In its Executive Summary of the revised SGEIS released yesterday, the DEC states clearly that groundwater is at sufficient risk from gas drilling to restrict gas drilling to protect those drinking groundwater. But they only afford that protection to those drinking from primary aquifers. The DEC leaves the great majority of drinkers of groundwater in the Marcellus unprotected. They have some explaining to do.
I’m looking forward to hearing the DEC’s logic and science—their risk assessment strategy— used to assess that only some drinkers of contaminated groundwater need protection.
Primary aquifers are used as drinking water for some municipalities.
The list is on on page 5: http://www.dec.ny.gov/docs/water_pdf/togs213.pdf
The list includes about 300,000 people in those municipalities drinking water from these primary aquifers in counties in the Marcellus shale. (see attached spreadsheet and chart at bottom.)
Page 18 of the new DEC doc describes the exclusion of primary aquifers. It’s pasted below, bold face added.
No HVHF Operations on Primary Aquifers
Although not subject to Filtration Avoidance Determinations, 18 other aquifers in the State of New York have been identified by the New York State Department of Health as highly productive aquifers presently utilized as sources of water supply by major municipal water supply systems and are designated as “primary aquifers.” Because these aquifers are the primary source of drinking water for many public drinking water supplies, the Department recommends in this dSGEIS that site disturbance relating to HVHF operations should not be permitted there either or in a protective 500-foot buffer area around them. Horizontal extraction of gas resources underneath Primary Aquifers from well pads located outside this area would not significantly impact this valuable water resource.
As the DEC says, this is in addition to the exclusion of drilling in the watersheds of NYC and Syracuse.
Now, one can make an argument, as the DEC has, that the exclusion of drilling in the NYC and Syracuse water supplies is based on their being unfiltered surface water (as opposed to ground water), with a risk of “turbidity” from surface drilling activity. And because there have been rules in place for years restricting industry and development in unfiltered surface watersheds to avoid having to build super-expensive filtration plants, as for NYC. A more clear eyed assessment of carving out the NYC watershed is that the DEC wants to excise the political opposition of NYC, which could easily create a critical mass of opposition in the state. But they do have the surface water “turbidity” argument to fall back on to explain this preferential exclusion, even if politics is the underlying reason.
But when you are dealing with groundwater sources, how can you rationally and scientifically exclude some aquifers and not others? Again, the actual rationale appears overtly political, rather than based on the science or risk. The DEC is trying to carve out the opposition of the municipalities drinking from primary aquifers—including Jamestown, Elmira, Cortland, Binghamton, Corning, Salamanca. After all, these municipalities are really organized entities of people…….. who would otherwise likely oppose drilling.
Problem is, there are at least 1,140,000 people drinking groundwater in the Marcellus shale. What’s up, DEC? You’ve determined that groundwater is at risk. You’re going to protect 300,000 people from ground water pollution, but not the other 840,000.
Who are those people? Hello, it’s us, the people of rural NY State who will be drinking from polluted wells. It’s us, people who will not be receiving equal protection against the very threats that the DEC assesses are too risky for the people of upstate municipalities.
I think I’m going to call my lawyer.
Ken Jaffe, MD
county percent of population drinking groundwater county population population drinking groundwater population drinking groundwater from primary aquifer population drinking groundwater not from primary aquifer name of primary aquifer Cortland 100 49,336 49,336 39,000 10,336 Cortland-
Chenango 95 50,477 47,953 47,953 Tioga 90 51,125 46,013 46,013 Waverly-
Cattaraugus 90 80,317 72,285 72,285 Salamanca Allegany 85 48,946 41,604 41,604 Steuben 80 98,990 79,192 49,000 30,192 Corning-Cohocton Broome 80 200,600 160,480 110,000 50,480 Endicott-
Schuyler 80 18,343 14,674 14,674 Madison 75 73,442 55,082 55,082 Otsego 75 62,259 46,694 46,694 Chemung 70 88,830 62,181 50,000 12,181 Elmira Yates 60 25,348 15,209 15,209 Genesee 60 60,079 36,047 36,047 Wyoming 55 42,155 23,185 23,185 Chautauqua 50 134,905 67,453 52,000 15,453 Jamestown Seneca 30 35,251 10,575 10,575 Ontario 25 107,931 26,983 26,983 Cayuga 25 80,026 20,007 20,007 Albany 20 304,204 60,841 60,841 Tompkins 15 101,564 15,235 15,235 Onondaga 15 467,026 70,054 70,054 Monroe 10 744,344 74,434 74,434 Erie 5 919,040 45,952 45,952 Totals 3,844,538 1,141,468 300,000 841,468
- incomplete DEC data on primary aquifer in Cattaraugus and Tioga Counties may underestimate those drinking from primary aquifer by up to 50,000; this could raise the total using primary aquifers to about 350,000
- incomplete DEC data on total users of ground water does not include Delaware and Sullivan Counties; this could raise the total users of unprotected groundwater to about 950,000
Office of Research and Development
U. S. Environmental Protection Agency
September 13, 2010
Re: Potential Relationships Between Hydraulic Fracturing and Drinking Water Resources
I have reviewed your scoping materials released in March 2010, and would like to offer some comments for your consideration. A common theme among them is the idea of context: I encourage you to sense and communicate the most holistic viewpoint possible as this research initiative advances.
The term “hydraulic fracturing”:
As a biochemist and former construction professional, I’ve been striving to apprehend the gas industry’s foray into shale gas extraction for about two years. This study has brought me into contact with a large number of industry representatives, state and river basin commission officials, and environmental activists. I’ve found that people from the three groups not only are far apart in their perceptions, they employ technical language very differently. Of greatest significance here, environmentalists tend to apply the term “hydrofracking” to the overall process of gas extraction from unconventional reservoirs – from access road construction to pipeline pressurization, while industry insiders use the term chiefly to describe the specific technical steps taken to force fissures in rocks deep underground. Regulators and public health officials with whom I’ve discussed it have been split on this semantic question.
I recommend that, in addition to providing a glossary of terms, you include a section devoted to the various meanings that have been attached to the term “hydraulic fracturing”, and explain the definition by which it should be understood by those reading your report(s). Whatever choice you make with respect to the definition of hydraulic fracturing, I urge you to ensure that this investigation encompasses the broadest possible scope.
Influence of human error:
Another important element of context regards whether or not human error should be considered integral to the overall process of shale gas extraction. Industry representatives I’ve conferred with claim that the process is safe – as long as it is done properly. Incidents about which I’ve challenged them, from Alabama, Arkansas, Colorado, Louisiana, Michigan, New Mexico, Ohio, Oklahoma, Texas, West Virginia, Wyoming, and multiple sites in PA, have been met with explanations reasonably paraphrased as, “Yes, well, that was due to human error. The process itself is completely safe.” (This begs the questions of when and how the industry intends to shift its labor force to non-humans.) Whether and to what degree human error is included as a factor in your assessment of hydraulic fracturing should be explicitly stated.
I believe it would be helpful to assess the relative influences of human error and current technology on the overall safety of shale gas extraction. Specific questions that might contribute to “pure technology” risk assessments include:
How many fractures are propagated in a typical hydraulic fracturing stage? (Hundreds? Thousands?)
What is the detection limit for fractures extending beyond the target zone? (1%? 10%?)
Do different rock strata overlying shales suppress out-of-zone fractures or propagate them? How are these fractures monitored empirically (if they ever are)? What is the current time-frame of fracture growth observation? (Days? Months?) What should that time frame be?
Long-term fate of infrastructure:
With respect to time frames, I recommend that you develop longitudinal data on abandoned infrastructure (played-out wells, pipelines and underground storage facilities). How long will steel pipe within concrete casing withstand the corrosive effects of brines and sulfur-metabolizing microbes at temperatures up to 180 °F? (50 years? 150 years?) How much pressure redevelops in that time? What impact does repeated stimulation by hydraulic fracturing exert on the longevity of a gas well’s casing? How do hydraulic fracturing and underground injection in target zones above and beneath an abandoned horizontal well affect the integrity of its casing and plugs?
Here are some more readily accessible questions: What monitoring programs for abandoned infrastructure are maintained by energy companies and/or regulatory agencies? What reporting is required? What activities are underway to locate and stabilize “orphan” wells and pipelines?
Air quality concerns:
While your congressional mandate is to study potential relationships between hydraulic fracturing and drinking water resources, the impact of shale gas extraction on air quality is also of real concern. In particular, the use of open pits for impounding flow-back fluids from gas wells practically guarantees health impacts on people and animals in close proximity. Most organic chemicals used as additives are less dense than water, so they float to the pond surface (classic oil / water separation). These organics concentrate until they comprise essentially 100% of the surface. There they vaporize and aerosolize into the overlying and surrounding air.
The widespread venting of condensate tanks and “glycol” reboilers, related to purifying “raw” natural gas, also contributes to diminished air quality in and around gas fields.
A possible consequence is the increasingly described “down-winder’s syndrome” characterized by frequent headaches, nausea, sore throats, rashes, dyspnea, and peripheral neuropathy, with occasional mental confusion, hair loss, fatigue and myalgia. I urge you to investigate possible links of shale gas extraction to this phenomenon as well as to locally elevated levels of ozone and diesel combustion particulates.
Recapture of “lost” data:
Citizens who complain to county or state agency officials about alleged damage from nearby gas extraction activities are often encouraged to seek redress from the companies they blame for their losses. Energy company officials typically (1) deny any culpability for the citizens’ losses, and (2) offer assistance as “good neighbors” in exchange for (3) the aggrieved citizens’ signatures on liability releases / non-disclosure agreements. Whenever such contracts are signed, local officials typically note that the reported problems were solved, and close their investigations.
The scale of ongoing retail purchases of bottled water, in locales where complaints against gas extraction companies had surfaced, suggest that many homeowners’ complaints have not been resolved, and significant incident data may be forfeited by their non-disclosure agreements. This data is non-discoverable; however, I recommend that you offer some legal mechanism (e.g. limited immunity) for damaged homeowners and gas company executives to contribute the benefit of their experiences to your investigation.
Context of other investigations:
I encourage you to evaluate the results of your investigation in the light of other federally-funded studies, particularly the 2010 Annual Report of the President’s Cancer Panel, “Reducing Environmental Cancer Risk: What We Can Do Now”, and the pending U. S. Department of Energy report on Energy and Water.
Thank you for your attention.
Dr. Ronald E. Bishop
Oral comment on scoping document for EPA study, 9/15/10, Binghamton, NY:
I own 200+ acres. I was offered a lease, and experience the difficult consequences of both long- and short-term economic trends. Yet this is not another plea for gas extraction.
The first problem with this scope is its foregone conclusion, found in its very first sentence. “Natural gas plays a key role in our nation’s clean energy future.” Two biases in twelve words! – the second of which is downright false: natural gas is NOT clean energy. What a way to begin a study! The sentence continues, “…and the process known as hydraulic fracturing is one way of accessing that vital resource.” Nowhere is the question asked: With present technology and the limits of human performance, CAN natural gas extraction proceed with guaranteed safety, including in a low-impact, non-industrializing manner? These assumptions and omissions are serious flaws.
Next, to avoid conclusions that are theoretical, nebulous, and open to manipulation, an essential aspect of data gathering is the close scrutiny of all records of all state regulatory agencies for problems associated with the full spectrum of natural gas extraction processes. Yet this channel of investigation receives little if any mention in this document. To the point, such records are difficult to find. In response to a 2009 FOIL request, the New York State DEC admitted that the agency does not compile a record of drilling problems requiring follow-up. In fact, for decades, regulatory agencies everywhere have had very cozy relationships with the industries they regulate. The result: a dearth of official documention and recognition of the fact that, as the tail follows the dog, groundwater pollution follows natural gas extraction whereever it goes.
Therefore, this study must:
1) dispense with foregone conclusions and biases
2) examine case histories and regulator records unflinchingly and in detail
3) provide a frank assessment of the effects of industry influence on regulators’ record-keeping
4) avoid all such influence itself
Comments to the EPA Hearing on Horizontal Drilling /High-Volume Hydraulic Fracturing
September 15, 2010, Binghamton, New York
Good evening. My name is Joan Tubridy; I am the daughter of a NYC Fire Captain, a former farmer for 23 years, and a middle school Math and English teacher for the past 16 years. I am also a member of CDOG (Chenango Delaware Otsego Gas Drilling Opposition Group). I wish to thank Mike Bernhard of Chenango County for his significant contributions to my remarks.
I grew up believing that state agencies with names like the Department of Environmental Conservation, the Department of Environmental Protection, the Arkansas and Louisiana Departments of Environmental Quality, the Ohio Environmental Protection Agency, and the Texas Commission on Environmental Quality were all obligated to fulfill the mandates of their chosen titles. Over these past two years, I have had a disappointing education. These agencies appear to be captured by an industry they’ve been tasked to regulate.
For example, just this past Tuesday, Governor Ed Rendell of Pennsylvania said that the state Office of Homeland Security, which has been sending information about anti-gas drilling groups to law enforcement and drilling companies, will no longer do so. Should we feel reassured?
Furthermore, spokespersons for the Oil and Gas Industry have obfuscated the truth so often that they have apparently deceived pro-gas coalitions, members of Congress, and agencies with “Environmental” in their titles. The industry has repeatedly stated that the horizontal-drilled, high-volume hydrofracturing (HD/HVF) technology that makes the Marcellus Shale such a plum for gas corporations, has been going on safely for decades.
In fact, there has not been one HD/HVF well in the Marcellus or any other shale body in New York. Ever. Two current drilling practices (drilling horizontal wells in sandstones, and fracturing vertical wells in shale) have been co-mingled as if they “added up” to horizontal-drilled, high-volume hydrofractured wells in the Marcellus Shale (HD/HVF). They don’t and here’s why:
The Herkimer sandstone formation in Chenango County, New York, for example, is a porous stone which produces no methane, but which has – over geologic time – absorbed methane from neighboring shale formations. Though horizontally-drilled, these sandstone wells require no fracking. A single square mile filled with 80-acre Herkimer drilling units would not require one drop of frack fluid, nor produce one drop of toxic flowback. But a single square-mile HD/HVF Marcellus drilling unit, containing typically eight 4000-foot well bores on one pad, would require 32,000,000 gallons of fracking fluid.
A sandstone well is drilled once, never fractured, and the gas is gone; shale wells can be fractured multiple times, using increasing amounts of fracking fluids each time, to get decreasing amounts of gas.
Similarly, vertical wells drilled through the thin Marcellus shale encounter only about 150 feet of shale available for fracking, and are legally limited to using 80,000 gallons of fracking fluid per well. So, a fully built-out square mile of vertical Marcellus wells at the legal 40-acre spacing, will therefore yield about 2400 feet of frackable shale and be legally limited to using 1,280,000 gallons of fracking fluid. Compare this with horizontal well bores in that same thin layer in Pennsylvania which are commonly 4000 feet long on an eight-well pad: a total of 32,000 feet of frackable wellbore, requiring 32,000,000 gallons of fracking fluid.
Horizontal-drilled, high-volume hydrofracturing (HD/HVF) in the Marcellus Shale creates twenty-five (25) times the length of frackable wellbore as those created by a fully built-out vertical Marcellus field. That’s twenty-five times the drill cuttings, twenty-five times the flowback wastewater, twenty-five times the truck-traffic for water haulage, and twenty-five times the flowback disposal.
Horizontal-drilled, high-volume hydrofracturing (HD/HVF) in the Marcellus Shale requires fracking fluid that is thirty-five (35) times the legal limit for vertical shale wells, ignoring subsequent re-fracturing. The no-frack Herkimer sandstone experience is irrelevant to the discussion at hand today, though industry would like us to believe that horizontal-drilled, high-volume hydrofracturing (HD/HVF) has been going on for decades.
Another industry obfuscation was recently employed in Pennsylvania when a Chesapeake spokesperson attempted to shift the blame for recent water well problems following gas drilling, to poor construction and drilling of water wells. In his August 22, 2010 letter to the editor of the Sunday Review, Thomas Cummings, a water well driller in Towanda, Pennsylvania refuted this claim by Chesapeake and defended his practices and reputation. Several local homeowners contacted Mr. Cummings regarding disturbances in their water wells that began after nearby gas drilling activity had started. Mr. Cummings states, “The excitement of gas lease funding and large drilling rigs coming to our area has been replaced by damaged roads; delayed travel and traffic snarls; streams sucked dry by convoys of trucks driven by persons foreign to our area … residential sweet water invaded by methane that is blowing off well caps; local families displaced by gas workers; and other changes affecting our work and lifestyles. Our drinking water is being affected and millions of gallons of water are being extracted from our streams, rivers and municipal wells with insufficient recharge.”
I urge you, the Environmental Protection Agency:
1. to be wary of industry’s deliberate deceptions and to examine those mentioned above, and
2. to find individuals who have suffered contamination of their homes by the gas industry, and who have been silenced by money, trucked-in domestic water, and nondisclosure agreements. Legally challenge these nondisclosure agreements and seek out the stories these families have to tell about how their lives have become desperately focused on what most of us take for granted – a healthy home environment for our families.
I urge the Environmental Protection Agency to fulfill the grave obligation imbedded in your name.
November 7, 2008
Bureau of Oil & Gas Regulation
NYSDEC Division of Mineral Resources
625 Broadway, Third Floor
Albany, NY 12233-6500
Attention: dsGEIS Scope Comments
Dear NYSDEC regulators,
I am a small landowner who is concerned that proposed gas drilling on the two large farms adjacent to my property could contaminate my water well or deplete the aquifer that supplies my well. I plan on selling my home in the near future and need the monetary gains as part of my retirement income. My home & property value would be rendered virtually worthless if there were no water supply. I have read the dsGEIS and feel the following items need more emphasis/study or inclusion:
Procurement of professionally trained Gas Drilling Inspectors
Requiring Gas Drilling Companies to prepare Plans and Specifications for submittal to DEC
DEC needs to thoroughly research current gas well casing cement compositions and procedures
DEC should require a gas drilling company to furnish proof of adequate liability insurance
Issue 1: The need for PROFESSIONALLY TRAINED INSPECTORS
I worked for NYSDOT for 8yrs in the Bridge Design Unit and ODOT (Oregon DOT) for 16 yrs as a Construction Inspector and Materials Tester and later on advanced to an Associate Transportation Engineer as a Roadway Designer. I will tell you from first hand experience that a project as simple as State Highway Asphalt Paving required an ON-SITE-DAILY- OREGON D.O.T. TRAINED FIELD INSPECTOR and an ON-SITE-DAILY ODOT ASPHALT MATERIALS INSPECTOR testing the asphalt for such things as moisture content, percentage of asphalt in the mix, aggregate gradation sieve analysis and density. I know this because I was this Asphalt Materials Inspector. Thus, an operation the magnitude of the Gas Drilling Operations certainly demands the same attention!! I stated this at the DEC meeting held in Greene and also the Coalition meeting held in Harpursville. I also backed my concerns up with two letters to Judith Enck with a copies sent to Assemblyman Clifford Crouch asking both of them to make sure my concerns were carried to the governor prior to him signing the Bill. I also sent an extremely detailed position description for a Canadian Oil & Gas Drilling Inspector in British Columbia, Canada. The job description serves to illustrate the importance the Canadian government places on FIELD INSPECTIONS, and the degree of detail contained in the job description shows that gas drilling is not a simple process nor should it be treated as such! I am extremely grateful to Gov. Paterson and his close advisors for realizing the critical need for Gas Drilling Inspectors and imposing a moratorium on all gas drilling until the state can provide a means of enforcing gas regulations. But, recognizing the need for inspectors and finding the funding for these positions are two different things especially with the current economy. Thus, if DEC can not currently fund inspector positions, the gas drilling should only advance as fast as the current DEC inspectors can monitor them!!
Issue 2: Need for CONTRACT PLANS AND SPECIFICATIONS prepared by the Gas Drilling Companies themselves with submittal to the DEC for review and approval.
I attended a meeting at the Binghamton Public Library conducted by The Independent Oil & Gas Association. I expressed the need for contract plans/specs and John Holko insisted that the Gas Drillers already provide such plans to the DEC. The next day, I called Linda Collart of the DEC and conveyed what Mr. Holko had said. The only thing she knew of that would be a detailed drawing of any sort consisted of ONE SHEET! I asked her to send me a copy of one of these sheets for a recent DEC approved gas well. This sheet shows the geological strata, depths, hole & casing design, etc. But, this one sheet is a far-far-cry from what I am referring to and accustomed to seeing on a Dept. of Transportation project.
During my tenure with NYSDOT and ODOT, I was involved in preparing Preliminary Bridge Plans and specs for interstate bridges on 110 miles of I-88. I also prepared Preliminary Plans for many Oregon Highway Construction projects from projects as simple as asphalt resurfacing projects all the way up to a modernization project involving widening a two lane highway to four lanes and the creation of a new alignment to meet 70mph design speeds which would avoid impacting 100yr old oak trees, four historic homes, a high power transmission line, and wetland areas. These plans were extensive in nature, covering every known aspect of the construction and typically entailing 50 or more contract sheets with accompanying specifications of 100 or more sheets. Thus, I don’t see a Gas Drilling Project as requiring anything less since the impacts can be every bit as far reaching.
To further drive this point home I will explain a project that I have first hand knowledge of that was in the hands of our very own New York State DEC for review. These were Contract Plans (24” x 36” size) drawn up by Keystone Engineers for a large pond my neighbor, located on the hill directly above me, was proposing to build. I became very concerned with the location of this proposed pond and the fact that no one was going to be on site as an inspector to ensure adherence to the specifications. Thus, I was successful in having DEC deny the permit for this pond. But the main reason I bring this up is to illustrate that the division of DEC requires rather extensive PLANS and SPECS for a pond when it reaches a certain size and volume. And I might add that a pond does not pose any risk to underground water tables nor does it contain any toxic chemicals to pollute water supplies!! Thus, why isn’t this requirement for plans and specs carried over to the Gas Drilling Operations?? The Plans and Specs would succeed in one huge accomplishment, that being — there would be no mystery and no doubt about what the Gas Companies might be up to; their procedures would have to be clearly explained with accompanying detailed drawings and construction notes showing every aspect of their operation. It would be very refreshing and assuring for landowners and DEC personnel to know exactly what the Gas Drilling Plan is.
You might be thinking, what is there about a Gas Drilling Operation that would require a detailed drawing plan with accompanying specifications? ….. I will give you just one example: Environmentalist Bob Williams gave a presentation at the Coalition meeting in Harpursville wherein he showed a picture of a gas drilling pad. The pad was quite large and required that the earth be leveled with a berm constructed around the perimeter. This picture caused me to immediately think of my neighbors Pond Plans and Specs. The gas drilling berm is very much like the pond berm. The pond berm specs state that “the embankment is to be constructed in maximum 8” thick layers running continuous for the entire length of the fill with each layer being compacted prior to placement of the next layer, and the fill is to have at least 30% passing the #200 sieve.” Now, do you actually think the drilling pad berm was constructed in this manner?? I would bet the drill pad berm was constructed by a dozer pushin’ dirt up into an unkempt pile that was never even compacted. Now, what was the pond berm serving to contain? Yep, pure water. Now what is the drill pad berm supposed to contain? You got it, impure hazardous materials!! As you already know, the Gas Companies are not required to disclose these hazardous materials. However, Colorado Environmentalist Theo Colburn, PhD has discovered over 200 chemicals directly injected into the gas well during the fracturing process yet she (and I quote) “had been unable to find any information on the chemical content of waste pits until we were sent results of a chemical analysis of the residues from six waste pits in New Mexico. The 51 chemicals that were detected in those pits produced a health pattern even more toxic than anything we found in the past. Most important is that 43 of the 51 chemicals detected in the pits were not even on our original list of chemicals used during natural gas operations!” Thus, this drill pad and waste pits need the same careful plan drawings and specifications as DEC requires for a fairly innocuous pond berm!! And this is just one example of drilling details that need to be spelled out in a drawing with construction notes/specs. I know you are thinking how requiring the gas companies to develop and submit plans would slow up the gas drilling process even more than the procurement of inspectors, but this could be a good thing. It could give the state more time to ascertain how it will obtain funding for inspector type staff. And most of the onus of time and money to develop the plans would be placed on the Gas Drilling Companies with our DEC merely reviewing the plans which takes far less time than developing the plans.
Issue 3: DEC needs to RESEARCH GAS WELL CEMENT COMPOSITIONS AND CEMENTING PROCEDURES and HIRE AN OUTSIDE PROFESSIONAL IN THIS FIELD SUCH AS “SCHLUMBERGER” TO REVIEW GAS DRILLING APPLICATIONS SUBMITTED TO DEC FOR APPROVAL since this is such a complicated and critical aspect of gas drilling.
In the above mentioned example of a current DEC approved gas well that Linda Collart sent me, I noticed that Class A cement was being used. I called her to ask if this was regular Portland Cement and she said yes. Since I used to be an Asphalt and Concrete Materials Tester for Oregon DOT, I became concerned over the rigidity of Portland Cement and the extreme conditions deep gas well bore holes and drilling operations would exert on this concrete after the casing was cemented. Thus, I researched this topic and present the following findings:
Proper cementing is critical for the protection of subsurface aquifers and the prevention of gas leaking into zones that would otherwise not be gas bearing. Tubing and casing leaks, poor drilling and displacement practices, improper cement selection and design, and production cycling may all be factors in the development of gas leaks. Thus, the primary Gas drilling contractor frequently subcontracts this aspect of gas drilling to a company that exclusively performs this cementing operation. DEC personnel may have heard of “Schlumberger” since they are internationally renowned experts in this field. I contacted them for help via email and they responded by saying “IF the DEC is interested in soliciting our help we would be willing to participate.” (I have enclosed a copy of this email.) Here are some of my findings on this complicated aspect of drilling that even the professionals in the Oil & Gas Industry admit that they are still in the process of perfecting. Schlumberger says “much work remains to be done in simulating downhole conditions and developing new cement technologies/compositions for thermal applications and high pressure conditions.”
“During the life of a well, the cement sheath may be exposed to stresses imposed by well operations including perforating, hydraulic fracturing, high temperature-pressure differentials, and so on. Further, if the well is completed using complex completion such as a multilateral system, the cement sheath may be subject to shattering and subsequent loss of bond to pipe impact. Conventional well cement compositions are typically brittle when cured. These conventional cement compositions often fail due to stresses, such as radial and/or tangential stresses, that are exerted on the set cement. In other cases, cements placed in wellbores may be subjected to mechanical stress induced by vibrations resulting from operations, for example, in which wireline and pipe conveyed assembly are moved within the wellbore. Hydraulic, thermal and mechanical stresses may be induced from forces and changes in forces existing outside the cement sheath surrounding a pipe string. For example, overburden and geological formation pressures, formation temperatures, formation shifting, formation compaction, etc. may cause stress on cement within the wellbore. Conventional wellbore cements typically react to excessive stress by failing.”
Halliburton offers the following: “Wellbores exist in extremely dynamic environments; therefore, a cement sheath must be able to perform as intended over time. When cementing a well, the primary concern is to prevent fluids from migrating into an annulus. As a well ages, the annular seal may be compromised as a result of stresses brought on by temperature and pressure cycling that occur as the well is operated. By industry convention and tradition the effect of stresses on the cement sheath’s mechanical properties are not ordinarily assessed during the design and construction phase of a well. Although short term considerations are necessary for effective slurry mixing and placement, a sole focus on liquid cement slurry properties and the 24 hour compressive strength does not account for long-term cement integrity, which is critical if the well is subjected to stress on a large scale.” Halliburton has devised an analytical tool, “Welllife” computer software which analyzes properties such as Young’s modulus, friction angle, cohesion of cement sheath and simulates failure events that could occur during various field operations to determine the best cements for particular geological stratum.
Schlumberger says “cement sheath damage or debonding can allow gas to migrate to the surface and cause sustained casing pressure (SCP). The presence of such flows can require a well to be shut in for remediation or abandoned altogether.” Schlumberger has designed a “FUTUR active set-cement” which provides long-term zonal isolation and prevents the flow of hydrocarbons through potential leak paths up and along the annulus. Any hydrocarbon that comes in contact with FUTUR active cement technology will activate the self-healing properties of this unique sealant material. Once activated, cracks in the cement sheath are healed. Even if the cement sheath is damaged again, FUTUR active set-cement will continue to self-repair on multiple, independent occasions.
Schlumberger also mentions how important it is to have a clean wellbore prior to cementing. “It is important to get the initial cementing job right, with good mud removal. Mud pockets in the annulus can cause catastrophic failure, including broken wellbores and collapsed casing. Shlumberger uses WELLCLEAN methodology to ensure that there are no channels or pockets of mud that can cause well failure. Soft formations offer little constraining pressure, and tensile pressures may lead to breakage. Cements with a low Young’s modulus, such as the flexible cement system using FlexSTONE technology, can deliver mechanical properties appropriate for these downhole stress environments.
The following are excerpts from a paper titled “From Mud to Cement-Building Gas Wells” dated Autumn 2003 by Tom Griffin of Griffin Cementing Consulting LLC, Joseph R. Levine of the US Minerals Management Service, Dominic Murphy of BHP Billiton Petroleum to name but a few of the authors. This study serves to illustrate the complexity of the cementing process; if the experts in this field attest to the complexity of this aspect of drilling, I think NYSDEC should pay more attention to cement designs and cementing procedures. “Since the earliest gas wells, uncontrolled migration of hydrocarbons to the surface has challenged the oil and gas industry. Gas migration, also called annular flow, can lead to sustained casing pressure (SCP), sometimes called sustained annular pressure (SAP).” “In the Gulf of Mexico, there are approximately 15,500 producing, shut-in and temporarily abandoned wells in the outer continental shelf area. United States Minerals Management (MMS) data show that 6692 of these wells, or 43%, have reported SCP on at least one casing annulus.” “By the time a well is 15 years old, there is a 50% probability that it will have measurable SCP in one or more of its casing annuli. However, SCP may be present in wells of any age. In Canada, SCP occurs in all types of wells-shallow gas wells in southern Alberta, heavy-oil producers in eastern Alberta and deep gas wells in the foothills of the Rocky Mountains. Most of the pressure buildup is due to gas.” “Long-term, durable zonal isolation is key to minimizing problems associated with annular gas flow and SCP development.” “Determining the precise source of annular flow or sustained casing pressure is often difficult, although likely causes can be divided into four primary categories: tubing and casing leaks, poor mud displacement, improper cement-slurry design, and damage to primary cement after setting. Leaks can result from poor thread connection, corrosion, thermal stress cracking or mechanical rupture of the inner string, or from a packer leak. If the pressure from a leak causes a failure of the production casing the outcome can be catastrophic. Leaks to the surface or underground blowouts may jeopardize personnel safety, production-platform facilities and the environment.” “Inadequate removal of mud or spacer fluids from the borehole prior to cement placement is a major contributing factor to poor zonal isolation and gas migration.” “Improper cement-slurry designs –Flow occurring before cement has set is a result of loss in hydrostatic pressure to the point that the well is no longer overbalanced – hydrostatic pressure is less than formation pressure. This decrease in hydrostatic pressure results from several phenomena that occur as part of the cement-setting process. The change from a highly fluid, pumpable slurry to a set, rock-like material involves a gradual transition of the cement. This may require several hours, depending on the temperature, and quantity and characteristics of retarding compounds added. As the cement begins to gel, bonding between the cement, casing and borehole allows the slurry to become partially self-supporting. This self-supporting condition would not be a problem if it occurred alone. The difficulty arises because, while the cement becomes self-supporting, it loses volume as a result of at least two factors. First, where the formation is permeable, the hydrostatic pressure overbalance drives water from the cement into the formation. The rate of water loss depends on the pressure differential, formation permeability, and fluid loss characteristics of the cement. A second cause pf volume loss is hydration volume reduction as the cement sets. This occurs because set cement is denser and occupies less volume than liquid slurry. Volume loss coupled with the interaction between partially set cement, borehole wall and casing cause a loss of hydrostatic pressure, leading to an underbalanced condition. While the hydrostatic pressure in the partially set cement is below formation pressure, gas may invade. If unchecked, the invasion of gas may create a channel through which gas can flow, effectively compromising cement quality and zonal isolation. Also, cement damage can occur long after the well construction process. Even a flawless primary cement job can be damaged by rig operations or well activities occurring after the cement has set. Changing stresses in the wellbore may cause microannuli, stress cracks, or both, leading to SCP. The mechanical properties of the casing and the cement vary significantly. Consequently they do not behave in a uniform manner when exposed to changes in temperature and pressure. As the casing and cement expand and contract, the bond between the cement sheath and casing may fail, causing microannulus, or flow path, to develop.
As the borehole reaches deeper into the earth, previously isolated layers of formation are exposed to one another, with the borehole as the conductive path. Isolating these layers, or establishing zonal isolation, is key to minimizing the migration of formation fluids between zones or to the surface where SCP would develop. Crucial to this process are borehole condition, effective mud removal, and cement-system design for placement, durability and adaptability to the well life cycle. Wellbore condition depends on many factors, including rock type, formation pressures, local stresses, the type of mud used and drilling operation parameters, such as hydraulics, penetration rate, hole cleaning and fluid density balance. The ultimate condition of the borehole is often determined early in the drilling process as drilling mud interacts with newly exposed formation. If mismatched, the interaction of the drilling mud with formation clays can have serious detrimental effects on borehole gauge and rugosity. Once a well is drilled, displacement, cementing and ultimately, zonal isolation efficiency are dependent on a stable borehole with minimal rugosity and tortuosity. Drilling fluid engineers and related technical specialists have applied various techniques to investigate rock response to drilling fluid chemistry under simulated downhole conditions. Mud companies have created high-performance water-base muds that incorporate various polymers, glycols, silicates and amines, or combination thereof, for clay control. Like the fluids themselves, drilling fluid hydraulics play a fundamental role in constructing a quality borehole. Balance must be maintained between fluid density, equivalent circulating density (ECD) and borehole cleaning. If the static or dynamic fluid density is too high, loss of circulation may occur. Conversely, if it is too low, shales and formation fluids may flow into the borehole, or in the worst case, well control may be lost. Improper control of density and borehole hydraulics can lead to significant borehole rugosity, poor displacement and failure to achieve isolation. Rheological properties of drilling fluids must be optimized in such a way that the frictional pressure losses are minimized without compromising cuttings-carrying capacity. Optimal fluid properties for achieving good borehole cleaning and low frictional pressure loss often appear to be mutually exclusive. Detailed engineering analysis is required to obtain an acceptable compromise that allows both objectives to be satisfied. During drilling, optimal fluid characteristics may change depending on the task, such as running casing or displacement borehole fluids. Modeling and simulation with software tools such as the M-I Virtual Hydraulics application can be useful in optimizing fluid properties in anticipation of changes in rig operations. Integrating carefully designed drilling fluids with other key services is critical for achieving successful wellbore construction, zonal isolation and well integrity.
Proper mud selection and careful management of drilling practices generally produce a quality borehole that is near-gauge, stable and with minimal areas of rugosity, or washout. To establish zonal isolation with cement, the drilling fluid must first be effectively removed from the borehole. Mud removal depends on many interdependent factors. Tubular geometry, downhole conditions, borehole characteristics, fluid rheology, displacement design, and hole geometry play major roles in successful mud removal. Optimal fluid displacement requires a clear understanding of each variable as well as inherent interdependencies among variables. The availability of computer technology has significantly advanced the way drillers approach wellbore displacement. Fluids can be built, complex interactions predicted, and displacements simulated on the computer screen rather than at the wellsite where minor mistakes may result in major costs. CemCADE cementing design and simulation software and WELLCLEAN II software are two software applications used for this purpose.
Integration of drilling fluids, spacer design and displacement techniques provide the foundation for optimal cement placement. Long-term zonal isolation and control of gas require the cement to be properly placed and to provide low permeability, mechanical durability and adaptability to changing wellbore conditions. Cement permeability depends on the solid fraction of the formulation. For high-density slurries, a high solid fraction is inherent, thus the permeability tends to be low. For low-density slurries, special products and techniques create low-density, high solid-fraction slurries. Mechanical durability varies with strength, Young’s modulus of elasticity and Poisson’s ratio. The cement should be designed so these properties are sufficient to prevent failure of the cement when exposed to changing well pressures and temperature fluctuations, which create stresses across the casing-cement-formation system. Special materials are required to give the cement flexibility in this environment. Sealing an annular space against gas migration can be more difficult in gas wells than in oil wells. Wellbore construction, particularly in the presence of gas bearing formations, requires that borehole, drilling fluid, spacer and cement designs, and displacement techniques be dealt with as a series of interdependent systems, each playing an equally important role. Often, the relationships among these systems is overlooked, or at the very least, poorly appreciated. Preventing gas migration and SCP has been helped by recent developments in cementing technology that offer significant advantages in durability and adaptation to changing wellbore conditions. Cement properties have traditionally been designed for optimal placement and strength development rather than long-term post-setting performance. The rapid development of high cement-compressive strength after placement was generally considered adequate for most wellbore conditions. Today, operators and service companies realize that the emphasis on strength at the expense of durability has often led to the development of SCP (sustained casing pressure) and reduced well productivity. Cement particle characteristics and size distribution can contribute significantly to both the resistance to gas influx and maintenance of a sustainable hydraulic seal, particularly in wellbores subjected to pressure and temperature cycling. FlexSTONE advanced flexible cement technology, part of the CemCRETE concrete-based oilwell cementing technology, is one of several solutions that effectively address cement flexibility and durability. Conventional Portland cements are known to shrink during setting. In contrast, FlexSTONE slurries can be designed to expand, further tightening the hydraulic seal and helping to compensate for variations in borehole or casing conditions. This capability helps avoid microannuli development. By adjusting specific additive characteristics and by blending the cement slurry with an engineered particle size distribution, a lowering of Young’s modulus of elasticity in cement can be achieved. Annular cement can then flex in unison with the casing rather than failing from tensile stresses. Thus, the potential development of microannuli and gas communication to the surface or to zones of lower pressure are minimized.” The original complete version of the above paper can be found at www.slb.com/media/services/resources/
Issue 4: DEC should not provide a well license to a person who does not furnish proof that the person has liability insurance of at least $5,000,000 per occurrence that provides compensation for all damages caused by drilling, pipeline construction, production, servicing or abandonment operations or caused by any vessel, craft or barge used to transport people or materials to the site of the drilling, pipeline construction or production operations.
I sincerely thank NYSDEC for welcoming the public’s comments on the dsGEIS and look forward to DEC’s response to my comments,
Attach: email from Schlumberger dated 10/26/2008
British Columbia, Canada OGC Oil and Gas Commission Position Description
Cc: Gov. David Paterson, Top Advisor Judith Enck & Assemblyman Clifford Crouch
Click on image for video:
Albany, NY, January 25, 2010 (see previous posts below): While approximately 500 people were inside the Convention Center (under The Egg), a group of demonstrators paused on the New York State Capitol Building’s steps — despite the rain and 40 mph gusts — demanding a “STATEWIDE BAN” on unconventional gas drilling.