hydraulic Fracturing and Drinking Water
This is a reprint of an email notice I received from the Carbon County Groundwater Guardians - check out their website - http://www.carbonwaters.org
This was written by JEREMY MILLER
Original post may be
http://greeninc.blogs.nytimes.com/2009/06/30/of-hydraulic-fracturing-and-drinking-water/
A bill introduced earlier this month would bring federal oversight of hydraulic fracturing fluids – chemical mixtures pumped at high pressure into oil and gas wells in order to unlock deposits trapped deep underground.
Environmentalists welcomed the bill, but representatives of the natural gas industry say the legislation could lead to increased costs, job losses and increased competition for water — particularly in the West.
The bill, known as the Fracturing Responsibility and Awareness of Chemicals Act, (FRAC) was introduced in both the House and Senate by representatives from Colorado, Pennsylvania and New York. It essentially seeks to overturn a 2005 legislative tweak that placed fracturing fluids outside the regulatory purview of the Safe Drinking Water Act.
“Our legislation says everyone deserves to have safe drinking water by ensuring that hydraulic fracturing is subject to the protections afforded by the Safe Drinking Water Act,” said Representative Maurice Hinchey, a New York Democrat and one of the bill’s authors, in a prepared statement. “The bill also lifts the veil of secrecy currently shrouding this industry practice.”
Several kinds of fracturing fluids are used by the gas industry. Some are merely water or compressed gases injected underground at high pressure. Others are slurries that contain a host of chemicals and “proppants” — granular substances composed of resin-coated sand grains or similar synthesized materials — that expand in the ground and hold open fissures for gas and oil to pass through.
Hydraulic fracturing fluids were developed by Halliburton in the 1940s, but their use has increased recently as exploration of deep gas fields in places like the Marcellus Shale and Colorado’s Roan Plateau has stepped up.
Today, nine out of 10 gas wells in the United States currently use fracturing fluids, according to the Interstate Oil and Gas Compact Commission, a multistate government group.
Whether or not those fluids are polluting water supplies is a matter of debate, though a lengthy report by the investigative site ProPublica last year noted that this is often difficult to determine — not least because the precise makeup of fracturing fluids are considered trade secrets in the industry.
The pending legislation would require disclosure of ingredients.
Amy Mall, a senior policy analyst with the Natural Resources Defense Council, said that the push for regulation under the Safe Drinking Water Act is not without precedent, and that the proposed legislation would simply bring hydraulic fracturing in line with other industry practices.
“Mines and companies that inject waste underground are already regulated by the E.P.A.,” said Ms. Mall. “It’s not like they’re being asked to do something completely new.”
Gas industry representatives, however, insist that states already regulate hydraulic fracturing, and that federal oversight is unwarranted.
“In the past 50 years, more than one million wells have been fractured under state regulation, and not a single well has been linked to drinking water contamination,” said Jeff Eshelman, a spokesman for theIndependent Petroleum Association of America, in an e-mail message.
Mr. Eshelman argued that regulation would increase the costs of building and maintaining gas wells and ultimately lead to the loss of jobs. Pointing to Alabama, the only state where E.P.A. Safe Drinking Water Act statutes have been applied to the underground injection of fracturing fluids, Mr. Eshelman also suggested that water scarcity could become more acute under a new regulatory regime.
According to Mr. Eshelman, the 11th Circuit Court of Appeals ruledin 1997 that only “federally certified” drinking water could be used as a fracturing agent in Alabama coal bed methane projects.
While that decision was voided after the 2005 Energy Policy Act exempted the regulation of fracturing fluids under the Safe Drinking Water Act, Mr. Eshelman said that the FRAC Act could trigger similar rulings across the country and potentially put gas companies in direct competition with municipalities for water.
“This could pose a serious issue for parts of the country, such as out West, where water supplies are a major concern,” wrote Mr. Eshelman.
Websites featured in this post
http://degette.house.gov/images/pdf/frack_senate.pdf
https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEiqjBS1xJxdbwHPbph_MmObUK0SXd74s5dGApP6xgKrb8_2NuBPO6kcgDuHJgPpke32P5XhvAPWQBlb88wEOzA5jME_dGPGOwbrG4oadLIA-U5opsugUAkFWk1gvQuNQb1nzGRvzlGNOCI/s1600-h/Fracing+fluids.png
http://www.halliburton.com/ps/default.aspx?pageid=106&navid=93&prodgrpid=MSE::1045774307813937
http://www.nytimes.com/2008/12/19/nyregion/19drill.html?_r=1
http://www.iogcc.state.ok.us/
http://www.propublica.org/feature/buried-secrets-is-natural-gas-drilling-endangering-us-water-supplies-1113
http://www.nrdc.org/land/use/down/contents.asp
http://www.ipaa.org/
http://www.energyindepth.org/PDF/LEAF_v_EPA.pdf
My personal and professional opinion:
1. The drilling companies should provide a listing and the approximate volume and mass of each chemical used - this should include MSDS sheets. This information should be in a format the community, royality owner, and local governments can understand.
2. Some companies are taking the lead on this issue - for example Fortuna
http://www.fortunaenergy.com/where_we_operate/marcellus_shale.html
3. Here is a listing of what Fortuna is using
http://www.fortunaenergy.com/upload/media_element/26/01/microsoft-word---chemical-descriptions-for-marcellus-shale-wells-fortuna-_2_.pdf
4. Hydrofracturing is not new - it has been used repeatedly for shallow groundwater development.
5. The chemicals in the frac water will likely cause less of a concern than the connate water and brine water removed from the borehole - I think the primary concern should be frac water treatment, reuse, and management and the possibily for deep well reinjection of the fluid.
6. The recipe for the frac fluid and drilling mud should be confidential - but the chemicals and estimated quality should be reported. Just like any recipe - the details are one thing - but the ingredients are still on the label.
This was written by JEREMY MILLER
Original post may be
http://greeninc.blogs.nytimes.com/2009/06/30/of-hydraulic-fracturing-and-drinking-water/
A bill introduced earlier this month would bring federal oversight of hydraulic fracturing fluids – chemical mixtures pumped at high pressure into oil and gas wells in order to unlock deposits trapped deep underground.
Environmentalists welcomed the bill, but representatives of the natural gas industry say the legislation could lead to increased costs, job losses and increased competition for water — particularly in the West.
The bill, known as the Fracturing Responsibility and Awareness of Chemicals Act, (FRAC) was introduced in both the House and Senate by representatives from Colorado, Pennsylvania and New York. It essentially seeks to overturn a 2005 legislative tweak that placed fracturing fluids outside the regulatory purview of the Safe Drinking Water Act.
“Our legislation says everyone deserves to have safe drinking water by ensuring that hydraulic fracturing is subject to the protections afforded by the Safe Drinking Water Act,” said Representative Maurice Hinchey, a New York Democrat and one of the bill’s authors, in a prepared statement. “The bill also lifts the veil of secrecy currently shrouding this industry practice.”
Several kinds of fracturing fluids are used by the gas industry. Some are merely water or compressed gases injected underground at high pressure. Others are slurries that contain a host of chemicals and “proppants” — granular substances composed of resin-coated sand grains or similar synthesized materials — that expand in the ground and hold open fissures for gas and oil to pass through.
Hydraulic fracturing fluids were developed by Halliburton in the 1940s, but their use has increased recently as exploration of deep gas fields in places like the Marcellus Shale and Colorado’s Roan Plateau has stepped up.
Today, nine out of 10 gas wells in the United States currently use fracturing fluids, according to the Interstate Oil and Gas Compact Commission, a multistate government group.
Whether or not those fluids are polluting water supplies is a matter of debate, though a lengthy report by the investigative site ProPublica last year noted that this is often difficult to determine — not least because the precise makeup of fracturing fluids are considered trade secrets in the industry.
The pending legislation would require disclosure of ingredients.
Amy Mall, a senior policy analyst with the Natural Resources Defense Council, said that the push for regulation under the Safe Drinking Water Act is not without precedent, and that the proposed legislation would simply bring hydraulic fracturing in line with other industry practices.
“Mines and companies that inject waste underground are already regulated by the E.P.A.,” said Ms. Mall. “It’s not like they’re being asked to do something completely new.”
Gas industry representatives, however, insist that states already regulate hydraulic fracturing, and that federal oversight is unwarranted.
“In the past 50 years, more than one million wells have been fractured under state regulation, and not a single well has been linked to drinking water contamination,” said Jeff Eshelman, a spokesman for theIndependent Petroleum Association of America, in an e-mail message.
Mr. Eshelman argued that regulation would increase the costs of building and maintaining gas wells and ultimately lead to the loss of jobs. Pointing to Alabama, the only state where E.P.A. Safe Drinking Water Act statutes have been applied to the underground injection of fracturing fluids, Mr. Eshelman also suggested that water scarcity could become more acute under a new regulatory regime.
According to Mr. Eshelman, the 11th Circuit Court of Appeals ruledin 1997 that only “federally certified” drinking water could be used as a fracturing agent in Alabama coal bed methane projects.
While that decision was voided after the 2005 Energy Policy Act exempted the regulation of fracturing fluids under the Safe Drinking Water Act, Mr. Eshelman said that the FRAC Act could trigger similar rulings across the country and potentially put gas companies in direct competition with municipalities for water.
“This could pose a serious issue for parts of the country, such as out West, where water supplies are a major concern,” wrote Mr. Eshelman.
Websites featured in this post
http://degette.house.gov/images/pdf/frack_senate.pdf
https://blogger.googleusercontent.com/img/b/R29vZ2xl/AVvXsEiqjBS1xJxdbwHPbph_MmObUK0SXd74s5dGApP6xgKrb8_2NuBPO6kcgDuHJgPpke32P5XhvAPWQBlb88wEOzA5jME_dGPGOwbrG4oadLIA-U5opsugUAkFWk1gvQuNQb1nzGRvzlGNOCI/s1600-h/Fracing+fluids.png
http://www.halliburton.com/ps/default.aspx?pageid=106&navid=93&prodgrpid=MSE::1045774307813937
http://www.nytimes.com/2008/12/19/nyregion/19drill.html?_r=1
http://www.iogcc.state.ok.us/
http://www.propublica.org/feature/buried-secrets-is-natural-gas-drilling-endangering-us-water-supplies-1113
http://www.nrdc.org/land/use/down/contents.asp
http://www.ipaa.org/
http://www.energyindepth.org/PDF/LEAF_v_EPA.pdf
My personal and professional opinion:
1. The drilling companies should provide a listing and the approximate volume and mass of each chemical used - this should include MSDS sheets. This information should be in a format the community, royality owner, and local governments can understand.
2. Some companies are taking the lead on this issue - for example Fortuna
http://www.fortunaenergy.com/where_we_operate/marcellus_shale.html
3. Here is a listing of what Fortuna is using
http://www.fortunaenergy.com/upload/media_element/26/01/microsoft-word---chemical-descriptions-for-marcellus-shale-wells-fortuna-_2_.pdf
4. Hydrofracturing is not new - it has been used repeatedly for shallow groundwater development.
5. The chemicals in the frac water will likely cause less of a concern than the connate water and brine water removed from the borehole - I think the primary concern should be frac water treatment, reuse, and management and the possibily for deep well reinjection of the fluid.
6. The recipe for the frac fluid and drilling mud should be confidential - but the chemicals and estimated quality should be reported. Just like any recipe - the details are one thing - but the ingredients are still on the label.
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