Unatego Area Landowners Association

Otego - Unadilla - Butternuts Area Residents

                              SOURCES OF NATURAL GAS

With the growth of natural gas from shale, there is renewed interest in natural gas resources. The diagram shows the geologic nature of most major sources of natural gas in the U.S. in schematic form:
  • Gas-rich shale is the source rock for many natural gas resources, but, until now, has not been a focus for production. Horizontal drilling and hydraulic fracturing have made shale gas an economically viable alternative to conventional gas resources.
  • Conventional gas accumulations occur when gas migrates from gas rich shale into an overlying sandstone formation, and then becomes trapped by an overlying impermeable formation, called the seal. Associated gas accumulates in conjunction with oil, while non-associated gas does not accumulate with oil.
  • Tight sand gas accumulations occur in a variety of geologic settings where gas migrates from a source rock into a sandstone formation, but is limited in its ability to migrate upward due to reduced permeability in the sandstone.
  • Coalbed methane does not migrate from shale, but is generated during the transformation of organic material to coal.



                                         What is Natural Gas?

    Hydrocarbons’ are C-H compounds with C-H and C-C bonds.  Breaking of these bonds by oxidation (combustion) releases heat energy.

    Most common petroleum and gas hydrocarbons are alkanes, with the general formula - CnH2n+2

    Natural gas has the lowest carbon footprint of any fossil fuel – and is made up mostly of methane - CH4,  with some ethane – C2H6,  propane - C3H8 and butane - C4H10.         

    ‘Heavier’ alkanes - pentane, hexane, heptane, octane, etc - are liquid at surface temperatures and pressures.  Liquid petroleum is a mixture of C5 to C30 alkanes, plus aromatics (e.g. benzene) and alkenes.  

    Methane is also produced by a variety of biological processes at the earth’s surface:                                 - methane from surface biological systems is rarely accompanied by ethane, propane or butane;                  - methane from biological systems can be distinguished from natural gas (petroleum system) methane using carbon and hydrogen stable isotope ‘fingerprinting’.

    Petroleum system natural gas is usually associated with minor liquid hydrocarbons (wet gas with condensate). Dry gas systems are most common in sedimentary rocks that have been heated above 140ºC.  Brine (formation water) is produced from most natural gas wells and must be safely disposed of.

    The most common unit of measure for natural gas is the MCF

    1 MCF = 1000 cubic feet of gas at surface temperature and pressure. This is approximately equal to

    1,000,000 BTU

    1 Therm = 100,000 BTU --- 1 MCF is approximately 1000 Therm     





    In the leading theory, dead organic material accumulates on the bottom of oceans, riverbeds or swamps, mixing with mud and sand. Over time, more sediment piles on top and the resulting heat and pressure transforms the organic layer into a dark and waxy substance known as kerogen.

    Left alone, the kerogen molecules eventually crack, breaking up into shorter and lighter molecules composed almost solely of carbon and hydrogen atoms. Depending on how liquid or gaseous this mixture is, it will turn into either petroleum or natural gas.

    The idea that petroleum is formed from dead organic matter is known as the "biogenic theory" of petroleum formation and was first proposed by a Russian scientist almost 250 years ago.

    In the 1950's, however, a few Russian scientists began questioning this traditional view and proposed instead that petroleum could form naturally deep inside the Earth. 



                                   U.S. SHALE GAS PLAYS

    - - - - - - - - - - - -

       Natural gas production from hydrocarbon rich shale formations, known as “shale gas,” is one of the most rapidly expanding trends in onshore domestic oil and gas exploration and production today.  In some areas, this has included bringing drilling and production to regions of the country that have  seen little or no activity in the past. New oil and gas developments bring change to the environmental and socio-economic landscape, particularly in those areas where gas development is a new activity. With these changes have come questions about the nature of shale gas development, the potential environmental impacts, and the ability of the current regulatory structure to deal with this development. Regulators, policy makers, and the public need an objective source ofinformation on which to base answers to these questions and decisions about how to manage the challenges that may accompany shale gas development.

       The United States has abundant natural gas resources. The Energy Information Administration estimates that the U.S. has more than 1,744 trillion cubic feet (tcf) of technically recoverable naturalgas, including 211 tcf of proved reserves (the discovered, economically recoverable fraction of theoriginal gas-in-place). Technically recoverable unconventional gas (shale gas, tight sands, andcoalbed methane) accounts for 60% of the onshore recoverable resource. At the U.S. production rates for 2007, about 19.3 tcf, the current recoverable resource estimate provides enough natural gas to supply the U.S. for the next 90 years. Separate estimates of the shale gas resource extend thissupply to 116 years.

       The lower 48 states have a wide distribution of highly organic shales containing vast resources of natural gas. Already, the fledgling Barnett Shale play in Texas produces 6% of all natural gas produced in the lower 48 States. Three factors have come together in recent years to make shale gas production economically viable: 1) advances in horizontal drilling, 2) advances in hydraulicfracturing, and, perhaps most importantly, 3) rapid increases in natural gas prices in the last several years as a result of significant supply and demand pressures. Analysts have estimated thatby 2011 most new reserves growth (50% to 60%, or approximately 3 bcf/day) will come from unconventional shale gas reservoirs. The total recoverable gas resources in four new shale gasplays (the Haynesville, Fayetteville, Marcellus, and Woodford) may be over 550 tcf. Total annual production volumes of 3 to 4 tcf may be sustainable for decades. This potential for production inthe known onshore shale basins, coupled with other unconventional gas plays, is predicted to contribute significantly to the U.S.’s domestic energy outlook.

    READ MORE:  http://www.fossil.energy.gov/programs/oilgas/publications/naturalgas_general/Shale_Gas_Primer_2009.pdf


                                  U.S. Natural Gas Facts

                           • 22% of energy consumed in US (2008)

                           •  Produces ~ 40% of our electricity

                           • 84% of gas consumed in US produced in US, 97% produced in NA

                           • 50% of production was from wells drilled in past 3.5 years (2008)

                           • Unconventional gas 46% of total US production (2007)

                           • Marcellus Shale may contain 516 tcf of natural gas (23 tcf of gas consumed in 2008)



                             U.S. Short-Term Energy Outlook

    U.S. Natural Gas Consumption.  EIA expects total natural gas consumption to increase by 0.7 percent to 62.9 billion cubic feet per day (Bcf/d) in 2010 and decline by 0.4 percent in 2011 (Total U.S. Natural Gas Consumption Growth Chart).  Cold weather drives this year's natural gas consumption increases.  Total natural-gas-weighted heating degree-days during the first 2 months of this year were 5.5 percent above the 30-year normal level and the highest for the period since 2004.

    The combination of frigid temperatures and electric space heating in the Southeast contributed not only to increases in residential and commercial sector natural gas consumption but also to very strong natural gas consumption in the electric power sector.  Even with the assumption of near-normal weather in March, EIA expects first- quarter natural gas use in the electric power sector to increase by about 3 percent above the same period last year and about 17 percent above the previous 5-year average.  This increase in first quarter 2010 electric power sector consumption has all but eliminated the projected 1.3-percent year-over-year decline in natural gas consumption for this sector in last month's Outlook.

    The 2011 outlook for a small decline in total natural gas consumption reflects the projected return to near-normal weather, which is expected to reduce consumption in the residential, commercial, and electric power sectors.  Continued economic recovery contributes to a projected 2.1-percent increase in natural gas consumption in the industrial sector.

    U.S. Natural Gas Production and Imports.  EIA expects total marketed natural gas production to decline by 2.7 percent to 58.7 Bcf/d in 2010 and increase by 1.1 percent in 2011.  The number of working natural gas rigs has been increasing this year in response to higher prices in both the spot and forward markets.  According to Smith International, natural gas rigs have increased by more than 17 percent, or by nearly 140, since the start of this year.  There are currently almost 570 working horizontal rigs, a new record.  EIA still anticipates a decline in 2010 production because of the lag time arising from low drilling rates last year and steep decline rates associated with newly- drilled wells.  However, continued recovery of drilling rig activity, increasing drilling efficiency, and the potential for higher production rates from shale gas wells could lead to higher-than-expected production this year and next.

    EIA expects U.S. net imports to be slightly higher in 2010 as a projected decline in pipeline imports is offset by lower exports and higher imports of liquefied natural gas (LNG).  While cold weather across the northern hemisphere has helped absorb some of the new LNG supply that has recently come on-stream, U.S. LNG imports are forecast to increase by nearly 0.8 Bcf/d over last year in the first quarter 2010.  For 2010 as a whole, U.S. LNG imports are forecast to increase by about 45 percent (or 0.56 Bcf/d).  As global LNG demand and import capacity expand next year, EIA expects U.S. LNG imports to show little year-over-year growth in 2011. 

    U.S. Natural Gas Inventories.  On February 26, 2010, working natural gas in storage was ­­­­­1,737 Bcf (U.S. Working Natural Gas in Storage Chart), 21 Bcf above the previous 5-year average (2005–2009) and 71 Bcf below the level during the corresponding week last year.  Persistent cold weather so far this year has taken a toll on inventories.  The estimated total inventory withdrawal in January and February is 1,406 Bcf.  The 5-year average withdrawal for these 2 months is 1,159 Bcf.  EIA now expects working natural gas inventories to finish the first quarter of 2010 at around 1,549 Bcf, or about 3.5 percent above the previous 5-year average.  In addition, resilient domestic production and higher U.S. LNG imports contribute to a projected end-of-October 2010 inventory that remains above the previous 5-year average.

    U.S. Natural Gas Prices.  The Henry Hub spot price averaged $5.32 per MMBtu in February, $0.51 per MMBtu lower than the average spot price in January and $0.14 per MMBtu lower than the forecast for February in last month’s Outlook (Henry Hub Natural Gas Price Chart ).  Historically, colder-than-normal weather and correspondingly high demand has contributed to large storage withdrawals and elevated prices during the winter.  For example, similar natural-gas-weighted heating degree-days and working natural gas storage withdrawals were recorded in January and February of this year and in 2003.   While the cold weather in 2003 contributed to a 63-percent increase in the monthly average spot price from December 2002 to February 2003, the monthly average spot price in February 2010 was virtually unchanged from the average price in December 2009.

    Much of the subdued price action this winter is attributable to the level of, as opposed to the change in, working inventories.  By the end of February 2003, working stocks stood at 851 Bcf compared with an estimated 1,729 Bcf this February.  Prices may strengthen slightly in the coming months as demand to rebuild natural gas in storage from risk-averse local distribution companies begins.  However, the potential for higher domestic production, increasing LNG supply, and limited consumption growth all reduce the possibility of sustained high prices as inventories are replenished over the next several months.  The Henry Hub spot price forecast averages $5.17 per MMBtu in 2010 and $5.65 per MMBtu in 2011.

    Volatility in the April and May 2010 futures and options markets trended lower over the last month.  For the 5-day period ended March 4, May futures averaged $4.77 per MMBtu, while the lower and upper limits of the 95-percent confidence interval calculated based on the implied volatility calculated from near-the-money options were $3.57 and $6.39 per MMBtu, respectively.  A year earlier, natural gas delivered to the Henry Hub in May 2009 was trading at $4.30 per MMBtu, with lower and upper limit for the 95-percent confidence interval calculated based on implied volatility of $2.80 and $6.60 per MMBtu, respectively.



                                    Evolution of a Shale Play

    Typically, development of a shale play has three distinct phases, from the discovery stage, through drilling and reservoir evaluation, to production.  The timeframe for this process can take several years.


    STAGE 1: Discovery & Planning - the stage during which all of the initial reservoir knowledge is gathered. Extensive analysis, including coring and seismic analysis, establishes the economic viability of the play during this phase and helps determine the techniques to be used to optimize the development. The effectiveness of planning accomplished in the discovery stage depends largely upon knowledge of the reservoir.


    STAGE 2: Drilling & Reservoir Evaluation - the operational phase with the focus on applying the planned techniques most efficiently to maximize reservoir contact and lower cost per unit. It is in this stage of development that the issues concerning infrastructure and practical efficiencies are addressed. And this is the present state of several currently hot shale plays.


    STAGE 3: Production Phase - focuses on optimizing reservoir drainage, which in U.S. shale gas plays typically requires stimulation, usually by hydraulic fracturing. The efficiency of these completion operations can have significant impact during the production phase; with proper fracturing and placement of proppants, some shale wells have been producing for decades.



    Along with its geographic abundance and enormous production potential, gas shale presents a number of challenges – starting with the lack of an agreed-upon industry standard for what exactly comprises shale.

    Shale makes up more than half the earth’s sedimentary rock but includes a wide variety of vastly differing formations. Within the industry, the generally homogenous, fine-grained rock can be defined in terms of its geology, geochemistry, geo-mechanics and production mechanism – all of which differ from a conventional reservoir, and can differ from shale to shale, and even within the same shale.

    Nevertheless, all shale is characterized by low permeability, and in all gas-producing shales, organic carbon in the shale is the source. Many have substantial gas stored in the free state, with additional gas storage capacity in intergranular porosity and/or fractures. Other gas shales grade into tight sands, and many tight sands have gas stored in the adsorbed state.

    Since these various conditions determine the production mechanism of the various shales, knowledge of local reservoir characteristics is of vital importance in keeping development costs under control and optimizing production over the life of the reservoir.

    Also, since every shale play is different (due to the unique nature of shale), every basin, play, well and pay zone may require a unique treatment.

    Currently the newest play is in the 54,000-square mile Appalachian Basin, but the Marcellus formation is not a new discovery. Prior to 2000, this low-density, vertically fractured shale formation was explored with a number of successful vertical gas wells, many of which have produced – slowly but surely – for decades. However, not until 2000 with the introduction of techniques pioneered in the Barnett shale, did Marcellus wells begin to yield significantly improved production rates.

    The Marcellus shale ranges in depth from 4,000 to 8,500 feet, with gas currently produced from hydraulically fractured horizontal wellbores. Horizontal lateral lengths exceed 2,000 feet, and, typically, completions involve multistage fracturing with more than three stages per well.


    For an in-depth look at the technical side of gas drilling, please go to: http://www.halliburton.com/public/shale/pubsdata/H06377.pdf 


              Drilling Non-Permeable Shales (Barnett, Marcellus)

     When a well is drilled, steel casing and surrounding layers of concrete are installed to isolate the well from drinking water aquifers through which the well penetrates. The depths at which this “surface casing” must extend are regulated.  In Barnett Shale operations in Texas, the surface casings are typically set to a depth of 1,200 1,300 feet, more than 400 feet below the Trinity Aquifer. After it is determined that the well can produce natural gas, additional strings of casing and tubing are set through the aquifers to provide even greater separation between the gas stream and the fresh water tables. States also require documentation of drinking water aquifer intervals, the design and installation of surface casing relative to those intervals, and the reporting of characteristics of the wellbore along with completion and production data to protect water resources.

    Horizontal drilling cross sectional view.

           To review the 2000 EPA Report on the chemical make-up of "produced water" (water recovered from the drilling process), click here: EPA Gas Drilling Chemicals.pdf


    For a step-by-step view of the different stages of hydrofracking a horizontal shale well, take a few minutes to view this video from the oil industry: http://www.northernoil.com/drilling.php 


    In order to release natural gas from low permeability shale, such as the Barnett in Texas or Marcellus in NY & PA, small cracks or fractures must be created in the rock — much like a windshield might be spidered or fractured if struck by a stone — to allow the gas to flow. “Fracing” is the process in which a mixture of sand, water and lubricants is pumped into the underground formation under high pressure to break open tiny fractures. These fractures are designed to release natural gas trapped inside the shale.

    What is Hydroftacking

    During fracing, water and sand are pumped under high pressure into the rock formation, creating tiny cracks in the shale and allowing gas to escape.

                                           Fracking Issues

    Hydraulic fracturing has become a controversial issue in the last few years because the technique requires huge amounts of water laced with chemicals that may be toxic, which are forced under high pressure into the target rock formation.  Concerns over contamination of the aquifer, water requirements, and waste water disposal are the main criticisms of this technique of extracting gas from shale.

    A newer approach to fracking, which has already been successfully employed on the Marcellus Shale, involves the use of propane.  The proprietary new fracturing system uses liquefied petroleum gas (LPG), consisting mostly of propane, rather than water- or oil-based fracing fluids. Using propane as the fracturing fluid and pumping it into a reservoir does not result in the types of formation damage other fluids often cause.  Click here to READ MORE about uising propane for fracking: http://www.gasfrac.com/fracforward.pdf

    Another issue that has raised concerns recently involves the way a gas well is sealed after being drilled.  When a new gas well is drilled, it must be sealed to prevent hydrocarbons from escaping back up the well to the environment by forcing cement grouting down between the casing and walls of the bore hole.   It is presumed that this will prevent the escape of hydrocarbons or other noxious compounds into the aquifer or back to the surface.  Click here to READ MORE about the process of sealing off a gas well: http://www.slb.com/~/media/Files/resources/oilfield_review/ors03/aut03/p62_76.ashx


    Pipelines are necessary to get the natural gas from the wellhead to market. While the diameter of the pipeline may vary depending on its function, they are all similar to normal utility pipelines that currently deliver gas to your home or office, and thus pose no elevated safety issues. New pipelines may be installed through traditional open trenching, boring underneath the ground, or a combination of the two.

    Pipeline Connection


    For information on the NY State Department of Agriculture and Markets' guidelines for pipeline construction across farming land, please click here: http://www.agmkt.state.ny.us/AP/agservices/WEBAPConstrGuides.pdf 

    For a more complete overview of pipeline technology & proceedures, please click here: http://www.ipd.anl.gov/anlpubs/2008/02/61034.pdf

    For information for landowners with forest lands, please click here: http://rnrext.cas.psu.edu/PDFs/FL%20Winter08.pdf